Use these links to rapidly review the document TABLE OF CONTENTS ~~INDEX~~ TOTABLE ~~FINANCIAL~~OF ~~STATEMENTS~~CONTENTS 2

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Form 10-K

ý		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended March 31, 2015
For the fiscal year ended March 31, 2016
OR
o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to

Commission file number: 001-34733

Niska Gas Storage Partners LLC
(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction or organization)		27-1855740 (I.R.S. Employer Identification No.)
170 Radnor Chester Road, Suite 150 Radnor, PA (Address of principal executive offices)		19087 (Zip Code)

(484) 367-7432
(Registrant's telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Exchange on which Registered

Common Units Representing Limited Liability Company Interests		New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act:

		Title of Class

		None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer ý		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No ý

As of September 30, ~~2014~~2015, the aggregate market value of the registrant's common units held by non-affiliates was $~~218~~54,~~401~~425,~~036~~619 based on a unit price of $123.4811. This calculation of such market value should not be construed as an admission or conclusion by the registrant that any person is in fact an affiliate of the registrant.

As of June 129, ~~2015~~2016, the registrant had 37,988,724 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

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TABLE OF CONTENTS


PART I	~~PART I~~
Item 1.	Business	1
Item 1A.	Risk Factors	1516
Item 1B.	Unresolved Staff Comments	3436
Item 2.	Properties	3436
Item 3.	Legal Proceedings	3436
Item 4.	Mine Safety Disclosures	3436
PART II	~~PART II~~
Item 5.	Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	3437
Item 6.	Selected Financial Data	3740
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	3941
Item 7A.	Quantitative and Qualitative Disclosures About Market Risks	6967
Item 8.	Financial Statements and Supplementary Data	7271
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	7271
Item 9A.	Controls and Procedures	7271
Item 9B.	Other Information	7271
PART III	~~PART III~~
Item 10.	Directors, Executive Officers and Corporate Governance	7372
Item 11.	Executive Compensation	8180
Item 12.	Security Ownership of Certain Beneficial Owners and Management	~~107~~104
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~109~~106
Item 14.	Principal Accounting Fees and Services	~~110~~108
PART IV	~~PART IV~~
Item 15.	Exhibits, Financial Statement Schedules	~~111~~108
FINANCIAL STATEMENTS	~~FINANCIAL STATEMENTS~~
Niska Gas Storage Partners LLC Index to Financial Statements		F-1

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GLOSSARY OF KEY TERMS

As used generally in the energy industry and in this report, the following terms have the meanings indicated below.

Basin A geological province on land or offshore where hydrocarbons are generated and trapped. Bcf One billion cubic feet of natural gas. A standard volume measure of natural gas products. British Thermal Unit ("BTU") British thermal unit, a traditional unit of heat measurement equal to the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit at one atmosphere pressure. Cap-and-Trade A market-based approach used to control pollution by providing economic incentives for achieving reductions in the emissions of pollutants. A central authority (usually a governmental body) sets a limit or cap on the amount of a pollutant that may be emitted. The limit or cap is allocated or sold to firms in the form of emissions permits which represent the right to emit or discharge a specific volume of the specified pollutant. CPUC California Public Utilities Commission. A regulatory agency that monitors privately owned public utilities in the state of California, including natural gas companies. Cushion A quantity of hydrocarbons held within the confines of the natural gas storage facility used for pressure support and to maintain a minimum field pressure. May consist of injected cushion gas, native cushion gas or oil. Cycle A complete withdrawal and injection of working gas. Dekatherm ("Dth") Equivalent to one million Btus or one MMBtu. One therm equals one hundred thousand Btus. Effective Working Gas Capacity The maximum volume of natural gas that can be cost-effectively injected into a storage reservoir and extracted during the normal operation of the storage facility. Effective working gas capacity excludes cushion. GAAP Generally accepted accounting principles in the United States of America. Gas storage capacity See Effective Working Gas Capacity. Holdco Niska Sponsor Holdings Coöperatief U.A. Hub Geographic location of a natural gas storage facility and multiple pipeline interconnections. Independent Storage Natural gas storage facilities owned and operated independently from the pipeline and distribution facilities to which they are interconnected. Inventory An amount of Working Gas held within the natural gas storage facility. It may relate to third-party customer volumes or to owner/operator volumes of working gas. Injection Rate The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.

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Inventory		An amount of Working Gas held within the natural gas storage facility. It may relate to third-party customer volumes or to owner/operator volumes of working gas.
Injection Rate		The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
Manager		Niska Gas Storage Management LLC. Also referred to as "our manager."
Mcf		Thousand cubic feet of natural gas.
Mega Dekatherm ("MDth")		Equivalent to one million Dekatherms.
MMbtu		Million British thermal units. A standard measure of natural gas for pricing purposes, particularly in the U.S.
MMcf		Million cubic feet of natural gas.
Natural Gas		Several hydrocarbons that occur naturally underground in a gaseous state. Natural gas is normally mostly methane, but other components also include ethane, propane, and butane.
Natural Gas Act		Federal law enacted in 1938 that established the Federal Energy Regulatory Commission's authority to regulate interstate pipelines.
NGPL		Natural Gas Pipeline Company of America.
Niska Holdings		Niska Holdings L.P.
Optimization		The purchase, storage and sale of natural gas by the storage owner for its own account in order to utilize storage capacity that is (1) not contracted to customers, (2) contracted to customers but underutilized by them or (3) available only on a short term basis.
Reservoir		A naturally occurring underground formation that originally contained crude oil or natural gas, or both.
Withdrawal Capacity		The amount of gas that is or can be removed from a natural gas storage facility. Usually stated in MMcf per day, Bcf per day or Mcf per day. Typically stated as maximum or peak daily withdrawal capacity.
Withdrawal Rate		The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
Working Gas		Natural gas in a storage facility in excess of Cushion.
Working Gas Capacity		See Effective Working Gas Capacity.

iii

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute "forward-looking statements." Forward-looking statements are based on management's current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties, some of which are beyond our control. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this document. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Known material factors that could cause our actual results to differ from those forward-looking statements are those described in Part I, Item 1A, "Risk Factors."

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I

Item 1. Business.

Overview

We are a Delaware limited liability company ~~whose~~who ~~predecessor~~ was formed in 2006 to own and operate natural gas storage assets. We own or contract for approximately ~~244~~243.9 billion cubic feet, or Bcf, of total natural gas storage capacity. Our assets are located in key North American natural gas producing and consuming regions and are connected at strategic points on the natural gas transmission network, providing access to multiple end-use markets. Our locations provide us and our customers with substantial liquidity, ~~meaning~~ meaning access to multiple counterparties for transactions to buy and sell natural gas. Since our inception in 2006, we have added 106.3 Bcf of new storage capacity through low cost organic expansions, an increase of approximately 74%.

Because the supply of natural gas remains relatively stable over the course of a year compared to the demand for natural gas, which fluctuates seasonally, natural gas storage facilities are needed to reallocate excess natural gas supply from periods of low demand to periods of high demand. We capitalize on the imbalance between supply of and demand for natural gas by providing our customers and ourselves with the ability to store natural gas for resale or use in a higher value period. Our natural gas storage facilities allow us to offer our customers "multi-cycle" gas contracts, which permit them to inject and withdraw their natural gas multiple times in one year, providing more flexibility to capture market opportunities. Since our inception, our storage contracts have provided cyclability rates ranging from 1.0 to 6.0 times per year.

Our common units are listed on the New York Stock Exchange, or the NYSE, under the symbol "NKA." You may find more information about us on our website at www.niskapartners.com. Our headquarters is located in Radnor, Pennsylvania, and our operations center is located in Calgary, Alberta, Canada.

On June 14, 2015, Niska Gas Storage Partners LLC ("Niska Partners" or the "Company"), the Manager, Holdco and certain of their affiliates entered into an Agreement and Plan of Merger and Membership Interest Transfer Agreement (the "Merger Agreement") with certain affiliates of Brookfield Infrastructure Partners L.P. and its institutional partners ("Brookfield"). Under the terms of the Merger Agreement, Brookfield will acquire all of the Company's outstanding common units for $4.225 per common unit in cash and will acquire all of the ownership interests in the Manager and all of the Incentive Distribution Rights ("IDRs") in the Company (the "Transaction") prior to June 14, 2017. A period provided for in the Merger Agreement for unsolicited consideration of alternative acquisition proposals expired on July 29, 2015.

The Merger Agreement, which includes a commitment by the Company not to make cash distributions until the earlier of the date of closing or termination of the Transaction, was approved by the Company's Board of Directors ("the Company Board") and the Conflicts Committee of its Board of Directors (the "Conflicts Committee"). Holdco, as the holder of approximately 53.93% of the issued and outstanding Common Units at the time of the Merger Agreement, delivered a written consent approving the Transaction. No additional unitholder action is required to approve the Transaction.

Recent Developments

On February 29, 2016, the Company completed an amendment and extension of its Revolving Credit Facilities (defined below), which included the approval of a change of control associated with the Transaction. The amended and restated Revolving Credit Facilities extends the term of the original agreement from June 29, 2016 to September 30, 2016 and allows for an additional term extension to December 31, 2016 provided that the Transaction has closed. The maximum capacity of the amended and restated Revolving Credit Facilities was reduced to $320.0 million effective February 29, 2016. The

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other substantive terms and conditions of the facilities were unchanged, other than with regards to the pricing and certain security interests.

The closing of the Transaction is dependent on the satisfaction of certain conditions related to regulatory requirements, including the approval of the CPUC. On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield. The decision is effective immediately. The Company expects that the merger transaction will proceed in accordance with the terms of the Merger Agreement and that it will close on or prior to July 31, 2016.

Organizational Structure

The following diagram depicts our simplified organizational and ownership structure as at March 31, ~~2015~~2016:

Refer to the Schedule 14C Information Statement filed on January 4, 2016 for additional details pertaining to the Transaction.

Our Relationship with Holdco

Niska Sponsor Holdings Coöperatief U.A. ("Holdco") owns our manager, approximately 53.93% of our outstanding common units and all of our IDRs.

Over 95% of the equity in Holdco is owned by the Carlyle/Riverstone Funds and affiliated entities with the balance owned by our current and former officers and employees. The Carlyle/Riverstone Funds are affiliated with Riverstone Holdings LLC, or Riverstone. Riverstone conducts buyout and growth capital investments in the midstream, exploration and production, oilfield services, power and renewable sectors of the energy industry. Riverstone's management has substantial experience in identifying, evaluating, negotiating and financing acquisitions and investments.

Management

Niska Gas Storage Management LLC, or "our manager," has a 1.80% managing member interest in us. Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board of directors, all of the members of which are appointed by our manager. References to our board refer to the board of directors of Niska Gas Storage Partners LLC as long as the delegation is in effect (or to the board of directors of our manager if such delegation is not in effect). Our board directs the management of our business and presently

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consists of eight members. Our manager appoints all members to our board, and three of our directors are independent as defined under the independence standards established by the NYSE.

Our Operations

Fee-based revenue

We store natural gas for a broad range of customers, including financial institutions, marketers, pipelines, power generators, utilities and producers of natural gas. Fee-based revenue consists of longer term contracts for storage fees that are generated when we ~~lease~~provide storage ~~capacity~~services on a monthly basis and shorter term ~~fees~~ fees associated with park and loan activities.

Long-Term Firm Storage Contracts

We provide multi-year, multi-cycle storage services to our customers under long-term firm, or LTF contracts. Under our LTF contracts our customers are obligated to pay us monthly reservation fees in exchange for the right to inject, store and withdraw volumes of natural gas on days and for periods selected by them at injection or withdrawal rates up to maximums specified in the contract. The reservation fees are fixed charges owed to us regardless of the actual amount of storage capacity utilized by customers. When customers utilize the capacity that is reserved under these contracts we also collect variable fees based upon the actual volumes of natural gas injected or withdrawn. These ~~variable~~ fees are designed to allow us to recover our variable operating costs and make up a small percentage of the total fees we receive under our LTF contracts.

Under an LTF ~~contracts~~contract, the customer has the right, but not the obligation, to store natural gas in the facility during the term of the contract, up to a specified volume or "inventory capacity." In addition to the total amount of inventory capacity, LTF contracts specify a customer's daily withdrawal and injection rights which typically increase or decrease as the customer's inventory changes. The maximum injection rate that a customer is typically entitled to is highest when that customer's inventory capacity is empty, reducing as that customer's inventory increases. When a customer's contracted inventory capacity is full, it has no further injection rights. A customer's maximum withdrawal rate is typically highest when its inventory is full, declining incrementally to zero when the customer's inventory is empty. LTF contracts provide the customer with the flexibility to use all, a portion, or none of its capacity and the freedom to inject or withdraw natural gas up to its daily injection or withdrawal rate, but obligate the customer to remove any injected natural gas by the end of the contract term.

Reservation fees comprise over 90% of the revenue received from LTF storage customers, and represent a steady and predictable baseline cash flow stream.

Short-Term Firm Storage Contracts

We also provide short-term storage services for customers under short-term firm, or STF contracts. STF contracts typically have terms of less than one year; however can extend up to two years. Under an STF contract, a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and a fixed fee to withdraw on a specified future date or dates. The fee stipulated in the contract for each performance obligation (injection and withdrawal) is recognized when the service occurs. An STF contract differs from an LTF contract in that the customer is obligated to inject and withdraw specified quantities of natural gas on specified dates rather than entitled to utilize injection and withdrawal capacity at its option.

Proprietary Optimization

We purchase, store and sell natural gas for our own account in order to utilize, or optimize, storage capacity and injection and withdrawal capacity that is: (1) not contracted to customers;

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(2) contracted to customers, but underutilized by them; or (3) available only on a short-term basis. We have a stringent risk policy that limits, among other things, our exposure to commodity price fluctuations by requiring us to promptly enter into a forward sale contract or other hedging transaction whenever we enter into a proprietary purchase contract. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that a margin is effectively locked in promptly after we enter into the purchase. As a result, there are no speculative positions beyond the minimal operational tolerances specified in our risk policy. We purchase natural gas for our own account, inject it and subsequently withdraw and sell the gas. The flexibility arising from purchasing and selling natural gas for our own account allows us to generate incremental value through our proprietary optimization strategy by capturing spot and inter-period opportunities. Unlike fee-based storage transactions, proprietary optimization requires us to fund the carrying cost of the inventory with our own working capital.

Risk management techniques, adapted to the unique aspects of natural gas storage, enable us to match the capacity at our facilities with the portfolio of long-term and short-term contracts and proprietary optimization transactions at those facilities in order to utilize the maximum amount of capacity available. We utilize New York Mercantile Exchange Inc., or NYMEX, and Intercontinental Exchange, Inc., or ICE, which are regulated exchanges for the purchase and sale of energy products, to hedge our commodity risk with respect to the pricing of natural gas. This helps us reduce potential credit, delivery and supply risks. Generally these are financial swaps and are settled without the requirement for physical delivery. In the case of NYMEX futures, we can enter an EFS (exchange for swaps) to avoid the requirement for delivery.

Customers and Counterparties

Our gas storage customers include a broad mix of natural gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities. Approximately 7267% of the counterparties under our active natural gas storage contracts and proprietary storage optimization transactions either (1) have an investment grade credit rating, (2) provide us with another form of financial assurance, such as a letter of credit or other collateral, or (3) are governmental entities. Our fully secured and investment grade counterparties account for approximately 9188% of our credit exposures as of March 31, ~~2015~~2016.

During certain reporting periods a large portion of our credit exposure can be attributed to one or two counterparties. These exposures reflect the full commodity value of natural gas sales under our optimization strategy.

We analyze the financial condition of our counterparties prior to entering into an agreement. Our exposure to the volume of business transacted with a natural gas clearing and settlement facility is mitigated by the facility's requirement to post margin deposits to reduce the risk of default. In the event of any default, the exchange would absorb losses by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults.

Our Assets

Our owned and operated natural gas storage facilities consist of AECO Hub™ (comprised of two facilities in Alberta, Canada), our Wild Goose storage facility in California and our Salt Plains storage facility in Oklahoma. Our natural gas storage assets are modern, well-maintained, automated facilities with low maintenance costs, long useful lives and comparatively high injection and withdrawal, or cycling, capabilities. The size and flexibility of our facilities, together with the application of advanced skills in reservoir engineering, drilling, geology and geophysics, enable us to support individual high-cycle contracts in excess of the average physical cycling capabilities of our facilities. In addition to

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the facilities we own and operate, we also ~~contracted~~contract for 81.59 Bcf of natural gas storage capacity from Natural Gas Pipeline Company of America LLC, or NGPL, on its pipeline system in the mid-continent (Texas and Oklahoma) at cost-of-service based rates. The following table highlights certain important design information about our assets:

	AECO Hub™
									NGPL
	Suffield		Countess		Wild Goose		Salt Plains
March 31, 2015: Name									Midcon/ Texok
	Alberta		Alberta		California		Oklahoma				Total
Location
Gas Storage Capacity (Bcf)		83.5		70.5		75		13		8.5		250.5
Peak Withdrawal (MMcf per day)		1,800		1,250		950		150		114		4,264
Peak Injection (MMcf per day)		1,600		1,150		525		115		57		3,447
Reservoirs		5		2		3		1		N/A		11
Storage Wells		60		29		17		30		N/A		136
Compression (horsepower)		36,000		34,500		27,900		10,000		N/A		108,400
In Service Date		1988		2003		1999		1995		N/A		1988 - 2003

March 31, 2016:

On April 1, 2015, our contract for 5.6 Bcf of the 8.5 Bcf leased on NGPL capacity expired, thereby reducing our total capacity to 244.9 Bcf.

	AECO Hub™

	AECO Hub™								NGPL
	Suffield		Countess		Wild Goose		Salt Plains		NGPL
	Suffield		Countess		Wild Goose		Salt Plains		Midcon/ Texok
Name Location	Alberta		Alberta		California		Oklahoma		Midcon/ Texok		Total
Gas Storage Capacity (Bcf)		83.5		70.5		75		13		2.9		244.9
Peak Withdrawal (MMcf per day)		1,800		1,250		950		150		40		4,190
Peak Injection (MMcf per day)		1,600		1,150		525		115		20		3,410
Reservoirs		5		2		3		1		N/A		11
Storage Wells		60		29		17		30		N/A		136
Compression (horsepower)		36,000		34,500		27,900		10,000		N/A		108,400
In Service Date		1988		2003		1999		1995		N/A		1988 - 2003

On May 1, 2016, 1.0 Bcf of the 2.9 Bcf leased on NGPL capacity expired, thereby reducing our total capacity to 243.9 Bcf.

AECO Hub™

Overview

AECO Hub™, our largest operation, is comprised of two facilities in Alberta, Suffield and Countess, which are 75 miles apart but operate as one hub. Due to its high injection and withdrawal capacity (2.8 Bcf per day and 3.1 Bcf per day, respectively), AECO Hub™ supports high cycling customer contracts. AECO Hub™ is the largest natural gas storage provider in western Canada and the largest independent storage hub in North America, based on our analysis of working gas capacity owned by other storage owners, adjusted according to each such owner's percentage ownership of its respective storage facilities. Its location on TransCanada Pipeline's Alberta System with direct access to abundant western Canadian natural gas supply and pipeline connections to most major U.S. and Canadian natural gas markets provides us and our customers with significant flexibility and liquidity.

AECO Hub™ is located in the Western Canadian Sedimentary Basin, or the WCSB, which is the major hydrocarbon basin in Canada and one of the most prolific natural gas producing regions in North America. The WCSB accounts for a majority of annual Canadian natural gas production and a significant amount of annual North American natural gas production according to the Canadian National Energy Board, or NEB. Natural gas production grew in the WCSB in fiscal ~~2015~~2016 compared to ~~production in~~ fiscal ~~2014~~2015. Further, we expect that Canadian natural gas production will grow in future years ~~in response~~ to support aexpected ~~growing demand for~~ LNG exports to serve Asian markets. New production to support these projects will be provided by large new shale and tight gas plays in northeast British Columbia and western Alberta, along with a large remaining conventional natural gas resource base.

AECO Hub™ is connected to the extensive Alberta System. Most of the natural gas produced in Alberta flows into the Alberta System, which transports that natural gas from the well or gas plant to industrial consumers and gas utilities in Alberta and to export pipelines at the Alberta border.

AECO Hub™ has been a central part of the Alberta System since the early 1990s, when the Suffield facility began providing title transfers as a hub service before that service was available on the pipeline. Many transactions were being transacted by storage customers and others at the Suffield facility and a new price index, known as the "AECO Hub™ Price Index," was developed to facilitate ~~price discovery. AECO Hub™ is the most commonly referenced pricing point for Canadian natural gas, and the price of natural gas in Alberta is often referred to as the "AECO Price."~~

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price discovery. AECO Hub™ is the most commonly referenced pricing point for Canadian natural gas, and the price of natural gas in Alberta is often referred to as the "AECO Price."

AECO Hub™ Facilities

AECO Suffield and AECO Countess, the two facilities that make up the AECO Hub™, are geographically separated, but the toll design of the Alberta System means that they are both commercially located at the same point. This enables us to operate the two facilities as one integrated commercial operation without customers incurring incremental transportation costs. Customers nominate injections or withdrawals at Suffield's interconnect with the Alberta System, and AECO Hub™ allocates the nominations between its Suffield and Countess facilities based on its reservoir management strategy.

Our rights to use the reservoirs at Suffield and Countess are held pursuant to a series of natural gas storage agreements, trust arrangements and similar instruments entered into with the holders of subsurface mineral interests of the land where the reservoirs are situated. Rights to access, occupy and use the lands for facilities including the well sites and pipelines are derived from access agreements, right-of-ways, easements, leases and other similar land use agreements with the surface owners of such land.

Suffield Storage Facility. AECO Suffield is located in southeastern Alberta. It is near the Alberta System's "eastern gate," the largest natural gas delivery point in Canada, where gas is delivered into TransCanada's mainline pipeline system (transporting natural gas to eastern Canada and the northeastern U.S.) and the Foothills/Northern Border pipeline system (transporting natural gas to Chicago and the Midwestern U.S.). AECO Suffield consists of 60 storage wells and five storage reservoirs with aggregate effective working capacity of approximately 83.5 Bcf. The storage reservoirs are connected to a central processing and compression facility by a system of five pipelines. Compression is provided by natural gas powered engines that have a total of more than 36,000 horsepower.

All of the processing and compression facilities and substantially all of the well sites for the storage reservoirs are located on the Canadian Forces Base, Suffield military training range, or CFB Suffield. CFB Suffield is open prairie land, which provides relatively low costs for seismic surveys, drilling and pipelining. While the military restricts access to the well sites on a limited basis from time-to-time (i.e., during military exercises), AECO Suffield has not experienced any operational issues due to the location since its inception in 1988.

Countess Storage Facility. AECO Countess is located in south central Alberta, approximately 60 miles east of Calgary. Countess is connected to a large diameter pipe of the Alberta System. This modern natural gas storage project consists of 29 storage wells and two high performance gas storage reservoirs that are connected to a central processing and compression facility. The two storage reservoirs each have their own gathering pipeline system. Compression is electrically powered and totals approximately 34,500 horsepower. The two reservoirs have total effective working capacity of approximately 70.5 Bcf.

Customers

AECO Hub™'s customers consist of a mix of natural gas market participants, including financial institutions, producers, marketers, power generators, and pipelines, resulting in a portfolio of customers with diverse usage patterns and varying contract expiration dates. This allows more opportunity for AECO Hub™ to optimize underutilized capacity.

Most of AECO's LTF contracts have capacity of 1.0 Bcf or greater. LTF contract terms have been selected so that a manageable amount of contracts expire each year, avoiding exposure to a large ~~contract turnover volume. The weighted average contract life of our LTF storage contracts at AECO Hub™ on March 31, 2015 was 3.6 years. Excluding our largest volumetric customer, TransCanada Gas~~

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~~Storage~~contract turnover volume. The weighted average contract life of our LTF storage contracts at AECO Hub™ on March 31, 2016 was 2.9 years. Excluding our largest volumetric customer, TransCanada Gas Storage Partnership, or TransCanada, the weighted average contract life is 2.73 years with ana weighted average volume of 32.17 Bcf.

Regulatory

AECO Hub™ is subject to provincial regulatory jurisdiction. Operations are subject to the regulation of the Alberta Energy Regulator, or the AER, which must also approve proposed expansions of storage capacity. AECO Hub™ is not subject to active market regulation. While the Alberta Utilities Commission, or the AUC, does have overriding jurisdiction to set natural gas storage prices when authorized to do so by the Alberta Government, it is not currently Alberta Government policy to apply such rate regulation. As such, there is no cost-of-service or other utility-type regulation of storage rates or other commercial terms of storage contracts that apply to AECO Hub™. Therefore, AECO Hub™ can charge customers negotiated market-based rates as well as store purchased natural gas for its own account.

Environmental

Both AECO Hub™ facilities are subject to federal and provincial environmental laws and regulations, including oversight by Alberta's Department of Environment and Sustainable Resource Development and the AER. We are not aware of any material environmental liabilities relating to the AECO Hub™ facilities.

Wild Goose

Overview

Our Wild Goose storage facility is located 55 miles north of Sacramento, California. Wild Goose is a high deliverability, multi-cycle storage facility. This capability is made possible by the rock quality of the Wild Goose reservoirs and the extensive use of horizontal well technology.

Wild Goose is strategically located in a highly liquid market and is one of four independent operating storage facilities in northern California. Wild Goose provides natural gas receipt and delivery services at Pacific Gas & Electric Company (PG&E), or PG&E Citygate, a liquid trading point where natural gas supply from multiple upstream basins is bought and sold to various wholesale, end use and retail market participants. This provides an opportunity for storage to balance supply and demand. This location provides customers with the opportunity to take advantage of PG&E Citygate pricing, liquidity and arbitrage opportunities.

Facility

Wild Goose operates 17 natural gas storage wells that are completed in three depleted natural gas reservoirs with an effective working capacity of 75.0 Bcf and a gas generated compression of 27,900 horsepower. The Wild Goose reservoirs are located in high quality rock formations. In addition, the reservoirs have a strong water drive mechanism, which helps maintain reservoir pressure and well deliverability. Rights to use the reservoirs at Wild Goose for natural gas storage are held pursuant to a series of natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for the pipelines are derived from right-of-ways, easements, leases, and other similar land-use agreements.

Customers

Wild Goose's customers include a mix of natural gas market participants, including financial institutions, producers, marketers, power generators, pipelines and municipalities, resulting in a

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~~portfolio~~ ~~of customers with diverse usage patterns and different contract expiration dates. This allows us to optimize underutilized capacity.~~ Customers

Wild Goose's ~~has~~customers ~~contracts~~include ~~for~~a ~~terms~~mix of ~~one~~natural ~~year~~gas ormarket ~~longer.~~participants, Asincluding atfinancial ~~March 31~~institutions, ~~2015~~producers, ~~the~~marketers, ~~weighted~~power generators, ~~average~~pipelines ~~contract~~and ~~life~~municipalities, resulting in a portfolio of ~~our~~customers ~~LTF~~with ~~storage~~diverse ~~contracts~~usage atpatterns ~~Wild~~and ~~Goose~~different iscontract 2expiration dates.~~3 years~~ This allows us to optimize underutilized capacity.

Wild Goose has contracts for terms of one year or longer. As at March 31, 2016, the weighted average contract life of our LTF storage contracts at Wild Goose is 2.0 years.

Regulatory

Wild Goose is regulated as a state utility by the CPUC and is certified to serve the California ~~intra-state~~intrastate market. Wild Goose has regulatory authority to negotiate market based rates for third-party storage contracts and buys and sells natural gas for its own account to optimize its operations. In addition, as an independent storage provider Wild Goose is exempt from the ~~provisions~~ provisions of California's affiliate conduct rules and has the right to coordinate its operation with our other facilities. It is however, restricted from contracting for natural gas storage services with its affiliates.

Environmental

We are not aware of any material environmental liabilities relating to the Wild Goose facility.

In constructing and expanding the Wild Goose facility, we have experienced no significant environmental-related delays or unexpected costs by initially bringing forward development plans that mitigate any environmental impacts to the satisfaction of all responsible agencies and stakeholders.

Salt Plains

Overview

Our Salt Plains storage facility is located 110 miles north of Oklahoma City, Oklahoma. Salt Plains provides intrastate services in Oklahoma through its connection to pipelines operated by ONEOK Gas Transportation Pipelines, L.L.C., or ONEOK, and intrastate and interstate services through its interconnect with pipelines operated by Southern Star Central Gas Pipeline, Inc., or Southern Star.

Salt Plains is in a strategic mid-continent location with interconnects to pipelines owned by Southern Star and ONEOK, which serve both regional and mid-continent natural gas markets. This provides customers the benefits of liquidity, supply, and arbitrage opportunities. In addition, natural gas produced in the Rocky Mountains that is delivered to the mid-continent region gets redistributed to various pipelines such as Southern Star that have access to Salt Plains.

Facility

Salt Plains operates 30 gas storage wells and a gas generated compression of 10,000 horsepower. The reservoir is a depleted natural gas storage reservoir characterized by high quality rock. The wells are connected to a central plant facility by seven miles of pipeline. Rights to use the reservoir at Salt Plains for natural gas storage are held pursuant to a series of gas storage agreements with the mineral rights owners of the lands where the reservoir is situated. Rights for the lands used for the pipelines are derived under these gas storage agreements as well as from right-of-way grants from other land owners.

Customers

Over the years, Salt Plains' customers include a mix of natural gas market participants, including financial institutions, producers, and marketers. As at March 31, 2015, the weighted average contract life of our LTF storage contracts at Salt Plains is 2.0 years.

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Customers

Over the years, Salt Plains' customers include a mix of natural gas market participants, including financial institutions, producers, and marketers. As of March 31, 2016, the weighted average contract life of our LTF storage contracts at Salt Plains was 2.3 years.

Regulatory

Our Salt Plains intrastate operations are subject to regulation by the Oklahoma Corporation Commission, or the OCC. Salt Plains is also authorized to provide interstate storage service under the Natural Gas Policy Act of 1978 and the Federal Energy Regulatory Commission, or FERC, regulations and policies that allow intrastate pipeline and storage companies to engage in interstate commerce (commonly known as NGPA section 311 services). Salt Plains provides these NGPA section 311 services, which are not subject to FERC's broader jurisdiction under the Natural Gas Act, pursuant to a Statement of Operating Conditions which is on file with FERC. The OCC's regulatory policies are generally less stringent than those of FERC. Currently, Salt Plains is authorized to charge market based rates in both intrastate and interstate service and has no restrictions on affiliate interactions.

Environmental

We are not aware of any material environmental liabilities relating to the Salt Plains facility.

NGPL Contracted Capacity

Overview

From 2001 to March 31, 2015, one of our subsidiaries had a contract for 8.5 Bcf of gas storage capacity on the MidCon section and the TexOk section of the NGPL pipeline system in the mid-continent. On April 1, 2015 and May 1, 2016, 5.6 Bcf and 1.0 Bcf, respectively, of the original 8.5 Bcf expired, thereby reducing our leased capacity to 21.9 Bcf. The NGPL system connects and balances Gulf Coast and mid-continent supply basins with Chicago and other Midwestern U.S. end-use markets. NGPL has a number of different storage facilities on its pipeline system and manages its storage capacity as pools on separate legs of the pipeline. Under NGPL's FERC-approved tariff, NGPL is limited to charging cost-of-service rates for its transportation and storage services. We have a tariff-based right of first refusal to renew the remaining contracts, effectively making this capacity a long-term asset without any invested capital~~, with an option to exit either temporarily or permanently, should the rate be above market value~~.

As a customer of the NGPL capacity, and not the operator, we use our optimization strategy to generate revenue from our use of the capacity, and we do not remarket storage services.

Access Gas Services

We have a natural gas marketing business in Eastern Canada, British Columbia and Alberta serving commercial and industrial customers. In British Columbia, we also serve residential customers. This is a margin business where supply is contracted to serve customers at committed prices. In Eastern Canada, we also provide ~~fee-based~~ agency services to natural gas end-users. The retail marketing business is an extension of our proprietary optimization activities.

Regulation

Our operations are subject to extensive laws and regulations that have the potential to have a significant impact on our business. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. We are subject to regulatory oversight by federal, state, provincial and local regulatory agencies, many of which implement rules and regulations that are binding on the natural gas storage and pipeline industry, related businesses and individual participants. The failure to comply with such laws and regulations can result in substantial penalties. The cost of regulatory compliance on our operations increases our costs of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.

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The failure to comply with such laws and regulations can result in substantial penalties. The cost of regulatory compliance on our operations increases our costs of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors.

Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. The following is a summary of the kinds of regulation that may impact our operations. However, such discussion should not be considered an exhaustive review of all regulatory considerations affecting our operations.

Environmental Matters

Our natural gas storage operations are subject to stringent and complex federal, state, provincial and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals. These laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities under statutes such as the Clean Water Act, the Clean Air Act, or CAA, the Safe Drinking Water Act and comparable legislation in Canada, limiting or preventing the release of materials from our facilities, managing wastes generated by our operations, the installation of pollution control equipment, responding to releases of process materials or wastes from our operations, and the risk of substantial liabilities for pollution resulting from our operations. The Occupational Safety and Health Act, or OSHA, comparable state statutes that regulate the protection of the health and safety of workers, as well as the Occupational Health and Safety Act in the Province of Alberta, and comparable federal legislation in Canada also apply to our operations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil, and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. We believe that we are in substantial compliance with existing environmental laws and regulations and that such laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. For example, on April 17, 2012, the U.S. Environmental Protection Agency (EPA) finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers of natural gas processing plants, dehydrators, storage tanks and other production equipment. These rules may require a number of modifications to our operations including the installation of new equipment to control emissions. ~~Moreover,~~Because onmuch ~~April 21, 2014, the EPA proposed changes to its definition~~ of ~~"waters of~~ the ~~United~~regulation ~~States." A final rule~~ is ~~expected~~still inbeing ~~spring 2015. Because the content of the EPA's final rule~~finalized, ~~if any, is unknown,~~ we cannot currently assess the potential impact of ~~the~~proposed ~~EPA's~~regulations ~~proposal~~ on our operations.

AsSeveral apotential ~~result~~pieces of ~~these~~regulation ~~and~~that ~~similar developments, there can be no assurance of the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures~~ may ~~be different from the amounts that we currently anticipate. Moreover, these or similar developments could~~ affect ~~the demand for natural gas, have an adverse effect on~~ our ~~cost of doing~~ business, ~~and~~are ~~reduce~~as ~~demand for the natural gas storage services we provide.~~ follows:

•: Adoption of the Clean Power Plan Regulations

In August 2015, the U.S. Environmental Protection Agency (the "EPA") issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants to meet the individual state targets established in the Clean Power Plan. The EPA has also given states the option ~~Occupational~~to ~~Safety~~develop ~~and~~compliance ~~Health~~plans ~~Act~~ for annual rate-based reduction limits (pounds per megawatt hour or mass-based tonnage) for CO2.

~~The~~Judicial challenges ~~workplaces~~have inbeen filed. On February 9, 2016, the U.S. ~~associated~~Supreme ~~with~~Court ~~the~~granted ~~storage~~a ~~facilities~~stay weof ~~operate~~the ~~are~~implementation ~~subject~~of tothe CPP before the ~~requirements~~United States Court of ~~the~~Appeals ~~Federal~~for the ~~Occupational~~District ~~Safety~~of ~~and~~Columbia ~~Health~~("Circuit ~~Act,~~Court") oreven ~~OSHA,~~issued asa ~~amended~~decision. By its terms, asthis ~~well~~stay aswill remain in effect

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~~comparable~~throughout ~~state~~the ~~statutes~~pendency ~~that~~of ~~regulate~~ the ~~protection~~appeals ofprocess including at the ~~health~~Circuit Court and ~~safety~~the ofSupreme ~~workers.~~Court ~~Workplaces~~through inany ~~Canada~~certiorari ~~associated~~petition ~~with~~that ~~our~~may ~~operations~~be ~~are~~granted. ~~subject~~The tostay suspends the ~~requirements~~rule, ofincluding the ~~Occupational~~ ~~Health~~requirement ~~and~~that ~~Safety~~states ~~Act~~submit intheir ~~the~~initial ~~Province~~plans ofby ~~Alberta~~September ~~and~~2016. ~~comparable~~The ~~federal~~Supreme ~~legislation.~~Court's ~~Failure~~stay applies only to ~~comply~~EPA's ~~with~~regulations ~~OSHA~~for ~~requirements,~~CO2 oremissions ~~comparable~~from ~~requirements~~existing inpower ~~Canada,~~plants ~~including~~and ~~general~~will ~~industry~~not affect EPA's standards, ~~recordkeeping~~for ~~requirements~~new ~~and~~power ~~monitoring~~plants. It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of ~~occupational~~the ~~exposure~~CPP. toWe ~~regulated~~are ~~substances,~~currently ~~could~~assessing ~~subject~~the usimpact tothat ~~fines~~the Clean orPower ~~significant~~Plan ~~compliance~~would ~~costs~~have on the Company if the rules were upheld at the conclusion of this appellate process and were implemented in their current form.

•: Final Rule for the Waters of the United States

In May 2015, the EPA issued a final rule that sets forth changes to its definition of "waters of the United States" ("Rule") under the Clean Water Act ("CWA"). Judicial challenges to this Rule have been filed in district courts across the country and the Sixth Circuit issued a nationwide stay on the Rule in October 2015. The Sixth Circuit also issued a decision in February 2016 that challenges to the Rule are properly heard in front of appellate courts, rather than district courts. The fate of lawsuits in the various district courts is therefore uncertain. Several district courts have already dismissed challenges following the Sixth Circuit's jurisdictional ruling and EPA is currently seeking to dismiss challenges in other district courts on the same grounds. It is possible, however, that the district courts could find that the Sixth Circuit's ruling is not binding. In addition, both the Tenth and Eleventh Circuits are also considering whether challenges to the ~~Climate~~Rule ~~Change~~ are properly heard at the district or appellate level in light of the Sixth Circuit's recent jurisdictional ruling. It remains to be seen how the various proceedings will affect the substance of the Rule and its implementation. If the Rule survives the appeals process, any expansion to CWA jurisdiction could impose additional permitting obligations on our operations, which may adversely affect any development or expansion we may plan to undertake.

•: New National Ambient Air Quality Standards for Ozone

~~There~~On October 1, is2015, ~~increasing~~the ~~attention~~EPA infinalized both the ~~United~~8-hour ~~States~~primary and ~~worldwide~~secondary ~~concerning~~air ~~the~~quality ~~issue~~standards offor ~~climate~~ground ~~change~~level ~~and~~ozone, reducing the ~~effect~~acceptable level of ~~greenhouse gases~~ground ~~(GHGs).~~level ~~Future~~ozone ~~regulation~~to of70 parts ~~GHGs~~per inbillion ~~the~~from ~~United~~75 ~~States~~parts ~~could~~per ~~occur~~billion. ~~pursuant~~The toEPA ~~future~~will ~~U.S.~~now ~~treaty~~evaluate ~~commitments,~~the ~~new~~states' ~~domestic~~attainment ~~legislation~~status ~~that~~and ~~may~~the ~~impose~~states amust ~~carbon~~determine ~~emissions~~whether ~~tax~~additional orcontrol ~~establish~~measures ~~a cap-and-trade~~are ~~program~~needed orin ~~regulation~~order byto ~~the~~meet ~~EPA~~this standard. ~~The~~If ~~Obama~~states ~~Administration~~where ~~has~~we ~~indicated~~operate ~~its~~are ~~support~~not ~~for~~in aattainment ~~mandatory~~with ~~cap-and-trade~~this ~~program~~new tostandard, ~~reduce~~the ~~GHG~~EPA ~~emissions,~~may ~~and~~enact itadditional isregulations ~~possible~~beyond ~~that~~those ~~federal legislation~~currently ~~could~~contemplated beto ~~adopted~~further incontrol ~~the~~emissions ~~future.~~of ~~Similarly,~~volatile organic ~~the~~compounds ~~outcomes~~and ofnitrogen ~~ongoing~~oxides ~~international~~from ~~negotiations~~certain ~~since~~sources, ~~the~~which ~~2011~~could ~~Durban~~apply ~~Climate~~to ~~Change~~our ~~Conference~~operations ~~make~~and itcould ~~possible~~result ~~that~~in aincreased ~~new,~~compliance ~~legally-binding international~~costs. ~~instrument~~Niska toPartners ~~control~~cannot ~~GHGs~~predict ~~will~~the befinancial ~~adopted~~impact in of the ~~future~~revised ozone standards at this time.

•: Carbon Taxes in British Columbia and Alberta

~~While~~British aColumbia ~~new~~imposes ~~federal~~a orcarbon ~~international~~tax ~~program~~of ~~seems~~C$30 ~~unlikely~~per inton ~~the~~of ~~near~~carbon ~~future,~~dioxide weequivalent ~~may~~emissions. ~~have~~In toNovember ~~comply~~2015, ~~with~~Alberta ~~state~~unveiled orplans ~~regional programs~~ to ~~limit~~institute ~~GHG~~an ~~emissions.~~economy-wide ~~State~~carbon ~~and~~tax ~~regional programs~~beginning ~~that~~in ~~may~~2017. ~~impact~~The ~~our~~C$20 ~~operations~~per ~~include~~ton ~~the~~price ~~Western~~on ~~Climate~~carbon ~~Initiative~~emissions ~~(WCI)~~will ~~and~~cover ~~the~~approximately ~~Regional~~90% ~~Greenhouse~~of ~~Gas~~the ~~Initiative~~economy, ~~(RGGI).~~including ~~The~~natural ~~future status of RGGI~~gas, and ~~agreement between the states in the Northeastern U.S. is uncertain. We do not believe that RGGI~~ will ~~impact~~increase ~~our~~to ~~business~~C$30 ~~because~~per weton ~~do not currently have operations~~ in ~~RGGI member states~~2018. ~~The~~These ~~WCI~~taxes iscould anreduce ~~agreement~~demand ~~that was originally~~for ~~between~~natural ~~the states of California~~gas, ~~Oregon,~~have ~~Washington,~~an ~~New~~adverse ~~Mexico,~~effect ~~Arizona,~~on ~~Utah~~our ~~and~~cost ~~Montana, and the Canadian provinces~~ of ~~British~~doing ~~Columbia~~business, ~~Manitoba, Ontario,~~ and ~~Quebec~~reduce todemand ~~create a regional cap-and-trade scheme~~ for ~~GHG~~the ~~emissions.~~natural ~~However,~~gas instorage ~~2011,~~services ~~all~~we ~~states except California withdrew from the WCI. Still though~~provide, italthough iswe ~~likely~~would ~~that~~not ~~regional~~be ~~efforts~~impacted to ~~curb GHG emissions will continue. Depending on the scope of~~ any ~~regional~~greater ~~programs~~degree ~~that~~than ~~we must comply with, we could be required to obtain and surrender~~other ~~allowances~~similarly-situated ~~for~~natural ~~GHG~~gas ~~emissions~~storage ~~statutorily attributed to our operations (e~~companies.~~g., emissions~~ ~~from compressor stations or the injection and withdrawal of natural gas).~~

•: California Regulation

InFollowing ~~2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with~~ a ~~goal~~major ofnatural ~~reaching~~gas ~~(i) 1990~~leak ~~GHG~~near ~~emissions~~Porter ~~levels by the year 2020~~Ranch, ~~(ii) 80% of 1990 levels by 2050~~California, ~~and (iii) establishing a mandatory emissions reporting program. AB 32 directed~~ the California ~~Air~~Department ~~Resources~~of ~~Board,~~Conservation orannounced ~~CARB,~~in toFebruary ~~begin~~2016 ~~developing~~emergency ~~discrete~~regulations ~~early~~requiring ~~actions~~enhanced ~~to reduce GHGs~~testing, ~~while~~inspection ~~also~~and ~~preparing~~monitoring ~~a scoping plan to identify how best to reach the 2020 limit. Since the passage~~ of ABoil ~~32, the CARB approved in December 2010 a GHG cap-~~and~~-trade~~ ~~program,~~gas ~~which~~storage ~~was scheduled to take effect~~ in ~~2012. However, various legal challenges threaten to further delay~~ California~~'s cap-and-trade program~~. NoRequirements ~~final~~include ~~determination~~daily ~~has~~inspection ~~been~~of ~~made~~gas ~~with~~storage ~~regard~~well toheads, ~~the~~ongoing ~~potential~~verification ~~applicability~~ of ~~the~~ ~~AB 32 cap-and-trade program to our operations. We are therefore not in a position to quantify any potential costs associated with compliance under~~ the ~~program~~mechanical asintegrity ~~proposed.~~of ~~However,~~gas ~~any~~storage ~~limitation~~wells, aongoing ~~finalized program places on GHG emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.~~

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~~Safety~~measurement ~~Administration~~of ~~setting~~annular ~~GHG~~gas ~~emission~~pressure ~~and~~or ~~fuel~~annular ~~economy~~gas ~~standards~~flow ~~for~~within ~~new~~wells, ~~light-duty~~regular ~~vehicles;~~testing ~~(3) the~~of ~~April~~all ~~2010~~safety ~~"Timing~~valves ~~Rule,"~~used ~~concluding~~in ~~that~~wells, ~~stationary~~compliance ~~source~~with ~~regulation~~minimum ~~under Titles I~~ and Vmaximum ofpressure ~~the~~limits, ~~CAA~~and ~~(involving~~establishment ~~Prevention~~ of ~~Significant~~a comprehensive ~~Deterioration~~risk ~~regulations~~management ~~and~~plan ~~operating~~for ~~permits,~~each ~~respectively)~~facility. ~~must~~The ~~regulate~~regulations ~~GHG~~will ~~emissions~~remain ~~beginning~~in ~~when~~effect ~~such~~for ~~emissions~~six ~~are~~months, ~~subject~~but tocan ~~controls under~~be ~~the~~extended ~~mobile~~if ~~source~~necessary. ~~provisions~~The ofDepartment ~~the~~intends ~~Act;~~to ~~(4) the~~develop ~~June~~permanent ~~2010~~regulations after ~~"Tailoring~~a ~~Rule,"~~public ~~exempting~~comment ~~small~~period. ~~stationary~~These ~~sources~~regulations ~~from~~are ~~PSD~~likely ~~and~~to ~~Title~~have Van ~~requirements~~adverse ~~through~~effect ~~regulations~~on ~~modifying~~our ~~the~~costs ~~Act's emissions~~of ~~thresholds;~~doing ~~and (5) the December 2010 "SIP Call" rule~~business, ~~finding~~although ~~thirteen~~we ~~state~~should ~~Implementation Plans ("SIPs") inadequate because they did~~ not ~~regulate~~be ~~GHGs~~impacted ~~from stationary sources, and directing those states~~ to ~~correct~~any ~~the~~greater ~~inadequacies~~degree orthan ~~face~~other ~~federalization~~similarly situated ofnatural ~~their~~gas ~~permitting~~storage ~~programs~~companies.

OnIn ~~June 2,~~addition ~~2014,~~to ~~the~~these ~~EPA~~emergency ~~further~~regulations, ~~proposed~~it ~~new~~is ~~regulations~~possible ~~limiting~~that ~~carbon~~the ~~dioxide~~Porter ~~emissions~~Ranch ~~from~~natural ~~existing~~gas ~~power~~leak ~~generation~~may ~~facilities.~~lead ~~Under~~to ~~this~~legislation ~~proposal,~~or ~~nationwide~~other ~~carbon dioxide~~regulations ~~emissions~~that would beimpose further regulatory ~~reduced~~requirements byon ~~30%~~natural ~~from~~gas ~~2005~~storage. ~~levels~~For byinstance, ~~2030~~Senate ~~with~~Bill a887 ~~flexible~~introduced ~~interim~~earlier ~~goal.~~this ~~The~~year ~~final~~would ~~rule~~have ~~has~~imposed ~~been~~more ~~submitted~~rigorous toinspection ~~the~~requirements ~~White~~on ~~House~~wells, ~~Office~~required ofthe ~~Management~~adoption ~~and~~of ~~Budget~~more stringent standards for ~~review~~well ~~and~~design, isinstallation ~~expected~~and tositing beand ~~issued~~the ~~by mid~~phase-~~summer~~out ~~2015,~~of ~~with~~non-complying ~~the~~wells ~~emission~~over ~~reductions~~time. ~~scheduled~~At tothis ~~commence~~stage, init ~~2020.~~is Ifimpossible ~~finalized~~to ~~along~~say ~~the~~whether ~~lines~~this proposed, ~~the~~legislation ~~rule~~or ~~could~~other legislation ~~result~~that inmay ~~increased~~be ~~demand~~proposed ~~for~~to further regulate natural gas. ~~However,~~storage ~~any~~will ~~expansion~~be ~~to the~~enacted ~~proposed~~in ~~program,~~California. orIf ~~the~~any ~~adoption~~such ofrequirements ~~similar~~are ~~legislative~~enacted orinto ~~regulatory~~law ~~programs~~ in ~~the~~California ~~future,~~and ~~that~~apply ~~sought~~ to ~~reduce~~our ~~greenhouse~~operations, complying ~~gas emissions associated~~ with ~~the~~these ~~use~~more ofstringent ~~natural~~standards ~~gas~~ could ~~reduce demand~~increase ~~for~~our ~~natural~~costs ~~gas,~~of ~~have~~operations anand ~~adverse~~restrict ~~effect~~the onscope of our ~~cost~~operations. ofThese ~~doing~~requirements ~~business,~~would ~~and~~apply ~~reduce~~to ~~demand~~our ~~for~~competitors ~~the~~as ~~natural~~well ~~gas~~and ~~storage~~we ~~services~~do wenot foresee ~~provide,~~that ~~although~~our weoperations ~~would~~or ~~not~~business would be impacted to any greater degree than other similarly- situated natural gas storage companies. Although EPA's actions are subject to further procedural delays and legal challenges, and efforts are underway in Congress to limit or remove the EPA's authority to regulate GHG emissions, they will proceed as proposed unless revised by the EPA or altered by the courts or Congress.

~~Pursuant~~As to a ~~Congressional~~result ~~mandate~~of inthese ~~the~~and ~~FY2008~~similar ~~Consolidated Appropriations Act~~developments, ~~EPA~~there ~~has~~can ~~promulgated~~be ~~regulations~~no ~~requiring~~assurance ~~the measuring and reporting~~ of ~~GHG emissions from a variety of industrial sources. Finalized in October 2009,~~ the ~~Mandatory~~amount ~~Reporting of Greenhouse Gas Emissions Rule (Mandatory Reporting Rule~~ or ~~MRR)~~timing ~~sets~~of ~~out~~future ~~general~~expenditures ~~provisions~~for ~~applicable~~environmental ~~to all entities with MRR~~ compliance ~~obligations,~~or ~~as well as a series of subparts covering particular industrial sectors. For most sectors~~remediation, ~~MRR~~and ~~obligations~~actual ~~are triggered when the facility's emissions exceed 25,000 metric~~future ~~tons~~expenditures ofmay ~~carbon dioxide equivalent in a year, however, some facilities will~~ be ~~covered~~different ~~regardless~~from ~~of their emissions levels. Since~~ the ~~initial~~amounts ~~MRR~~that ~~was~~we ~~finalized,~~currently ~~the~~anticipate. ~~EPA has gone on to finalize additional subparts~~Moreover, ~~bringing~~these ~~new~~or ~~sectors~~similar ~~within~~developments ~~the~~could ~~scope~~affect of the ~~rule.~~demand ~~Finalized~~for ~~in June 2010, Subpart W of the MRR applies to owners and operators of petroleum and~~ natural gas ~~systems~~, ~~which are~~have ~~defined~~an toadverse ~~include~~effect ~~onshore~~on ~~oil~~our ~~and~~cost ~~natural gas production, offshore oil and natural gas production, onshore natural gas process, onshore natural gas transmission and compression, underground~~of ~~natural~~doing ~~gas storage~~business, ~~LNG storage,~~ and ~~LNG~~reduce ~~import~~demand ~~and~~for ~~export activities be subject to~~ the ~~MRR's requirements if they emit more than 25,000 metric tons of carbon dioxide equivalent per year. Because our primary business involves underground~~ natural gas storage, services we ~~are potentially subject to Subpart W of the MRR~~provide.

~~British~~ ~~Columbia has been in the process of implementing a cap-and-trade system consistent with the requirements of the WCI. The province has created a Climate Action Secretariat that is~~ ~~responsible for developing cap-and-trade rules. Ontario, another province participating in the WCI, committed to a phase out of coal fired power by 2014. Ontario closed its last coal-fired generating~~ ~~plant in April 2014. The current Ontario government brought forward Bill 138, Ending Coal for Cleaner Air Act, 2013. Subject to certain exceptions, the~~ ~~bill amends the Environmental Protection Act (Ontario) by adding a new part which prohibits the use of coal at generation facilities after Dec 31, 2014.~~ ~~The~~ Occupational ~~Ending~~Safety ~~Coal for Cleaner Air Act, 2013 is through its 2nd reading~~ and isHealth ~~still proposed legislation.~~ Act

~~Alberta regulates~~The ~~GHG~~workplaces ~~emissions~~in ~~under~~the U.S. associated with the ~~Climate~~storage ~~Change~~facilities ~~and~~we ~~Emissions~~operate ~~Management~~are subject to the requirements of the Federal Occupational Safety and Health Act, or OSHA, as amended, as well as comparable state statutes that regulate the ~~Specified~~protection ~~Gas~~of ~~Reporting~~the ~~Regulation~~health (and safety of workers. Workplaces in Canada associated with our operations are subject to the ~~"SGRR")~~requirements of the Occupational Health and Safety Act in the Province of Alberta and comparable federal legislation. Failure to comply with OSHA requirements, ~~which~~or comparable ~~imposes~~requirements ~~GHG~~in ~~emissions~~Canada, ~~reporting~~including general industry standards, recordkeeping requirements and monitoring of occupational exposure to regulated substances, could subject us to fines or significant compliance costs.

Climate Change

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases (GHGs). The Paris Agreement, which was announced by the Parties to the United Nations Framework Convention on Climate Change in December 2015, established a global goal of keeping temperatures well below 2 ºC above preindustrial levels. The Agreement is not legally binding on the parties, however. In the United States, future regulation of GHGs could occur pursuant to future U.S. treaty commitments. Under the Paris Agreement, the United States has pledged to reduce its emissions by 26 to 28% in 2025 relative to a 2005 baseline. While the U.S. will likely not need to take Congressional action to meet these initial commitments, further reductions would likely require domestic legislation beyond the Clean Power Plan, such as a carbon emissions tax or a cap-and-trade program.

While a new federal or international program seems unlikely in the near future, we may have to comply with state or regional programs to limit GHG emissions. State and regional programs that may impact our operations include the Western Climate Initiative (WCI) and the Regional Greenhouse Gas

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~~requirements,~~Initiative ~~and the Specified Gas Emitters Regulation~~ (~~the "SGER"~~RGGI)~~, which imposes GHG emissions limits~~. AThe ~~facility~~future ~~subject~~status ~~to the SGRR must report if it has GHG emissions~~ of 50RGGI,~~000~~ ~~metric~~and ~~tonnes~~agreement ~~or more~~between inthe ~~any~~states ~~year.~~in ~~Under~~ the ~~SGER,~~Northeastern ~~GHG~~U.S. ~~emission~~is ~~limits~~uncertain. ~~apply~~We ~~once~~do anot ~~facility~~believe ~~has~~that ~~direct~~RGGI ~~GHG~~will ~~emissions~~impact inour abusiness ~~year~~because ofwe ~~100,000~~do ~~metric~~not ~~tonnes or more. Under the SGER, subject facilities are required to~~currently ~~reduce~~have ~~their~~operations ~~emission~~in ~~intensities~~RGGI (emember states.~~g., metric~~ ~~ton~~The ofWCI ~~GHGs~~is ~~emitted~~an ~~per~~agreement ~~unit~~that ofwas ~~production)~~originally bybetween ~~12% in~~ the ~~case~~states of ~~facilities~~California, ~~operating~~Oregon, ~~prior~~Washington, toNew ~~2000~~Mexico, ~~and~~Arizona, byUtah 2%and ~~per~~Montana, ~~year~~and ~~beginning in~~ the ~~fourth~~Canadian ~~year~~provinces of ~~commercial~~British ~~operations~~Columbia, ~~for~~Manitoba, ~~facilities~~Ontario, ~~commencing operations in 2000~~ and ~~after~~Quebec up to create a ~~maximum~~regional ofcap-and-trade ~~12%.~~scheme Afor ~~facility~~GHG ~~subject~~emissions. toHowever, ~~the~~in ~~SGER~~2011, ~~may~~all ~~meet~~states ~~the~~except ~~applicable~~California ~~emission~~withdrew ~~limits~~from bythe ~~making~~WCI. ~~emissions~~Still, ~~intensity~~it ~~improvements,~~is ~~offsetting~~likely ~~GHG~~that ~~emissions~~regional byefforts ~~purchasing~~to ~~offset~~curb ~~credits~~GHG oremissions ~~emission~~will ~~performance~~continue. ~~credits~~Depending inon the ~~open~~scope ~~market,~~of orany ~~acquiring~~regional ~~"fund~~programs ~~credits"~~that bywe ~~making~~must ~~payments~~comply ofwith, ~~CDN~~we ~~$15~~could ~~per~~be ~~metric tonne~~required to ~~the~~obtain ~~Alberta~~and ~~Climate~~surrender allowances ~~Change~~for ~~and~~GHG ~~Management~~emissions ~~Fund.~~statutorily ~~The~~attributed ~~direct~~to ~~and~~our ~~indirect~~operations ~~costs~~(e.g., emissions offrom ~~these~~compressor ~~regulations~~stations ~~may~~or ~~adversely~~the ~~affect~~injection ~~our~~and ~~operations~~withdrawal ~~and~~of ~~financial~~natural ~~results~~gas).

In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching (i) 1990 GHG emissions levels by the year 2020, (ii) 80% of 1990 levels by 2050, and (iii) establishing a mandatory emissions reporting program. AB 32 directed the California Air Resources Board, or CARB, to begin developing discrete early actions to reduce GHGs while also preparing a scoping plan to identify how best to reach the 2020 limit. Since the passage of AB 32, the CARB approved in December 2010 a GHG cap-and-trade program, which was scheduled to take effect in 2012. Compliance obligations for some entities began in 2013. However, various legal challenges threaten to further delay California's cap-and-trade program. No final determination has been made with regard to the potential applicability of the AB 32 cap-and-trade program to our operations. We are therefore not in a position to quantify any potential costs associated with compliance under the program as proposed. However, any limitation a finalized program places on GHG emissions from our equipment and operations could require us to incur costs to reduce the GHG emissions associated with our operations.

Even in the absence of new federal legislation the EPA has begun to regulate GHG emissions using its authority under the CAA as articulated by the April 2007 United States Supreme Court ruling in Massachusetts, et al. v. EPA that the EPA has authority to regulate carbon dioxide emissions. The GHG regulations that the EPA has issued following Massachusetts , et al. v. EPA include: (1) the December 2009 "endangerment finding" determining that air pollution from six GHGs endangers public health and welfare, and that mobile sources cause or contribute to that air pollution; (2) the May 2010 "Tailpipe Rule," issued jointly with the National Highway Traffic Safety Administration setting GHG emission and fuel economy standards for new light-duty vehicles; (3) the April 2010 "Timing Rule," concluding that stationary source regulation under Titles I and V of the CAA (involving Prevention of Significant Deterioration regulations and operating permits, respectively) must regulate GHG emissions beginning when such emissions are subject to controls under the mobile source provisions of the Act; (4) the June 2010 "Tailoring Rule," exempting small stationary sources from PSD and Title V requirements through regulations modifying the Act's emissions thresholds; (5) the December 2010 "SIP Call" rule, finding thirteen state Implementation Plans ("SIPs") inadequate because they did not regulate GHGs from stationary sources, and directing those states to correct the inadequacies or face federalization of their permitting programs; and (6) the August 2015 Clean Power Plan (CPP), which establishes carbon pollution standards for power plants. For more information, see the "Adoption of the Clean Power Plan Regulations" section above.

If the CPP survives legal challenges, the rule could result in increased demand for natural gas. However, any expansion to the proposed program, or the adoption of similar legislative or regulatory programs in the future, that sought to reduce greenhouse gas emissions associated with the use of natural gas could reduce demand for natural gas, have an adverse effect on our cost of doing business, and reduce demand for the natural gas storage services we provide, although we would not be impacted to any greater degree than other similarly-situated natural gas storage companies. EPA's actions are subject to further procedural delays and legal challenges, however, and it is not yet clear how either the D.C. Circuit Court or the Supreme Court will rule on the legality of the CPP.

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Pursuant to a Congressional mandate in the FY2008 Consolidated Appropriations Act, EPA has promulgated regulations requiring the measuring and reporting of GHG emissions from a variety of industrial sources. Finalized in October 2009, the Mandatory Reporting of Greenhouse Gas Emissions Rule (Mandatory Reporting Rule or MRR) sets out general provisions applicable to all entities with MRR compliance obligations, as well as a series of subparts covering particular industrial sectors. For most sectors, MRR obligations are triggered when the facility's emissions exceed 25,000 metric tons of carbon dioxide equivalent in a year, however, some facilities will be covered regardless of their emissions levels. Since the initial MRR was finalized, the EPA has gone on to finalize additional subparts, bringing new sectors within the scope of the rule. Finalized in June 2010, Subpart W of the MRR applies to owners and operators of petroleum and natural gas systems, which are defined to include onshore oil and natural gas production, offshore oil and natural gas production, onshore natural gas process, onshore natural gas transmission and compression, underground natural gas storage, LNG storage, and LNG import and export activities be subject to the MRR's requirements if they emit more than 25,000 metric tons of carbon dioxide equivalent per year. Because our primary business involves underground natural gas storage, we are potentially subject to Subpart W of the MRR.

British Columbia has been in the process of implementing a cap-and-trade system consistent with the requirements of the WCI. The province has created a Climate Action Secretariat that is responsible for developing cap-and-trade rules. Ontario, another province participating in the WCI, committed to a phase out of coal fired power by 2014. Ontario closed its last coal-fired generating plant in April 2014. The current Ontario government brought forward Bill 138, Ending Coal for Cleaner Air Act, 2013. Subject to certain exceptions, the bill amends the Environmental Protection Act (Ontario) by adding a new part which prohibits the use of coal at generation facilities after December 31, 2014. The Ending Coal for Cleaner Air Act, 2013 is through its first reading and is still proposed legislation.

Alberta regulates GHG emissions under the Climate Change and Emissions Management Act, the Specified Gas Reporting Regulation (the "SGRR"), which imposes GHG emissions reporting requirements, and the Specified Gas Emitters Regulation (the "SGER"), which imposes GHG emissions limits. A facility subject to the SGRR must report if it has GHG emissions of 50,000 metric tonnes or more in any year. Under the SGER, GHG emission limits apply once a facility has direct GHG emissions in a year of 100,000 metric tonnes or more. Under the SGER, subject facilities are required to reduce their emission intensities (e.g., metric ton of GHGs emitted per unit of production) by 12% in the case of facilities operating prior to 2000 and by 2% per year beginning in the fourth year of commercial operations for facilities commencing operations in 2000 and after up to a maximum of 12%. A facility subject to the SGER may meet the applicable emission limits by making emissions intensity improvements, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring "fund credits" by making payments of CDN $15 per metric tonne to the Alberta Climate Change and Management Fund. The direct and indirect costs of these regulations may adversely affect our operations and financial results.

Rates

Commercial arrangements at our facilities in the U.S. are subject to the jurisdiction of regulators, including FERC, the OCC and the CPUC. With authorization of the Alberta Government, commercial arrangements at our facility in Alberta, Canada, could be regulated by the AUC, but it is not currently Alberta Government policy to apply any such rate regulation. Each of our facilities currently has the ability to negotiate and charge rates based upon market prices, and are not limited to charging cost-of-service rates which are capped at recovery of costs plus a reasonable rate of return. The exemptions we receive under the regulatory regimes applicable to us enable us to buy, sell and store natural gas for our own account at our existing storage assets. The ability to charge market-based rates enables us to charge greater prices than many other storage providers which are required to charge cost-of-service based rates and our ability to buy, sell and store natural gas for our own account enables us to optimize our working gas capacity. In addition, we are permitted to consolidate management, marketing, and administrative functions for efficiencies in matters that some competing operators are prohibited from due to affiliate rules to which they are subject.

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cost-of-service based rates and our ability to buy, sell and store natural gas for our own account enables us to optimize our working gas capacity. In addition, we are permitted to consolidate management, marketing, and administrative functions for efficiencies in matters that some competing operators are prohibited from due to affiliate rules to which they are subject.

Employees

As of March 31, ~~2015~~2016, we had ~~126~~121 employees. Our executive officers are currently employed by Niska Gas Transport Inc., Niska Partners Management ULC and subsidiaries of Niska Gas Storage Partners LLC.

Competition

The natural gas storage business is competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, access to supply sources, access to demand markets and flexibility and reliability of service. Because our facilities are strategically located in key North American natural gas producing and consuming regions, we face competition from existing competitors who also operate in those markets. Our competitors include natural gas storage companies, major integrated energy companies, pipeline operators and natural gas marketers of varying sizes, financial resources and experience. Competitors of the AECO Hub™ currently include TransCanada (Edson, CrossAlta), Atco (Carbon) and Enstor (Alberta Hub). Competitors of our Wild Goose facility currently include Brookfield Infrastructure (Lodi), PG&E, NW Natural (Gill Ranch), Central Valley Gas and a number of proposed projects in northern California. Competitors of our Salt Plains facility currently include Southern Star. Given the key location of our facilities, additional competition in the markets we serve could arise from new developments or expanded operations from existing competitors.

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Seasonality

Our cash expenditures related to our optimization activities are typically highest during summer months, and our cash receipts from our optimization activities are typically highest during winter months. Consequently, our results of operations for the summer are generally lower than for the winter.

Geographic Data; Financial Information about Segments

See Note 2223 toof our Consolidated Financial Statements.

Available Information

We make available, free of charge on our website (www.niskapartners.com), our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission ("SEC").

The public may also read and copy any materials we have filed with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a website that contains our reports, proxy and information statements and our other SEC filings. The address of that website is www.sec.gov.

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Item 1A. Risk Factors.

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be adversely affected.

Risks Related to the Transaction

There may be substantial disruption to our business and distraction of its management and employees as a result of the Transaction.

There may be substantial disruption to our business and distraction of our management and employees from day-to-day operations because matters related to the Transaction may require substantial commitments of time and resources which could otherwise have been devoted to other opportunities that could have been beneficial to us.

We may have difficulty attracting, motivating and retaining executives and other employees in light of the Transaction.

Our success depends in part upon our ability to retain our key employees. Some of those key employees may depart because of issues and uncertainty related to the Transaction or a desire not to remain following the Transaction. Accordingly, no assurance can be given that we will be able to retain key employees to the same extent as in the past.

The Transaction is subject to conditions, including certain conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Transaction, or significant delays in completing the Transaction, could negatively affect the trading prices of our common units and our future business and financial results.

The completion of the Transaction is subject to a number of conditions. The completion of the Transaction is not assured and is subject to risks, including the risk that certain closing conditions are not satisfied. If the Transaction is not completed, or if there are significant delays in completing the Transaction, the trading prices of our common units and our future business and financial results could be negatively affected, and will be subject to several risks, including the following:

•: we may be liable for damages to Brookfield under the terms and conditions of the Merger Agreement;
•: negative reactions from the financial markets, including declines in the price of our common units due to the fact that current prices may reflect a market assumption that the Transaction will be completed; and
•: the attention of our management will have been diverted to the Transaction rather than our own operations and the pursuit of other opportunities that could have been beneficial to us.
•: our Credit Agreement (defined below) will mature on September 30, 2016 and allows for an additional term extension to December 31, 2016 providing that the Transaction has closed. We may be required to obtain additional funds and/or a substitute financing to repay the outstanding balance at the earlier date of September 30, 2016.

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Risks Inherent in Our Business

Our level of exposure to the market value of natural gas storage services could adversely affect our revenues.

As portions of our third-party natural gas storage contract portfolio come up for replacement or renewal, and capacity becomes available, adverse market conditions may prevent us from replacing or renewing the contracts on terms favorable to us. The market value of our storage capacity, realized through the value customers are willing to pay for LTF contracts or via the opportunities to be captured by our STF contracts or optimization activities, could be adversely affected by a number of factors beyond our control, including:

•: prolonged reduced natural gas price volatility;
•: a material reduction in the difference between winter and summer prices on the natural gas futures market, sometimes referred to as the seasonal spread, due to real or perceived changes in supply and demand fundamentals;
•: a decrease in demand for natural gas storage in the markets we serve;
•: increased competition for storage in the markets we serve; and
•: interest rates which, when higher, increase the cost of carrying owned or customer inventory.

A prolonged downturn in the natural gas storage market due to the occurrence of any of the above factors could result in our inability to renegotiate or replace a number of our LTF contracts upon their expiration, leaving more capacity exposed to the value that could be generated through STF contracts or optimization. STF and optimization values would be impacted by the same factors, and market conditions could deteriorate further before the opportunity to extract value with those strategies could be realized.

Further, our lines of business and assets are concentrated solely in the natural gas storage industry. Thus, adverse developments, including any of the industry-specific factors listed above, would have a more severe impact on our business, financial condition and results of operations than if we maintained a more diverse business.

We face significant competition that may cause us to lose market share, negatively affecting our business.

Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. The natural gas storage business is competitive. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, flexibility and reliability of service. Our operations compete primarily with other storage facilities in the same markets in the storage of natural gas. The CPUC has adopted policies that favor the development of new storage projects and there are numerous projects, including expansions of existing facilities and greenfield construction projects, at various stages of development in the market where our Wild Goose facility operates. These projects, if developed and placed into service, may compete with our storage operations.

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We also compete with certain pipelines, marketers and liquefied natural gas, or LNG, facilities that provide services that can substitute for certain of the storage services we offer. In addition, natural gas as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas storage services. Some of our competitors have greater financial resources and may now, or in the future, have greater access to expansion or development opportunities than we do.

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If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct new storage facilities that would create additional competition for us. The storage facility expansion and construction activities of our competitors could result in storage capacity in excess of actual demand, which could reduce the demand for our services, and potentially reduce the rates that we receive for our services.

We also face competition from alternatives to natural gas storage—ways to increase supply of or reduce demand for natural gas at peak times such that storage is less necessary. For example, excess production or supply capability with sufficient delivery capacity on standby until required for peak demand periods or ability for significant demand to quickly switch to alternative fuels at peak times would represent alternatives to natural gas storage.

Competition could intensify the negative impact of factors that significantly decrease demand for natural gas at peak times in the markets served by our storage facilities, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas. Increased competition could reduce the volumes of natural gas stored in our facilities or could force us to lower our storage rates.

If third-party pipelines interconnected to our facilities become unavailable or more costly to transport natural gas, our business could be adversely affected.

We depend upon third-party pipelines that provide delivery options to and from our storage facilities for our benefit and the benefit of our customers. Because we do not own these pipelines, their continuing operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, line repair, reduced operating pressure, lack of operating capacity or curtailments of receipt or deliveries due to insufficient capacity. In addition, these third-party pipelines may become unavailable to us and our customers because of the failure of the interconnects that transport natural gas between our facilities and the third-party pipelines. Because of the limited number of interconnects at our facilities (Wild Goose is connected to third- party pipelines by two interconnects, AECO Hub™ by two interconnects (one at each facility) and Salt Plains by two interconnects), the failure of any interconnect could materially impact our ability or the ability of our customers to deliver natural gas into the third-party pipelines. If the costs to us or our customers to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If third-party pipelines become partially or completely unavailable, our ability to operate could be restricted, thereby reducing our profitability. A prolonged or permanent interruption at any key pipeline interconnect could have a material adverse effect on our business, financial condition and results of operations.

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Our operations are subject to operational hazards and unforeseen interruptions, which could have a material adverse effect on our business.

Our operations are subject to the many hazards inherent in the storage of natural gas, including, but not limited to:

•: negative unpredicted performance by our storage reservoirs that could cause us to fail to meet expected or forecasted operational levels or contractual commitments to our customers;
•: unanticipated equipment failures at our facilities;
•: damage to storage facilities and related equipment caused by tornadoes, hurricanes, floods, earthquakes, fires, extreme weather conditions and other natural disasters and acts of terrorism;

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•: damage from construction and farm equipment or other surface uses;
•: leaks of or other losses of natural gas as a result of the malfunction of equipment or facilities;
•: migration of natural gas through faults in the rock or to some area of the reservoir where the existing wells cannot drain the natural gas effectively;
•: blowouts (uncontrolled escapes of natural gas from a well), fires and explosions;
•: operator error; and
•: environmental pollution or release of toxic substances.

These risks could result in substantial losses due to breaches of our contractual commitments, personal injury or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our operations. In addition, operational interruptions or disturbances, mechanical malfunctions, faulty measurements or other acts, omissions, or errors may result in significant costs or lost revenues. Natural gas that moves outside of the effective drainage area through migration could be permanently lost and will need to be replaced to maintain design storage performance.

Information technology systems present potential targets for cyber security attacks.

We are reliant on technology to improve efficiency in our business. Information technology systems are critical to our operations. These systems could be a potential target for a cyber security attack as they are used to store and process sensitive information regarding our operations, financial position, and information pertaining to our customers and vendors. While we take the utmost precautions, we cannot guarantee safety from all threats and attacks. Any successful breach of security could result in the spread of inaccurate or confidential information, disruption of operations, environmental harm, endangerment of employees, damage to our assets, and increased costs to respond. Any of these instances could have a negative impact on cash flows, litigation status and/or our reputation, which could have a material adverse affect on our business, financial conditions, and operations. There is no guarantee that adequate insurance to cover the effects of a cyber security attack will be available at rates we believe are reasonable in the near future or that the cost of responding to a breach will be covered by insurance or recoverable in rates.

We are not fully insured against all risks incident to our business, and if an accident or event occurs that is not fully insured it could adversely affect our business.

We may not be able to obtain the levels or types of insurance we desire, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial results.

We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use the capacity could have a material adverse effect on our business, financial condition and results of operations.

To the extent any one or more of these customers becomes financially distressed or commences bankruptcy proceedings, the contracts governing these customer relationships could be renegotiated at

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lower rates or rejected under applicable provisions of the United States Bankruptcy Code. Any such renegotiation or rejection could have a material adverse effect on our revenue and cash flows and our ability to make cash distributions to our unitholders.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We have $575.0 million principal amount outstanding of the 6.50% senior notes due 2019. In addition, we have credit facilities that provide us up to $~~400~~370.0 million in borrowing capacity. Our level of debt could have important consequences to us, including the following:

•: additional financing for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•: we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to members; and
•: we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally than our competitors with less debt.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under our credit facilities will depend on market interest rates because the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures. In addition, we may take actions such as selling assets, restructuring or refinancing our debt or seeking additional equity capital although we may not be able to effect any of these actions on satisfactory terms, or at all. Our inability to obtain additional financing on terms favorable to us or our inability to service our debt could have a material adverse effect on our business, results of operations and financial condition. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our members.

We are dependent upon the cash flow generated by our operations in order to meet our debt service obligations and to allow us to make distributions to our members. The operating and financial restrictions and covenants in our ~~credit~~Credit ~~agreement~~Agreement (defined below), the indenture governing our senior notes and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our members. For example, our ~~credit~~Credit ~~agreement~~Agreement and the indenture governing our 6.50% Senior Notes restrict or limit our ability to:

•: make distributions;
•: incur additional indebtedness or guarantee other indebtedness;
•: grant liens or make certain negative pledges;
•: make certain loans or investments;
•: engage in transactions with affiliates;
•: make any material change to the nature of our business;

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•: make a disposition of assets; or
•: enter into a merger or plan to consolidate, liquidate, wind up or dissolve.

Furthermore, our ~~credit~~Credit ~~agreement~~Agreement contains covenants requiring us to maintain certain financial ratios and tests, including that we maintain a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both credit facilities. Our ability to comply with those covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we violate any of the restrictions, covenants, ratios or tests in our ~~credit~~Credit ~~agreement~~Agreement or the indenture governing our 6.50% Senior Notes, the lenders or the note holders, as the case may be, will be able to accelerate the maturity of all borrowings and demand repayment of amounts outstanding, our lenders' commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

The indenture governing our 6.50% Senior Notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, both the indenture and our ~~credit~~Credit ~~agreement~~Agreement contain covenants limiting our ability to pay distributions to unitholders. The covenants apply differently depending on our fixed charge coverage ratio (defined substantively the same in the indenture and the ~~credit~~Credit ~~agreement~~Agreement). If the fixed charge coverage ratio is greater than 1.75 to 1.0, we will be permitted to make restricted payments, including distributions to our unitholders, if the aggregate restricted payments since the date of our IPO, excluding certain types of permitted payments, are less than the sum of a number of items including, most importantly, operating surplus (defined similarly to the definition in our Operating Agreement) calculated as of the end of our preceding fiscal quarter and the aggregate net cash proceeds received by us as a capital contribution or from the issuance of equity interests, including the net proceeds received from our IPO. The indenture governing our 6.50% Senior Notes contains an additional general basket of $75.0 million not contained in our ~~credit~~Credit ~~agreement~~Agreement.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our $~~400.0~~320 Million Credit Agreement" and "Our 6.50% Senior Notes Due 2019." Any subsequent replacement of our ~~credit~~Credit ~~agreement~~Agreement, our 6.50% Senior Notes or any new indebtedness could have similar or greater restrictions.

We will be required to make capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to pay future cash distributions may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations. To fund our expansion capital expenditures, we will be required to use cash from our operations or incur borrowings or sell additional common units or other membership interests. Such uses of cash from operations will reduce cash available for distribution to our members. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our members. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional membership interests may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions to our unitholders in the future.

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uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our members. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional membership interests may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions to our unitholders in the future.

If we do not successfully complete expansion projects or make and integrate acquisitions that are accretive, our future growth may be limited.

A principal focus of our strategy is to expand our business. Our ability to grow depends on our ability to complete expansion and development projects and make acquisitions that result in an increase in cash per unit generated from operations. We may be unable to successfully complete accretive expansion or development projects or acquisitions for any of the following reasons:

•: we are unable to identify attractive expansion or development projects or acquisition candidates or we are outbid by competitors;
•: we are unable to obtain necessary regulatory and/ or government approvals;
•: we are unable to realize anticipated costs savings or successfully integrate the businesses we build or acquire;
•: we are unable to raise financing on acceptable terms;
•: we make or rely upon mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;
•: we are unable to secure adequate customer commitments to use the newly expanded or acquired facilities;
•: we are unable to hire, train or retain qualified personnel to manage and operate our business and assets;
•: we are unable to complete expansion projects on schedule and within budgeted costs;
•: we assume unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate;
•: our management's and employees' attention is diverted because of other business concerns; or
•: we experience unforeseen difficulties operating in new product areas or new geographic areas.

If any expansion or development project or acquisition eventually proves not to be accretive to our cash flow per unit, our business, financial condition and results of operations may be materially adversely affected.

Exposure to currency exchange rate fluctuations will result in fluctuations in our cash flows and operating results.

Currency exchange rate fluctuations could have an adverse effect on our results of operations. Historically, a portion of our revenue has been generated in Canadian dollars, but we incur operating and administrative expenses in both U.S. dollars and Canadian dollars and financing expenses in U.S. dollars. If the Canadian dollar weakens significantly, we would be required to convert more Canadian dollars to U.S. dollars to satisfy our obligations, which would cause our financial condition and result of operations to be adversely affected.

20 A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. In addition, because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. In addition, under U.S. GAAP, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt, capital lease obligations and asset retirement obligations are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation

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A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. In addition, because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. In addition, under U.S. GAAP, all foreign currency-denominated monetary assets and liabilities such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt, capital lease obligations and asset retirement obligations are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant non-monetary foreign currency exchange gains and losses in certain periods.

Our operations are subject to environmental and worker safety laws and regulations that may expose us to significant costs and liabilities.

Our natural gas storage activities are subject to stringent and complex federal, state, provincial and local environmental and worker safety laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct certain activities, increases in operating expenses or curtailment of certain operations to limit or prevent releases of materials from our facilities, the incurrence of capital expenditures associated with the installation of pollution control equipment, and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material.

In addition, laws and regulations to reduce emissions of greenhouse gases could affect the production or consumption of natural gas and, adversely affect the demand for our storage services and the rates we are able to charge for those services. ~~The~~In 2015, the U.S. ~~Congress~~pledged ~~and~~to ~~the~~reduce ~~EPA~~its asgreenhouse ~~well~~gases asby ~~some~~26 - 28% ~~states~~by 2025 under the recent Paris Agreement and ~~regional~~the U.S. ~~groupings~~EPA offinalized ~~states~~the ~~have~~Clean inPower ~~recent~~Plan, ~~years~~which ~~considered~~will ~~legislation~~establish ~~or regulations~~carbon topollution ~~reduce~~standards ~~emissions~~for ofpower ~~greenhouse~~plants ~~gases~~if it survives legal challenge. ~~These~~Future ~~efforts~~legislative ~~have~~and ~~included~~regulatory ~~consideration~~efforts ofcould include cap-and-trade programs, carbon taxes and greenhouse gas reporting and tracking programs. Although it is not possible at this time to predict how legislation or regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased demand for natural gas. However, if such future laws and regulations are expansive enough to restrict greenhouse gas emissions associated with the use of natural gas, they could reduce the demand for natural gas and/or result in additional compliance costs or operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. In addition, some scientists have concluded that increasing concentrations of greenhouse gas in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets and operations. See "Business—Regulation" for more information.

A change in the jurisdictional characterization of our assets by regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

AECO Hub™ in Alberta is not currently subject to rate regulation. The AER has jurisdiction to regulate the technical aspects of construction, development, and operation of storage facilities. If approved to do so by the Alberta Government, the AUC, may also set prices for natural gas stored in Alberta. It is not currently Alberta Government policy to disturb market-based prices of independent natural gas storage facilities. If, however, the AUC was authorized to regulate the rates we charge, it could materially adversely affect our business. In addition, a connected pipeline tolling structure is available to our customers at AECO Hub™, allowing them to inject and withdraw natural gas without incremental transportation costs. There has been a decision to include the previously provincially-regulated Alberta System under the jurisdiction of the Federal National Energy Board, or NEB, and it is possible that the NEB could assume federal jurisdiction over, and set rates for, connected storage

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~~Alberta. It is not currently Alberta Government policy to disturb market-based prices of independent natural gas storage~~ facilities~~. If~~, ~~however, the AUC was authorized to regulate the rates we~~ charge, it could materially adversely affect our business. In addition, a connected pipeline tolling structure is available to our customers at AECO Hub™, allowing them to inject and withdraw natural gas without incremental transportation costs. There has been a decision to include the previously provincially-regulated Alberta System under the jurisdiction of the Federal National Energy Board, or NEB, and it is possible that the NEB could assume federal jurisdiction over, and set rates for, connected storage facilities, including AECO Hub™, or invoke transportation toll design changes that negatively impact AECO Hub™.

Our Wild Goose operations are regulated by the CPUC. The CPUC has authorized us to charge our Wild Goose customers market-based rates because, as an independent storage provider, we, rather than ratepayers, bear the risk of any underutilized or discounted storage capacity. If the CPUC changes this determination, for instance as a result of a complaint, we could be limited to charging rates based on our cost of providing service plus a reasonable rate of return, which could have an adverse impact on our revenues associated with providing storage services.

Our Salt Plains operations are subject to primary regulation by the OCC and are permitted to conduct a limited amount of storage service in interstate commerce under Federal Energy Regulatory Commission, or FERC, regulations and policies that allow pipeline and storage companies to engage in interstate commerce (commonly known as NGPA section 311 services under the Natural Gas Policy Act of 1978), which services are not subject to FERC's broader jurisdiction under the Natural Gas Act. These section 311 services are provided by Salt Plains pursuant to a Statement of Operating Conditions which is on file with FERC. FERC has permitted Salt Plains to charge market-based rates for its section 311 services. Market-based rate authority allows Salt Plains to negotiate rates with individual customers based on market demand. This right to charge market-based rates may be challenged by a party filing a complaint with FERC. Our market-based rate authorization may also be re-examined if we add substantial new storage capacity through expansion or acquisition and as a result obtain market power. Any successful complaint or protest against our rates, or re-examination of those rates by FERC, could limit us to charging rates based on our cost of providing service plus a reasonable rate of return, and could have an adverse impact on our revenues associated with providing storage services. Should FERC or the OCC change their relevant policies, or should we no longer qualify for primary regulation by the OCC, our results of operations could be materially adversely affected.

Our current natural gas storage operations in the United States are generally exempt from the jurisdiction of FERC, under the Natural Gas Act of 1938, or the Natural Gas Act or, in the case of Salt Plains, are providing services under NGPA section 311. If our operations become subject to FERC regulation under the Natural Gas Act, such regulation may extend to such matters as:

•: rates, operating terms and conditions of service;
•: the types of services we may offer to our customers;
•: the expansion of our facilities;
•: creditworthiness and credit support requirements;
•: relationships among affiliated companies involved in certain aspects of the natural gas business; and
•: various other matters.

In the event that our operations become subject to FERC regulation, and should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPA Act 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for certain violations of up to $1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the Natural Gas Act and the EPA Act 2005.

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$1,000,000 per day for each violation. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the Natural Gas Act and the EPA Act 2005.

We hold title to our storage reservoirs under various types of leases and easements, and our rights thereunder generally continue only for so long as we pay rent or, in some cases, minimum royalties.

Our rights under storage easements and leases continue for so long as we conduct storage operations and pay our grantors for our use, or otherwise pay rent owing to the applicable lessor. If we were unable to operate our storage facilities for a prolonged period of time (generally one year) or did not pay the rent or minimum royalty, as applicable, to maintain such storage easements and leases in good standing, we might lose title to our natural gas storage rights underlying our storage facilities. In addition, title to some of our real property assets may have title defects which have not historically materially affected the ownership or operation of our assets. In either case, to recover our lost rights or to remove the title defects, we would be required to utilize significant time and resources. In addition, we might be required to exercise our power of condemnation to the extent available. Condemnation proceedings are adversarial proceedings, the outcomes of which are inherently difficult to predict, and the compensation we might be required to pay to the parties whose rights we condemn could be significant and could materially adversely affect our business, financial condition and results of operations.

Our risk management policies cannot eliminate all commodity price risk. In addition, any non-compliance with our risk management policies could result in significant financial losses.

While our hedging policies are designed to minimize commodity price risk, some degree of exposure to unforeseen fluctuations in market conditions remains. We have in place risk management systems that are intended to quantify and manage risks, including risks related to our hedging activities such as commodity price risk and basis risk. We monitor processes and procedures to prevent unauthorized trading and to maintain substantial balance between purchases and future sales and delivery obligations. However, these steps may not detect and prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. There is no assurance that our risk management procedures will prevent losses that would negatively affect our business, financial condition and results of operations. See "~~Management's~~Quantitative ~~Discussion~~ and ~~Analysis~~Qualitative ofDisclosures ~~Financial~~About ~~Condition and Results of~~Market ~~Operations~~Risks—Risk Management Policy and Practices."

New derivatives legislation could have an adverse impact on our ability to hedge risks associated with our business and on the cost of our hedging activities.

We use over-the-counter (OTC) derivative products to hedge commodity risks and, to a lesser extent, our currency risks. On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission ("CFTC"), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and CFTC rules also may require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user

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~~CFTC~~exception ~~Rules~~to ~~also~~the ~~may~~clearing, ~~require~~trade usexecution inand ~~connection~~margin ~~with~~requirements ~~certain~~for ~~derivatives~~swaps ~~activities~~entered to ~~comply~~hedge ~~with~~our ~~clearing~~commercial ~~and~~risks, ~~trade-execution~~the ~~requirements~~application ~~(or~~of ~~take~~such ~~steps~~requirements to ~~qualify~~other ~~for~~market anparticipants, ~~exemption~~such toas ~~such~~swap ~~requirements)~~dealers, may change the cost and availability of our derivatives. In addition, ~~the~~if ~~Dodd-Frank~~any ~~Act~~of ~~requires~~our ~~that~~swaps ~~regulators~~do ~~establish~~not ~~margin~~qualify ~~rules~~ for ~~uncleared~~the ~~swaps.~~commercial ~~Posting~~end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute derivatives to reduce risk and protect cash flows. Although we expect to qualify for the end-user exception to the clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the application of the such requirements to other market participants, such as swap dealers, may change the cost and availability of our derivatives. Other regulations also remain to be finalized, and the CFTC has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

We may enter into commercial obligations that exceed the physical capabilities of our facilities.

We enter into LTF and STF contracts and proprietary optimization transactions based on our understanding of the injection, withdrawal and working gas storage capabilities of our facilities as well as the expected usage patterns of our customers. If our understanding of the capabilities of our facilities or our expectations of the usage by customers is inaccurate we may be obligated to customers to inject, withdraw or store natural gas in manners which our facilities are not physically able to satisfy. If we are unable to satisfy our obligations to our customers we may be liable for damages, the customers could have the right to terminate their contracts with us, and our reputation and customer relationships may be damaged.

Our operations could be affected by terrorist activities and catastrophic events that could result from terrorism.

In the event that our storage facilities are subject to terrorist activities, such activities could significantly impair our operations and result in a decrease in revenues and additional costs to repair and insure our assets. The effects of, or threat of, terrorist activities could result in a significant decline in the North American economy and the decreased availability and increased cost of insurance coverage. Any of these factors could have a material adverse effect on our business, financial condition and results of operations.

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We depend on a limited number of customers for a significant portion of our revenues. The loss of any of these customers could result in a decline in our revenues.

We rely on a limited number of customers for a significant portion of our revenues. The loss of all or a portion of the revenues attributable to our key customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.

~~Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions or for other purposes.~~ 26

AnTable increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of ~~our~~Contents ~~common units to decline. Therefore, changes in interest rates may affect our ability to issue additional equity to make acquisitions or for other purposes.~~

Risks Related to Our Structure

Holdco currently controls our manager, which has sole responsibility for conducting our business and managing our operations. Our manager has delegated this responsibility to our board, all of the members of which are appointed by our manager. Our manager and its affiliates, including Holdco, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of our common unitholders.

Holdco owns and controls our manager. Our manager appoints all of the members of our board, which manages and operates us. Some of our directors and executive officers are directors or officers of our manager or its affiliates, including Holdco. Although our board has a contractual duty to manage us in a manner beneficial to us and our unitholders, our directors and officers have a fiduciary duty to manage our business in a manner beneficial to Holdco. Therefore, conflicts of interest may arise between Holdco and its affiliates, including our manager, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our board may favor our manager's own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations:

•: neither our Operating Agreement nor any other agreement requires Holdco to pursue a business strategy that favors us or our unitholders;
•: pursuant to our Operating Agreement, our manager has limited its liability and defined its and our board's duties in ways that are protective of it and the board as compared to liabilities and fiduciary duties that would be imposed upon a managing member under Delaware law in the absence of such definition. Our Operating Agreement also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under Delaware common law;
•: our board determines the amount and timing of asset purchases and sales, borrowings, issuance of additional membership interests and reserves, each of which can affect the amount of cash that is distributed to unitholders;
•: our board determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure. This determination can affect the amount of cash that is distributed to our unitholders and to the holders of the new incentive distribution rights;
•: our board determines which costs incurred by our manager and its affiliates are reimbursable by us;
•: our Operating Agreement does not restrict our manager from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;
•: our manager may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;
•: Holdco and its affiliates are not limited in their ability to compete with us;
•: our manager is allowed to take into account the interests of parties other than us, including Holdco and its affiliates, in resolving conflicts of interest with us;
•: except in limited circumstances, our manager has the power and authority to conduct our business without unitholder approval;
•: our Operating Agreement permits us to borrow funds to permit the payment of cash distributions or fund operating expenditures;

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•: our manager may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
•: our Operating Agreement permits us to distribute up to $50.0 million from capital sources, including on the incentive distribution rights, without treating such distribution as a distribution from capital;
•: our manager controls the enforcement of the obligations that it and its affiliates owe to us; and
•: our manager decides whether to retain separate counsel, accountants or others to perform services for us.

Affiliates of our manager, including Holdco and the Carlyle/Riverstone Funds and their portfolio company subsidiaries, are not limited in their ability to compete with us and are not obligated to offer us the opportunity to pursue additional assets or businesses.

Our Operating Agreement among us, Holdco and others does not prohibit affiliates of our manager, including Holdco and the Carlyle/Riverstone Funds, from owning assets or engaging in businesses that compete directly or indirectly with us. The Carlyle/Riverstone Funds and their portfolio companies may acquire, construct or dispose of additional natural gas storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. The Carlyle/Riverstone Funds and their affiliates are large, established participants in the energy industry and may have greater resources than we have, which may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition opportunities. As a result, competition from these entities could adversely impact our business, financial condition and results of operations.

Holders of our common units have limited voting rights and are not entitled to elect our manager or our directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right to elect our manager or our board on an annual or other continuing basis. Our board, including our independent directors, is chosen entirely by our manager. Unlike publicly-traded corporations, we do not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if the unitholders were dissatisfied with the performance of our manager, they have little ability to remove our manager.

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corporations. Furthermore, if the unitholders were dissatisfied with the performance of our manager, they have little ability to remove our manager.

We are a "controlled company" within the meaning of NYSE rules and, as a result, qualify for, and rely on, exemptions from some of the NYSE listing requirements with respect to independent directors.

Because Holdco controls more than 50% of the voting power for the election of our directors, we are a controlled company within the meaning of NYSE rules, which exempt controlled companies from the following corporate governance requirements:

•: the requirement that a majority of the board consist of independent directors;
•: the requirement that we have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

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•: the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer's performance in light of the goals and objectives, determination and approval of the chief executive officer's compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;
•: the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and
•: the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees' responsibilities and annual performance evaluations.

For so long as we remain a controlled company, we are not required to have a majority of independent directors or nominating, corporate governance or compensation committees. Accordingly, our unitholders may not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

Our Operating Agreement limits our manager's and directors' duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our manager or board that might otherwise constitute breaches of fiduciary duty.

Our Operating Agreement contains provisions that replace the fiduciary standards to which our manager or directors would otherwise be held by state fiduciary duty laws. The limitation and definition of these duties is permitted by the Delaware law governing limited liability companies. For example, our ~~operating~~Operating ~~agreement~~Agreement permits our manager or directors to make a number of decisions in their individual capacities, as opposed to their capacities as our manager or directors, free of fiduciary duties to us and our unitholders. This entitles our manager and/or directors to consider only the interests and factors that they desire and relieves them of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our members. Examples of decisions that our manager and/ or directors may make in their individual capacities include:

•: how to allocate business opportunities among us and its affiliates;
•: whether to exercise its call right;
•: how to exercise its voting rights with respect to the units it owns;
•: whether to exercise its registration rights;
•: whether to elect to reset target distribution levels; and
•: whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

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Even if unitholders are dissatisfied, they cannot initially remove our manager without Holdco's consent.

Unitholders have little ability to remove our manager. The vote of the holders of at least 66²/3% of all outstanding common units and Notional Subordinated Units voting together as a single class is required to remove our manager. Holdco owns 53.93% of our outstanding common units and all of our Notional Subordinated Units. Accordingly, our public unitholders are currently unable to remove our manager without Holdco's consent because Holdco owns sufficient units to be able to prevent the manager's removal.

~~Our manager, or its interest in us, may be transferred to a third party without unitholder consent.~~ 29

~~Our~~Table ~~manager may transfer its managing member interest to a third party in a merger or in a sale~~ of all or substantially all of its assets without the consent of our unitholders. Furthermore, our Operating Agreement does not restrict the ability of the owners of our manager from transferring ownership of our manager to a third party. The new owners of our manager would then be in a position to revoke the delegation to our board of the authority to conduct our business and operations or to replace our directors and officers with their own choices. This effectively permits a "change of control" of the company without unitholder vote or consent. Contents

We may issue additional membership interests without unitholder approval, which would dilute a unitholder's existing ownership interests.

Our Operating Agreement does not limit the number of additional membership interests that we may issue at any time without the approval of our unitholders. Our issuance of additional common units or other membership interests of equal or senior rank may have the following effects:

•: each unitholder's proportionate ownership interest in us will decrease;
•: the amount of cash available for distribution on each unit may decrease;
•: the ratio of taxable income to distributions may increase;
•: the relative voting strength of each previously outstanding unit may be diminished; and
•: the market price of the common units may decline.

Our manager has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our manager and its affiliates own more than 80% of the common units, our manager will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our Operating Agreement. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our manager is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our Operating Agreement that prevents our manager from issuing additional common units and exercising its call right. If our manager exercised its call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Our manager and its affiliates own approximately 53.93% of our outstanding common units.

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Our Operating Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our Operating Agreement restricts unitholders' voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our manager and its affiliates, their transferees and persons who acquired such units with the prior approval of our board, cannot vote on any matter. Our Operating Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Limited Liability Company Act, or the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units will be liable for the obligations of the transferor to make contributions to us that are known to such purchaser at the time it became a member and for unknown obligations if the liabilities could be determined from our Operating Agreement.

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The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by Holdco or other large holders.

We have 37,988,724 common units outstanding. 20,488,525 of the common units are owned by Holdco. Sales by Holdco or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we provided registration rights to Holdco. Under our Operating Agreement, our manager and its affiliates have additional registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal tax purposes, as well as our not being subject to a material amount of entity-level taxation ~~by individual states~~. If the Internal Revenue Service, or IRS, ~~treats~~were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you could be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited liability company under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, the IRS has made no determinations regarding our treatment as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders could be substantially reduced. Therefore, our treatment as a corporation would result in a reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a reduction in the value of the units.

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generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders could be substantially reduced. Therefore, our treatment as a corporation would result in a reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a reduction in the value of the units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a similar tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our common units could be negatively impacted.

Our Operating Agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to a material amount of entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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Notwithstanding our treatment for U.S. federal income tax purposes, we are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, the cash available for distribution to unitholders could be further reduced.

Most of our business operations and subsidiaries are subject to income, withholding and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional tax being imposed on us, reducing the cash available for distribution to unitholders. In addition, changes in our operations or ownership could result in higher than anticipated tax being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution. Although these taxes may be properly characterized as foreign income taxes, unitholders may not be able to credit them against their liability for U.S. federal income taxes on their share of our earnings.

Our Operating Agreement provides that the adverse impact of any such additional entity-level taxation will be borne directly or indirectly by all members.

We may become a resident of Canada and have to pay tax in Canada on our worldwide income, which could reduce our earnings, and unitholders could then become taxable in Canada in respect of their ownership of our units. Moreover, as a non-resident of Canada we may have to pay tax in Canada on our Canadian source income, which could reduce our earnings.

Under the Income Tax Act (Canada), or the Canadian Tax Act, a company that is resident in Canada is subject to tax in Canada on its worldwide income, and unitholders of a company resident in Canada may be subject to Canadian capital gains tax on a disposition of its units and to Canadian withholding tax on dividends paid in respect of such units.

Our place of residence, under Canadian law, would generally be determined based on the place where our central management and control is, in fact, exercised. It is not our current intention that our central management and control be exercised in Canada. Based on our operations, we do not believe that we are, nor do we expect to be, resident in Canada for purposes of the Canadian Tax Act, and we intend that our affairs will be conducted and operated in a manner such that we do not become a resident of Canada under the Canadian Tax Act. However, if we were or become resident in Canada, we would be or become subject under the Canadian Tax Act to Canadian income tax on our worldwide income. Further, unitholders who are non-residents of Canada may be or become subject under the Canadian Tax Act to tax in Canada on any gains realized on the disposition of our units and would be or become subject to Canadian withholding tax on dividends paid or deemed to be paid by us, subject to any relief that may be available under a tax treaty or convention.

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resident of Canada under the Canadian Tax Act. However, if we were or become resident in Canada, we would be or become subject under the Canadian Tax Act to Canadian income tax on our worldwide income. Further, unitholders who are non-residents of Canada may be or become subject under the Canadian Tax Act to tax in Canada on any gains realized on the disposition of our units and would be or become subject to Canadian withholding tax on dividends paid or deemed to be paid by us, subject to any relief that may be available under a tax treaty or convention.

The tax treatment of publicly traded partnerships, companies with multinational operations, or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, companies with multinational operations, or an investment in entities such as Niska Gas Storage Partners LLC may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, ~~the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income~~ from ~~activities related to fossil fuels be taxed as corporations beginning in 2021. From~~ time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration's proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Further, the Treasury Department and the Internal Revenue Service issued proposed Regulations interpreting the scope of the qualifying income requirement on May 5, 2015 (the "Proposed Regulations"). We believe that our operations are consistent with the current draft of the Proposed Regulations. However, the Proposed Regulations, once issued in final form, have the potential to change interpretations of the current law. 32

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Obama administration's proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

Further, on May 5, 2015, the Treasury Department and the Internal Revenue Service issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code (the "Proposed Regulations"). We do not believe the Proposed Regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If a tax authority contests the positions we take, the market for our common units may be adversely impacted and the cost of any such contest will reduce our cash available for distribution to unitholders. In addition, recently enacted U.S. legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.

The tax authorities may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with these positions. Any contest with a tax authority may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with a tax authority will be borne by our members because the costs will reduce our cash available for distribution.

Recently enacted U.S. legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our members with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to you may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Unitholders are required to pay any U.S. federal income taxes, Medicare taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

31 In response to current market conditions, we may engage in transactions to deliver and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt

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exchanges, debt repurchases, or modifications of our existing debt could result in "cancellation of indebtedness income" (also referred to as "COD income") being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because for U.S. federal income tax purposes distributions in excess of their allocable share of our net taxable income result in a decrease such unitholders' tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them for U.S. federal income tax purposes if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential of depreciation deductions and certain other items. In addition, because the amount realized includes a unitholder's share of our liabilities, unitholders may incur a tax liability on the sale of their units in excess of the amount of cash they receive.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by a tax-exempt entity, such as employee benefit plans and individual retirement accounts (known as IRAs), or a non-U.S. person raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, is unrelated business taxable income and will be taxable to them. In addition, we expect to withhold taxes from distributions to non-U.S. persons at the highest effective tax rate applicable to non-U.S. persons, and non-U.S. persons are required to file U.S. federal tax returns and pay tax on their shares of our taxable income attributable to our U.S. operations. Tax exempt entities (or those who intend to hold our units through an IRA) and non-U.S. persons should consult a tax advisor before investing in our common units.

We treat each unitholder as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of taxable income recognized by unitholders as a result of their ownership of our units. It also could affect the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to that unitholder's tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. However, such final regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

The amount of taxable income or loss allocable to each unitholder depends, in part, upon values that we periodically determine for our outstanding equity interests and our assets in order to comply with federal income tax law. The IRS may challenge our determinations of these values, which could adversely affect the value of our units.

U.S. federal income tax law requires us to periodically determine the value of our assets and to calculate the amount of taxable income or loss allocable to each partner based in part upon these values. We determine these asset values and allocations in part by reference to values that we determine for our outstanding equity interests. The IRS may challenge our valuations and related allocations. A successful IRS challenge to these valuations or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder's sale of units and could have a negative impact on the value of units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our tax partnership for U.S. federal income tax purposes.

We will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.

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treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.

Unitholders are likely subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to U.S. federal income taxes, unitholders are likely subject to state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in California, Oklahoma and Texas. Each of California and Oklahoma currently imposes a personal income tax on individuals. Many states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our storage facilities are constructed and maintained on property owned by others. Rights to use our reservoirs for natural gas storage are held pursuant to natural gas storage leases with the surface owners of the lands where the reservoirs are situated as well as mineral owner agreements and similar instruments entered into with the holders of subsurface mineral interests in such lands. Rights for the lands used for our pipelines are derived from right-of-ways, easements, leases and other similar land-use agreements.

For more information on our material properties, see "Business—Our Assets" in Item 1 of this Report.

Item 3. Legal Proceedings.

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

Our Limited Liability Company Interests

As of June 119, ~~2015~~2016 we had outstanding 37,988,724 common units, a 1.80% managing member interest and incentive distribution rights, or IDRs. The common units represent all of our limited partner interests and 98.20% of our total ownership interests excluding our IDRs. As discussed below under "Our Cash Distribution Policy—Incentive Distribution Rights," the IDRs represent the right to receive 48% of any quarterly cash distribution after our common unitholders have received the full quarterly distribution for each quarter plus any arrearages from prior quarters (of which there are currently none). Holdco currently owns approximately 53.93% of our outstanding common units and all of our IDRs.

34 Our common units, which represent limited liability company interests in us, are listed on the NYSE under the symbol "NKA." The following table sets forth for the indicated periods the high and low sales prices per unit for our common units on the NYSE:

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Three Months Ended	High		Low

March 31, 2016	$	3.75	$	3.01
December 31, 2015	$	3.47	$	2.66
September 30, 2015	$	3.72	$	3.02
June 30, 2015	$	3.99	$	1.21
March 31, 2015	$	4.62	$	1.44
December 31, 2014	$	12.91	$	2.71
September 30, 2014	$	16.10	$	12.27
June 30, 2014	$	16.43	$	12.26

~~currently~~ On ~~none).~~June 9, ~~Holdco~~2016, ~~currently~~the ~~owns~~closing ~~approximately~~market ~~53.93%~~price offor our ~~outstanding~~ common units ~~and~~was ~~all~~$4.16 ofper ~~our IDRs~~unit.

~~Our~~We ~~common~~have ~~units,~~gathered ~~which~~tax ~~represent~~information ~~limited~~from ~~liability~~our ~~company~~known ~~interests~~unitholders inand ~~us,~~from ~~are~~brokers/nominees ~~listed~~and, based on the ~~NYSE~~information ~~under~~collected, ~~the~~we ~~symbol "NKA." Our common units~~ have ~~been~~approximately ~~traded~~12,029 onbeneficial ~~the~~unitholders ~~NYSE since~~at ~~May~~March 1231, ~~2010~~2016. ~~Prior to that time, there was no public market for our common units. The following table sets forth for the indicated periods the high and low sales prices per unit for our common units on the NYSE:~~

Three Months Ended	High		Low
March 31, 2015	$	4.62	$	1.44
December 31, 2014	$	12.91	$	2.71
September 30, 2014	$	16.10	$	12.27
June 30, 2014	$	16.43	$	12.26
March 31, 2014	$	16.32	$	11.30
December 31, 2013	$	17.00	$	14.23
September 30, 2013	$	15.49	$	14.00
June 30, 2013	$	15.86	$	12.45

No cash distributions were paid during the year ended March 31, 2016. Cash distributions paid to common unitholders for the year ended March 31, 2015 were as follows:

On June 11, 2015, the closing market price for our common units was $1.40 per unit.

Record Date	Payment Date	Per Common Unit

November 12, 2014	November 20, 2014	$	0.35
August 11, 2014	August 19, 2014	$	0.35
May 19, 2014	May 27, 2014	$	0.35

WeCash ~~have~~distributions ~~gathered~~of ~~tax~~substantially ~~information~~all ~~from~~of our ~~known~~available ~~unitholders~~cash, ~~and~~generally ~~from~~defined ~~brokers/nominees~~as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, ~~based~~anticipated oncash ~~the~~expenditures ~~information~~and ~~collected,~~contingencies weare ~~have~~made ~~approximately~~as ~~16,095~~our ~~beneficial~~board ~~unitholders~~deems atappropriate. Distributions of cash paid by us to a unitholder will not result in taxable gain or income except to ~~March 31,~~the ~~2015~~extent the aggregate amount distributed exceeds the tax basis of the common units owned by the unitholder.

Cash distributions paid to common unitholders for the years ended March 31, 2015 and 2014 were as follows:

Record Date	Payment Date	Per Common Unit
November 12, 2014	November 20, 2014	$	0.35
August 11, 2014	August 19, 2014	$	0.35
May 19, 2014	May 27, 2014	$	0.35
February 10, 2014	February 18, 2014	$	0.35
November 13, 2013	November 21, 2013	$	0.35
August 12, 2013	August 15, 2013	$	0.35
May 20, 2013	May 23, 2013	$	0.35

Cash distributions of substantially all of our available cash, generally defined as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies are made as our Board deems appropriate. Distributions of cash paid by us to a unitholder will not result in taxable gain or income except to the extent the aggregate amount distributed exceeds the tax basis of the common units owned by the unitholder.

We are a publicly traded LLC and are not subject to federal income tax on our U.S.-sourced income. Instead, unitholders are required to report their allocable share of our income, gain, loss and deduction, regardless of whether we make distributions.

We are subject to withholding taxes by the Canada Revenue Agency ("CRA") for the portion of our quarterly distributions that are derived from our Canadian operations. Unitholders receive foreign tax credits equal in amount to the amount that we pay to the CRA and can apply these credits against other Canadian sourced income, to the extent that they may have any. 37

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We are subject to withholding taxes by the Canada Revenue Agency ("CRA") for the portion of our quarterly distributions that are derived from our Canadian operations. Unitholders receive foreign tax credits equal to the amount that we pay to the CRA and can apply these credits against other Canadian sourced income, to the extent that they may have any.

Holders

As of June 119, ~~2015~~2016, there were thirteen holders of record of our common units. The number of record holders does not include holders of units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Our Cash Distribution Policy

Our Operating Agreement contains a policy pursuant to which we pay regular quarterly cash distributions in an aggregate amount equal to substantially all of our cash available for distribution, after reserves for the prudent conduct of our business (including reserves for capital expenditures, operating expenditures and debt service) or for distributions to members in respect of future quarters. OnOur ~~January 28~~board ~~and~~previously ~~May 6, 2015, our Board~~ suspended the quarterly distribution to common unitholders for the third and fourth quarters of fiscal 2015, ~~respectively.~~and ~~Our~~in June ~~Board~~2015 ~~may~~the ~~continue~~Company entered into a definitive agreement to ~~consider~~be ~~whether~~acquired by Brookfield including a commitment by the Company not to make cash distributions onuntil athe ~~quarter-by-quarter~~earlier ~~basis,~~of the date of closing or termination ~~may~~of ~~determine~~the toTransaction. ~~change~~As ~~our~~a ~~distribution~~result, ~~policy~~no cash distributions were made during the year ended March 31, 2016.

Managing Member Interest

Our manager is entitled to 1.80% of all distributions that we make prior to our liquidation. Our manager has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current managing member interest if we issue additional membership interests in the future. The manager's 1.80% interest in distributions will be reduced if we issue additional membership interests in the future and our manager does not contribute a proportionate amount of capital to us to maintain its 1.80% managing member interest.

Incentive Distribution Rights

The IDRs entitle the Carlyle/Riverstone Funds to receive 48% of any quarterly cash distributions after our common unitholders have received the full minimum quarterly distribution ($0.35 per unit) for each quarter plus any arrearages from prior quarters. To date, the Company has not made any payments with respect to the IDRs.

To date, the Company has not made any payments with respect to the IDRs.

Limitations on Cash Distributions; Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly cash distributions from us., ~~Our~~and ~~distribution~~the ~~policy~~Company ~~may~~has committed under the definitive agreement to be ~~changed~~acquired atby Brookfield not to make any cash distributions until the earlier of the date of closing or the termination of the Transaction. If the Transaction is terminated ~~time~~under ~~and~~the terms of the agreement, our distribution policy is subject to other certain restrictions, including:

•: We may continue to lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business, including capital needs to maintain our storage facilities,

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~~$400.0 million~~finance ~~credit agreement or indenture, we would be prohibited from making cash distributions to unitholders notwithstanding~~ our ~~stated~~proprietary ~~cash~~optimization ~~distribution~~program ~~policy. See "Management's Discussion~~ and ~~Analysis~~fund ofthe ~~Financial~~margin ~~Condition~~requirements ~~and Results~~ of ~~Operations—Liquidity~~our ~~and~~hedging ~~Capital Resources—Our 6~~instruments.~~50%~~ ~~Senior Notes Due 2019" and "—Our $400.0 Million Credit Agreement."~~

•: Our cash distribution policy may be affected by restrictions on distributions under our Credit Agreement and by the indenture relating to our 6.50% Senior Notes as well as by restrictions in future debt agreements that we enter into. Specifically, our Credit Agreement and indenture contain financial tests and covenants, commensurate with companies of our credit quality that we must satisfy. Should we be unable to satisfy these restrictions under our Credit Agreement or indenture or if we are otherwise in default under our Credit Agreement or indenture, we would be prohibited from making cash distributions to unitholders notwithstanding our stated cash distribution policy. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our 6.50% Senior Notes Due 2019", "—Our $320 Million Revolving Credit Facilities", and "—Our $50 Million Short-term Credit Facility".
•: Our board's determination of cash available for distribution takes into account reserves for the prudent conduct of our business (including reserves for cash distributions to our members), and the establishment of (or any increase in) those reserves could result in a continued suspension of cash distributions to our unitholders.
•: Even if our cash distribution policy is not modified or revoked, we may continue to not pay distributions under our cash distribution policy and the decision to make any distribution is determined by our board.
•: Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Sales of Unregistered Securities

None.

~~Item 6. Selected Financial Data.~~ 39

The following table shows selected historical consolidated financial and operating data of Niska Gas Storage Partners LLC for each fiscal year in the five-year period ended March 31, 2015.

The historical consolidated financial data presented for each fiscal year in the five-year period ended March 31, 2015 is derived from the audited financial statements for those respective periods, and should be read together with and are qualified in their entirety by reference to, the historical audited consolidated financial statements of Niska Gas Storage Partners LLC and the accompanying notes included in Item 8.

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Item 6. Selected Financial Data.

The following table shows selected historical consolidated financial and operating data of Niska Gas Storage Partners LLC for each fiscal year in the five-year period ended March 31, 2016.

The historical consolidated financial data presented for each fiscal year in the five-year period ended March 31, 2016 is derived from the audited financial statements for those respective periods, and should be read together with and are qualified in their entirety by reference to, the historical audited consolidated financial statements of Niska Gas Storage Partners LLC and the accompanying notes included in Item 8.

Moreover, the table should be read together with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations."

	Years Ended March 31,
	2015			2014			2013			2012			2011
	2016			2015			2014			2013			2012
	(dollars in thousands, except per unit amounts)
Consolidated Statement of Earnings Data:
Revenues(1)	$	9854,~~319~~345		$	~~207~~98,~~396~~319		$	~~140~~207,~~695~~396		$	~~268~~140,~~581~~695		$	~~230~~268,~~075~~581
Depreciation and amortization		~~117~~57,~~323~~435			41117,~~286~~323			5041,~~409~~286			4650,~~132~~409			46,~~891~~132
Interest and debt expense		51,336			66,315			67,010			74,630			77,007
Interest		52,301			51,336			66,315			67,010			74,630
Earnings (loss) before income taxes		(~~382~~115,~~312~~105	)		(19382,~~213~~312	)		(6219,~~543~~213	)		(~~185~~62,~~459~~543	)		27(185,~~403~~459	)
Net earnings (loss)		(~~350~~103,~~656~~331	)		(8350,~~957~~656	)		(438,~~601~~957	)		(~~165~~43,~~772~~601	)		57(165,~~457~~772	)
Earnings (loss) per unit(2)		(92.3467	)		(09.2534	)		(0.6325	)		(20.3963	)		0(2.3139	)
Balance Sheet and Other Financial Data (at period end):
Total current assets	$	~~253~~153,~~405~~665		$	~~297~~253,~~137~~405		$	~~247~~297,~~775~~137		$	~~439~~247,~~427~~775		$	~~443~~439,~~699~~427
Total assets		1991,~~160,959~~897			1,~~539~~160,~~191~~959			1,~~524~~539,~~392~~191			1,~~803~~524,~~358~~392			21,~~061~~803,~~270~~358
Total debt(3)		~~779~~730,~~426~~673			~~706~~779,~~725~~426			~~722~~706,~~274~~725			~~807~~722,~~179~~274			~~800~~807,~~000~~179
Members' equity		~~185~~80,~~671~~639			~~554~~185,~~140~~671			~~597~~554,~~377~~140			~~690~~597,~~390~~377			~~916~~690,~~973~~390
Cash distributions declared (per unit):
Common units	$	~~1.05~~—		$	1.4005		$	1.40		$	1.40		$	01.8740
Subordinated units(6)		—			—			—			0.70			0.87
Subordinated units(4)		—			—			—			—			0.70
Operational Data: (unaudited)
Operational Data (unaudited):
Effective working gas capacity (Bcf)(4)		250.5			250.5			225.5			221.5			204.5
Effective working gas capacity (Bcf)(5)		244.9			250.5			250.5			225.5			221.5
Capacity added during the period (Bcf)		—			~~25.0~~—			425.0			174.0			1917.0
Percent of operated capacity leased to third parties(5)		68.6	%		76.1	%		74.8	%		62.4	%		71.4	%
Percent of operated capacity leased to third parties(6)		78.5	%		68.6	%		76.1	%		74.8	%		62.4	%

(1)Revenues include optimization revenues, which are presented net of cost of goods sold. (2)Earnings (loss) per unit for the years ended March 31, 2016, 2015 and 2014 were only attributable to common unitholders as a result of cancellation of the Company's subordinated units at the beginning of fiscal 2014. (3)Includes obligations under capital lease and ~~asset-based~~the ~~revolving~~ credit facilities. (4)~~Represents operated and NGPL leased capacity. Effective working gas capacity data is as at March 31 of each year. (5)Excludes NGPL leased capacity of 8.5 Bcf. (6)~~On April 2, 2013, Niska Partners completed an equity restructuring with affiliates of the Carlyle/Riverstone Funds. In the restructuring, all of the Company's 33.8 million subordinated units were cancelled. (5)Represents operated and NGPL-leased capacity. Effective working gas capacity data is as at March 31 of each year. (6)Excludes NGPL-leased capacity of 2.9 Bcf in fiscal 2016, and 8.5 Bcf in fiscal years prior.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The historical financial statements included elsewhere in this document reflect the consolidated assets, liabilities and operations of Niska Gas Storage Partners LLC ("Niska Partners" or the "~~Niska~~Company") as at March 31, ~~2015~~2016 and ~~2014~~2015, and for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013.~~ 2014. The following discussion of the historical consolidated ~~and combined~~ financial condition and results of operations should be read in conjunction with the historical financial statements and ~~accompanying~~ accompanying notes of ~~Niska~~the Company included elsewhere in this document. In addition, this discussion includes forward-looking statements that are subject to risks and uncertainties that may result in actual ~~results~~ results differing from statements we make. See "Forward-Looking Statements." Factors that could cause actual results to differ include those risks and uncertainties that are discussed in "Risk Factors."

Overview

We operate the AECO HubTM, which consists of the Countess and Suffield gas storage facilities ~~(collectively, the AECO HubTM)~~ in Alberta, Canada, and the Wild Goose and Salt Plains gas storage facilities in California and Oklahoma, respectively. WeNiska ~~market~~Partners ~~our~~markets ~~working~~ gas storage services of working gas capacity ~~and~~in weaddition ~~optimize~~to ~~our~~optimizing storage capacity with ~~our~~its own proprietary gas purchases at each of these facilities. We ~~have~~also operate a ~~total~~natural gas marketing business which is an extension of ~~approximately~~our ~~244~~propriety optimization activities in Canada. The Company has a total of 243.9 Bcf of working gas capacity among ~~our~~its facilities, including 21.9 Bcf leased from a third -party pipeline company. ~~We also operate a natural gas marketing business which is an extension of our proprietary optimization activities in Canada.~~

We earn revenues by ~~leasing~~providing natural gas storage services on a long-term firm ("LTF") contract basis for which we receive monthly reservation fees for fixed amounts of storage, providing ~~leasing~~ storage services on a short-term firm ("STF") contract basis, where a customer pays a fixed fee to inject a specified quantity of natural gas on a specified date or dates and a fixed fee to withdraw on a specified future date or dates, and optimization, where we purchase and sell gas on an economically hedged basis in order to improve facility utilization at margins that can be higher than those from third-party contracts. Proprietary optimization activities occur when the Company purchases and sells natural gas for its own account. Our revenues related to our marketing business are included in proprietary optimization activities. We have aggregated all of our activities in one reportable operating segment for financial reporting purposes. Our consolidated financial statements are prepared in accordance with GAAP.

WeIn ~~have~~June ~~aggregated~~2015, ~~all~~the Company, the Manager, Holdco and certain of ~~our~~their ~~activities~~affiliates inentered ~~one~~into ~~reportable~~a ~~operating~~definitive ~~segment~~agreement ~~for~~to ~~financial~~be ~~reporting~~acquired ~~purposes~~by Brookfield. ~~Our~~Under ~~consolidated~~the ~~financial~~terms ~~statements~~of ~~are~~the ~~prepared~~Merger Agreement, Brookfield will acquire all of the Company's outstanding common units for $4.225 per common unit in ~~accordance~~cash ~~with~~and ~~GAAP~~will acquire the Managing Member and the IDRs in the Company prior to June 14, 2017.

The ~~fiscal~~closing ~~year~~of ~~ended~~the ~~March 31,~~Transaction ~~2015~~is ~~was~~dependent ~~extremely~~on ~~difficult~~the ~~for~~satisfaction ~~Niska.~~of ~~Adjusted~~certain ~~EBITDA~~conditions ~~and~~related ~~Cash~~to ~~Available~~regulatory ~~for~~requirements, ~~Distribution~~including ~~declined~~the ~~substantially~~approval toof ~~$66.7 million~~the ~~and $14~~CPUC.1 On May ~~million~~12, ~~respectively~~2016, ~~from~~the CPUC ~~$140.0 million~~issued ~~and~~a ~~$75.0 million~~Proposed Decision, ~~respectively~~which inif ~~fiscal~~finally ~~2014.~~approved ~~Included~~will inallow the ~~fiscal~~transfer ~~2015~~of ~~amounts~~control ~~are~~of aWild ~~one-time~~Goose ~~contract~~to ~~termination~~Brookfield ~~settlement with~~and ~~our~~also ~~largest~~allow ~~customer~~the ofTransaction ~~$26.0 million~~to ~~and~~proceed ~~benefits~~to ~~from~~close ~~inventory~~in ~~write-downs~~accordance ofwith ~~$23~~the Merger Agreement.~~1 million.~~ ~~Excluding~~The ~~these~~Proposed ~~amounts,~~Decision ~~Adjusted~~can ~~EBITDA~~still ~~and~~be ~~Cash~~amended ~~Available~~prior ~~for~~to ~~Distribution~~being ~~would have~~voted ~~been~~on ~~$17.6 million~~by ~~and~~the ~~negative~~CPUC ~~$35.0 million,~~and ~~respectively.~~may ~~These~~or ~~unfavorable~~may ~~financial~~not ~~results~~be ~~resulted~~approved ~~from~~by athe ~~significant~~CPUC. ~~deterioration in market conditions which included:~~

39 The fiscal year ended March 31, 2016 reflected a continuation of difficult market conditions for Niska. Adjusted EBITDA for the year ended March 31, 2016 was $17.1 million, compared to $66.7 million in fiscal 2015 and $140.0 million in fiscal 2014. Included in the fiscal 2016 amounts are benefits of inventory write-downs of $45.2 million. Fiscal 2015 included a one-time contract termination settlement with our largest customer of $26.0 million and benefits from inventory write-downs of $23.1 million. Excluding these amounts, Adjusted EBITDA would have been negative $28.1 million for fiscal 2016 and positive $17.6 million for fiscal 2015. The unfavorable financial results in fiscal 2016 resulted from extraordinarily low seasonal spreads which substantially reduced the value of our storage

Table of Contents

~~In addition~~services, and ~~the~~reduced ~~Company~~price ~~recorded~~volatility ~~non-cash~~resulting ~~charges~~from ~~including~~increased ~~additional depreciation of $64.7 million associated with migration of cushion~~ gas atsupply ~~two~~in ~~of its Canadian-based facilities and~~ the ~~write-off~~market ofwhich, ~~the~~in ~~remainder~~turn, ofreduced ~~the~~our ~~Company's~~ability ~~recorded~~to ~~goodwill~~capture ofadditional ~~$245.6 million.~~value ~~The~~based ~~combination~~on ofchanges ~~the market events discussed above and non-cash charges resulted~~ in anatural ~~net loss~~gas ~~for the period of $350~~prices.~~7 million.~~

~~The~~In ~~financial~~addition, ~~impact~~in offiscal ~~the~~2016 ~~market~~and ~~events~~2015 ~~discussed above has significantly reduced~~ the Company's ~~available~~recorded ~~liquidity,~~non-cash ~~which~~charges ~~consists~~ of ~~cash~~additional ondepreciation ~~hand~~of ~~and availability under its~~ $~~400~~24.5 million ~~revolving~~and ~~credit agreement~~$64. ~~At March~~7 ~~31,~~million ~~2015~~respectively, ~~the~~associated ~~Company~~with migration ~~had $106.8 million~~ of ~~available~~cushion ~~liquidity,~~gas ~~compared to $279.8 million~~ at ~~March 31,~~its ~~2014~~Canadian-based facilities. The ~~significant~~ ~~reduction~~combination inof ~~liquidity~~poor ~~resulted~~market ~~from~~conditions ~~the~~and ~~negative~~non-cash ~~economic~~charges ~~factors~~resulted ~~noted~~in ~~above~~a ~~coupled~~net ~~with~~loss for the ~~Company's~~fiscal ~~financing~~2016 of ~~significant~~$103.3 million, ~~amounts~~compared to offiscal ~~inventory~~2015 ~~for~~net ~~optimization~~loss ~~and~~of ~~temporary pressure support~~$350.7 million.

AnThe ~~important credit metric for the~~ Company's isavailable ~~our~~liquidity ~~fixed~~consists ~~charge~~of ~~coverage~~amounts ~~ratio,~~available orunder ~~FCCR,~~its ~~which~~Revolving isCredit ~~contained~~Facilities ~~in the Indenture to our 6.50% Senior Notes~~ and ~~our~~its ~~$400.0 million Revolving~~Short-Term Credit ~~Agreement, or Credit~~ Facility. ~~The~~In ~~FCCR~~February 2016, ~~measured~~the onCompany acompleted ~~trailing-twelve~~an amendment ~~month~~and ~~basis,~~extension ~~measures~~of ~~our~~its ~~Adjusted~~Credit ~~EBITDA divided by fixed charges~~Agreement, ~~both of~~ which ~~are~~reduced ~~defined in~~ the ~~Indenture and~~maximum ~~Credit~~capacity ~~Facility.~~to ~~When our FCCR is below 2~~$320.0 million ~~times,~~and weextends ~~are~~the ~~restricted~~term inof ~~our~~the ~~ability~~original toagreement ~~issue~~from ~~new debt. When our FCCR is below 1.75 times~~June 29, we2016 ~~are restricted in our ability~~ to ~~pay distributions.~~ ~~When our FCCR is below 1.1~~September ~~times~~30, we2016 ~~are~~and ~~unable~~allows tofor ~~borrow the last 15% of availability under our credit facility without triggering~~ an ~~event~~additional ofterm ~~default.~~extension ~~Availability is limited~~ to anDecember 31, ~~aggregate borrowing~~2016 ~~base~~providing orthat ~~$400 million,~~the ~~whichever~~Transaction ishas ~~less~~closed. AsThe ofCompany's ~~March 31,~~fixed ~~2015,~~charge wecoverage ~~had~~ratio a ("FCCR") ofhas been below 1.~~3 to~~ 1:1.0 ~~and~~since ~~we were entitled to draw on~~ the ~~full~~first ~~capacity~~quarter of ~~the~~fiscal ~~Credit~~2016 ~~Facility.~~and Weas ~~believe that~~a itresult isthe ~~likely~~Company ~~that~~continued ~~our~~to ~~FCCR~~be ~~will~~unable ~~fall below 1.1~~ to ~~1.0~~borrow in the ~~period~~last ~~ending~~15% ~~June 30,~~of ~~2015. If this occurs, we will reduce~~ availability byunder ~~15%~~the ~~commencing~~Revolving ~~when~~Credit weFacilities ~~report~~without ~~earnings~~triggering an ~~for~~event ~~that period~~of default.

In ~~response~~connection towith ~~deteriorating~~the ~~conditions~~entry ininto the ~~natural~~Merger ~~gas~~Agreement, ~~storage~~Brookfield ~~industry,~~agreed weto ~~have~~lend ~~undertaken~~up to $50.0 million to the Company under a ~~number~~short-term ofcredit ~~steps~~facility to ~~improve~~be ~~our~~used ~~financial~~for ~~position~~working capital purposes. During fiscal 2016, ~~results~~reduced ofliquidity ~~operations~~due ~~and~~to ~~credit~~lower profitability was partially offset by the funds available under the Short-Term Credit Facility. As at March 31, 2016, the ~~metrics~~balance under the Short-term Credit Facility was $40.1 million, ~~including~~and the ~~following:~~Company had $66.8 million of total available liquidity, compared to $80.1 million at March 31, 2015.

As we begin fiscal ~~2016~~2017, market conditions for natural gas storage ~~remain~~are ~~challenging~~improving, with ~~relatively~~widening ~~narrow~~ seasonal spreads and ~~continuing~~increasing ~~muted~~ volatility. WeThe ~~are~~Company ~~unable~~estimates tothat, ~~predict~~based on expected ifrevenues, ~~and~~of ~~when~~which ~~natural~~over ~~gas~~80% ~~storage~~have ~~markets~~already ~~will~~been ~~return~~transacted toacross ~~more~~all ~~robust~~revenue ~~levels.~~strategies, ~~However~~and expected costs, wethe ~~believe~~Company ~~that~~will ~~our~~generate ~~existing~~sufficient ~~sources~~cash offlow ~~liquidity,~~to ~~which~~fund ~~include~~its ~~cash~~operations onfor ~~hand~~the next twelve months, ~~expected~~except ~~cash~~for ~~from~~the ~~operations~~repayment of the outstanding balances of the Revolving Credit Facilities and ~~availability~~ ~~under~~the ~~our~~Short-Term ~~revolving~~Credit ~~credit~~Facility ~~facility,~~on ~~even~~their ifrespective ~~restricted~~maturity todates. ~~85%~~Failure ofto repay the ~~aggregate~~Revolving Credit ~~borrowing~~Facilities ~~base,~~when ~~will~~due bewould ~~sufficient~~also toconstitute ~~fund~~an ~~our~~event ~~short-term~~of ~~liquidity~~default ~~needs~~under ~~through~~the ~~March 31,~~terms ~~2016~~of the 6.50% Senior Notes.

On June 9, 2016, the CPUC issued a decision which approved the transfer of control of the Wild Goose facility to Brookfield, effective immediately. The Company believes that it is probable that the Merger will be completed on or before July 31, 2016 at which time the Company will pursue replacement financing. Should the merger not close as anticipated, the maturity of the Revolving Credit Facilities on September 30, 2016 would require the Company to seek a further extension of the maturity date or raise additional funds to repay the amounts projected to be outstanding at that time. We can provide no assurance that we will be able to obtain a further extension of the maturity date or raise additional funds to repay our Revolving Credit Facilities and the Short-Term Credit Facility upon maturity.

See also "How We Evaluate Our Operations—Capitalization, Leverage and Liquidity" and "Liquidity and Capital Resources."

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A summary of financial and operating data for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014:

	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
	(dollars in thousands)
Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) Data:
Revenues
Fee-based revenue	$	9254,~~340~~734		$	~~135~~92,~~356~~340		$	~~163~~135,~~325~~356
Optimization, net(1)		~~5,979~~(389	)		725,~~040~~979			~~(22~~72,~~630~~040	)

		98,319			207,396			140,695
		54,345			98,319			207,396
Expenses (Income):
Operating		3929,~~230~~806			4039,~~834~~230			3240,~~535~~834
General and administrative		2629,~~833~~993			3926,~~937~~833			3839,~~562~~937
Depreciation and amortization		~~117~~57,~~323~~435			41117,~~286~~323			5041,~~409~~286
Interest		5152,~~336~~301			6651,~~315~~336			6766,~~010~~315
Loss on extinguishment of debt(2)		—			~~36,697~~—			~~599~~36,697
(Gain) loss on disposal of assets(3)		(64	)		—			14,927
Impairment of goodwill(3)		—			245,604			—
Impairment of goodwill(3)		245,604			—			—
Losses (gains) on disposals of assets		268			(64	)		—
Foreign exchange losses (gains)		380			1,182			(694	)
Foreign exchange (gains) losses		(349	)		380			1,182
Other (income) expense		(114	)		~~358~~(11	)		~~(110~~358	)

Earnings (loss) before income taxes		(~~382~~115,~~312~~105	)		(19382,~~213~~312	)		(6219,~~543~~213	)
Income tax expense (benefit):
Current		2,~~595~~536			822,595			~~(1,414~~82	)
Deferred		(3414,~~251~~310	)		(1034,~~338~~251	)		(1710,~~528~~338	)

		(31,656	)		(10,256	)		(18,942	)
		(11,774	)		(31,656	)		(10,256	)

Net earnings (loss) and comprehensive income (loss)	$	(~~350~~103,~~656~~331	)	$	(8350,~~957~~656	)	$	(438,~~601~~957	)



Reconciliation of Adjusted EBITDA to net (loss) earnings:
Net earnings (loss)	$	(~~350~~103,~~656~~331	)	$	(8350,~~957~~656	)	$	(438,~~601~~957	)
Add (deduct):
Interest expense		5152,~~336~~301			6651,~~315~~336			6766,~~010~~315
Income tax benefit		(3111,~~656~~774	)		(1031,~~256~~656	)		(1810,~~942~~256	)
Depreciation and amortization		~~117~~57,~~323~~435			41117,~~286~~323			5041,~~409~~286
Non-cash compensation expense		21,~~305~~653			—2,305			—
Impairment of goodwill		~~245,604~~—			—245,604			—
Unrealized risk management (gains) losses		(31,694	)		8,732			89,851
Unrealized risk management losses (gains)		16,566			(31,694	)		8,732
Loss on extinguishment of debt		—			~~36,697~~—			~~599~~36,697
Foreign exchange losses (gains)		380			1,182			(694	)
Foreign exchange (gains) losses		(349	)		380			1,182
(Gain) loss on disposal of assets		(64	)		—			14,927
Losses (gains) on disposals of assets		268			(64	)		—
Other (income) expense		(114	)		~~358~~(11	)		~~(110~~358	)
Inventory impairment writedowns		63,800			4,600			22,281
Write-downs of inventory		4,300			63,800			4,600

Adjusted EBITDA(4)		6617,~~667~~065			~~139~~66,~~957~~667			~~181~~139,~~730~~957
Add (deduct):
Cash interest expense, net		(4748,~~684~~225	)		(6247,~~961~~684	)		(6362,~~599~~961	)
Income taxes (paid) recovered		(50	)		(73	)		722
Income taxes paid		(1,958	)		(50	)		(73	)
Maintenance capital expenditures		(42,~~844~~926	)		(14,~~575~~844	)		(1,~~833~~575	)
Other income (expense)		114			~~(358~~11	)		~~110~~(358	)

Cash Available for Distribution(4)	$	14(36,~~100~~040	)	$	7414,~~990~~100		$	~~117~~74,~~130~~990

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	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
	(dollars in thousands)
Balance Sheet Data (at period end):
Total assets		1991,~~160,959~~897			1,~~539~~160,~~191~~959			1,~~524~~539,~~392~~191
Property, plant and equipment, net of accumulated depreciation		~~820~~772,~~467~~023			~~908~~820,~~274~~467			~~918~~908,~~061~~274
Long-term debt(5)		~~584~~583,~~587~~206			~~585~~584,~~926~~587			~~656~~585,~~015~~926
Total partners' equity		185,671			554,140			597,377
Total members' equity		80,639			185,671			554,140
Operating Data (unaudited):
Effective working gas capacity (Bcf)(6)		~~250~~244.59			250.5			~~225~~250.5
Capacity added during period (Bcf)		—			~~25.0~~—			425.0
Percent of operated capacity contracted to third parties(7)		6878.65	%		7668.16	%		7476.81	%

(1)Optimization revenue is presented net of cost of goods sold. Net optimization revenues include unrealized risk management gains/losses and write-downs of inventory. We had unrealized risk management losses of $16.6 million for the year ended March 31, 2016, unrealized risk management gains of $31.7 million for the year ended March 31, 2015, and unrealized risk management losses of $8.7 million ~~and $89.9 million~~ for the ~~years~~year ended March 31, 2014 ~~and 2013~~. We had write-downs of inventory of $634.83 million, $463.68 million and $224.36 million for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014, respectively. Excluding these non-cash items, which do not affect Adjusted EBITDA, our realized optimization revenues were $3820.15 million, $8538.41 million and $8985.54 million for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014, respectively. (2)Loss on extinguishment of debt in the year ended March 31, 2014 relates to the redemption of our 8.875% Senior Notes due 2018 in March 2014. The loss consisted of a call premium of $28.6 million along with the write-off of unamortized deferred financing costs associated with the issuance of the 8.875% Senior Notes in 2010. ~~Loss on~~ extinguishment of debt in the year ended March 31, 2013 related to the write-off of a portion of deferred financing costs associated with the amendment and restatement of our $400.0 million revolving credit facilities. (3)Goodwill impairment in the fiscal year ended March 31, 2015 relates to goodwill in two subsidiaries that was determined to be fully impaired and, therefore, an impairment charge of $245.6 million was recorded. ~~Loss on disposal of assets in the fiscal year ended March 31, 2013 relates to losses on sales of cushion from one of our~~ ~~Canadian facilities and from one of our U.S. facilities.~~ (4)Adjusted EBITDA and Cash Available for Distribution in fiscal ~~2015~~2016 include the benefits of inventory write-downs related to inventory impairments of $2345.12 million (fiscal ~~2014~~2015—$223.41 million; fiscal ~~2013~~2014—$432.14 million). Excluding these benefits, Adjusted EBITDA would have been negative $4328.61 million for fiscal ~~2015~~2016 (fiscal ~~2014~~2015—~~137~~$43.6 million; fiscal ~~2013~~2014—$~~138~~137.6 million) and Cash Available for Distribution would have been negative $981.02 million for fiscal ~~2015~~ 2016 (fiscal ~~2014~~2015—negative $729.60 million; fiscal ~~2013~~2014—$7472.06 million). (5)~~Includes~~Long-term debt includes long-term obligations under capital lease, but excludes ~~asset-based revolving~~ credit facility drawings which are recorded in current liabilities. (6)Represents operated and NGPL-leased capacity. Effective working gas capacity data is as at March 31 of each year. In April 2015, 5.6 Bcf of leased capacity from NGPL expired, bringing our total NGPL-leased capacity down to 2.9 Bcf. (7)Excludes NGPL -leased capacity of 2.9 Bcf in fiscal 2016, and 8.5 Bcf in fiscal years prior.

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The following table sets forth average volume utilized by, and revenue and fees/margins derived from LTF contracts, STF contracts and proprietary optimization transactions for each of the years in the three-year period ended March 31, ~~2015~~2016:

	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
Storage Capacity (Bcf) utilized by:
LTF Contracts		9098.71			~~109~~90.57			~~126~~109.15
STF Contracts		7591.49			7475.74			3674.17
Proprietary optimization transactions		8454.49			6684.34			6366.3

Total		~~250~~244.59			250.5			~~225~~250.5



Revenue (in thousands)
Fee-based contracts
Fee-based contracts:
LTF Contracts	$	8036,~~781~~263		$	8380,~~940~~781		$	~~108~~83,~~615~~940
STF Contracts		1118,~~559~~471			5111,~~416~~559			5451,~~710~~416

		92,340			135,356			163,325
		54,734			92,340			135,356
Optimization:
Realized proprietary optimization transactions		3820,~~085~~477			8538,~~372~~085			8985,~~525~~372
Unrealized risk management gains (losses)		31,694			(8,732	)		(89,874	)
Unrealized risk management (losses) gains		(16,566	)		31,694			(8,732	)
Inventory write-downs		(63,800	)		(4,600	)		(22,281	)
Write-downs of inventory		(4,300	)		(63,800	)		(4,600	)

		5,979			72,040			(22,630	)
		(389	)		5,979			72,040

Total	$	9854,~~319~~345		$	~~207~~98,~~396~~319		$	~~140~~207,~~695~~396



Fees/Margins ($/Mcf)
LTF Contracts(1)	$	0.8937		$	0.7789		$	0.8677
STF Contracts		0.1520			0.6915			10.5169
Realized proprietary optimization transactions		0.4537			10.2945			1.4129

(1): Excluding the one-time, early termination payment of $26.0 million from TransCanada, realized margins would have been $0.60 per Mcf in fiscal 2015.

Non-GAAP Financial Measure

Adjusted EBITDA and Cash Available for Distribution

We use the non-GAAP financial measures "Adjusted EBITDA" and "Cash Available for Distribution" in this report. A reconciliation of ~~Adjusted~~ Adjusted EBITDA and Cash Available for Distribution to net earnings (loss), ~~their~~the most directly comparable financial measure as calculated and presented in accordance with GAAP, is shown above.

We define Adjusted EBITDA as net earnings (loss) before interest, income taxes, depreciation and amortization, ~~impairment of goodwill,~~ unrealized risk management gains and losses, loss on extinguishment of debt, foreign exchange gains and losses, ~~inventory impairment~~ write-downs of inventory, gains and losses on asset dispositions, non-cash compensation ~~expense~~, asset impairments and other income. We ~~define~~believe the adjustments for other income are similar in nature to the traditional adjustments to net earnings used to calculate Adjusted EBITDA and adjustment for these items results in an appropriate representation of this financial measure. Cash Available for Distribution is defined as Adjusted EBITDA reduced by interest expense (excluding amortization of deferred financing costs), income taxes paid ~~(or recovered)~~, maintenance ~~capital~~ capital expenditures and other (income~~) expense~~. Adjusted EBITDA and Cash Available for Distribution are used as a supplemental ~~financial measure by our management and by external users of our financial statements such as commercial banks and ratings agencies, to assess:~~

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~~The GAAP measure most directly comparable to Adjusted EBITDA and Cash Available for Distribution is net earnings. The non-GAAP~~ financial measures ofby ~~Adjusted~~our ~~EBITDA~~management and ~~Cash~~by ~~Available for~~external ~~Distribution~~users should not be considered as alternatives to net earnings. Adjusted EBITDA and Cash Available for Distribution are not presentations made in accordance with GAAP and have important limitations as analytical tools. Adjusted EBITDA and Cash Available for Distribution should not be considered in isolation or as substitutes for analysis of our ~~results~~financial ~~as reported under GAAP. Because Adjusted EBITDA and Cash Available for Distribution exclude some~~statements, ~~but~~such ~~not~~as ~~all,~~commercial ~~items~~banks ~~that affect net earnings~~ and ~~are~~ratings ~~defined differently by different companies~~agencies, ~~our definition of Adjusted EBITDA and Cash Available for Distribution may not be comparable~~ to ~~similarly titled measures of other companies.~~ assess:

•: the financial performance of our assets, operations and return on capital without regard to financing methods, capital structure or historical cost basis;
•: the ability of our assets to generate cash sufficient to pay interest on our indebtedness and make distributions to our equity holders;
•: repeatable operating performance that is not distorted by non-recurring items or market volatility; and
•: the viability of acquisitions and capital expenditure projects.

The GAAP measure most directly comparable to Adjusted EBITDA and Cash Available for Distribution is net earnings. The non-GAAP financial measures of Adjusted EBITDA and Cash Available for Distribution should not be considered as alternatives to net earnings (loss). Adjusted EBITDA and Cash Available for Distribution are not presentations made in accordance with GAAP and have important limitations as analytical tools. Neither Adjusted EBITDA nor Cash Available for Distribution should be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Cash Available for Distribution exclude some, but not all, items that affect net earnings (loss) and are defined differently by different companies, our definition of Adjusted EBITDA and Cash Available for Distribution may not be comparable to similarly titled measures of other companies.

We recognize that the usefulness of Adjusted EBITDA as an evaluative tool may have certain limitations, including:

•: Adjusted EBITDA does not include interest expense. Because we have borrowed money in order to finance our operations, interest expense is a necessary element of our costs and impacts our ability to generate profits and cash flows. Therefore, any measure that excludes interest expense may have material limitations;
•: Adjusted EBITDA does not include depreciation and amortization expense. Because we use capital assets, depreciation and amortization expense is a necessary element of our costs and ability to generate profits. Therefore, any measure that excludes depreciation and amortization expense may have material limitations;
•: Adjusted EBITDA does not include provision for income taxes. Because the payment of income taxes is a necessary element of our costs, any measure that excludes income tax expense may have material limitations;
•: Adjusted EBITDA does not reflect cash expenditures or future requirements for capital expenditures or contractual commitments;
•: Adjusted EBITDA does not reflect changes in, or cash requirements for, working capital needs; and
•: Adjusted EBITDA does not allow us to analyze the effect of certain recurring and non-recurring items that materially affect our net earnings or loss.

Similarly, Cash Available for Distribution has certain limitations because it accounts for some, but not all, of the above limitations.

How We Evaluate Our Operations

We generate substantially all of our revenue through long- and short-term contracts for the storage of natural gas for third-party customers and the proprietary optimization of storage capacity that is ~~uncontracted, underutilized or available only on a short-term basis. We evaluate our business on the basis of the following key measures:~~

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uncontracted, underutilized or available only on a short-term basis. We evaluate our business on the basis of the following key measures:

•: volume and fees derived from fee-based contracts;
•: volume and margin derived from our proprietary optimization activities;
•: operating, general and administrative expenses;
•: Adjusted EBITDA;
•: capitalization and leverage; and
•: borrowing base revolver availability, liquidity, and compliance with debt covenants.

Volume and Fees Derived from Fee-based Contracts

We provide fee-based natural gas storage services to our customers under long-term firm (LTF) and short-term firm (STF) contracts. When a customer enters into a LTF contract, the customer is obligated to pay us monthly reservation fees for a fixed amount of storage which is usable by the customer at their option subject to contractual limits. These fees are fixed regardless of the actual use by the customer, and we also collect a variable fee when the services are actually used in order to allow us to recover our variable operating costs. The volume-weighted average life of our LTF contracts at March 31, ~~2015~~2016 was 32.36 years. Reservation fees comprise over 90% of the revenue generated under LTF contracts and provide a baseline of revenue into ~~excess~~support of our operating and general and administrative costs.

We also provide fee-based services under short-term firm (STF) contracts, where a customer pays a fixed fee to inject a specified quantity of gas on a specified date or dates and to withdraw on a specified future date or dates.

We monitor both the volume and price of our LTF and STF contracts in order to evaluate the effectiveness of our marketing efforts as well as the relative attractiveness of each of these types of contracts compared to each other as well as in comparison to our optimization strategy. During periods when market values for storage capacity are higher, we typically use more of our capacity under LTF contracts. The fees we are able to generate from our LTF and STF contracts reflect market conditions, including interest rates. The capacity used for STF contracts depends, among other things, on available capacity not reserved under LTF contracts as well as market demand and contract rates available for these services.

Volume and Margin Derived from Our Proprietary Optimization Activities

When market conditions warrant, we enter into economically hedged transactions with available capacity. This can achieve higher margins than can be obtained from third-party contracts. Because we economically hedge our transactions, we are able to determine in advance the minimum margins that will be realized and add incremental margins by re-hedging as market conditions change.

At times, if spreads move favorably, such as if winter gas prices fall below forward prices for the following summer, we can further increase margins that have been substantially locked in by choosing to hold inventory into a subsequent period and re-hedging the transaction. This has the result of increasing our cash flow margins and overall profitability although for accounting purposes the income is recognized in a later period, causing cyclicality in our reported revenues and profits.

When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our net realized optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. However, because substantially all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by gains when the inventory is sold. These offsetting gains and losses may occur in different periods. 47

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When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized hedging gains and losses and inventory write-downs. For accounting purposes, our realized optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. However, because substantially all inventory is economically hedged, any inventory write-downs are offset by hedging gains and any unrealized hedging losses are offset by gains when the inventory is sold. These offsetting gains and losses may occur in different periods.

Operating Expenses

Our most significant variable operating expenses are fuel and electricity costs. These operating expenses vary significantly based upon the amount of natural gas we inject or withdraw throughout the year and the price of the energy commodity at the time of purchase. Variable operating expenses are partially offset by the variable fees we collect from our LTF contracts. The fixed component of our operating expenses include salaries and labor, parts and supplies, surface and mineral lease rentals and other general operating costs. These fixed operating expenses are more stable from year to year but can fluctuate due to unforeseen repairs ~~and equipment malfunctions~~.

General and Administrative Expenses

Our general and administrative expenses primarily consist of employee compensation, legal, accounting and tax consulting fees, and our ~~office~~ ~~lease~~office leases.

Capitalization, Leverage and Liquidity

We regularly monitor our credit metrics. Our most important credit metric is our fixed charge coverage ratio, or FCCR, which is contained in the Indenture to our 6.50% Senior Notes and our ~~$400.0 million Revolving~~ Credit Agreement. The FCCR measures our Adjusted EBITDA divided by fixed charges, both of which are defined in the Indenture and ~~credit agreement~~Credit Agreement. As discussed below, when our FCCR is below 2.0 times, we are restricted in our ability to issue new debt. When our FCCR is below 1.75 times, we are restricted in our ability to pay distributions. When our FCCR is below 1.1 times, we are unable to borrow the last 15% of availability without triggering an event of default. We also monitor our ratio of long-term and total debt to Adjusted EBITDA and our ratio of debt to debt plus equity. While these metrics are not included in our Indenture or ~~credit~~Credit ~~agreement~~Agreement, they are common metrics used to measure the credit-worthiness of companies, including those similar to us.

As of March 31, ~~2015~~2016, we had a FCCR of 10.3 to 1.0, a ratio of total debt to Adjusted EBITDA of 1142.78 times, a ratio of long-term debt to Adjusted EBITDA of 834.82 times and a ratio of of long-term debt to long-term debt plus equity of 7587.9%. ~~In response to deteriorating conditions in the natural gas storage industry, we have undertaken a number of steps to improve our credit metrics, including the following:~~

Funding the purchase of proprietary optimization inventory can consume a significant portion of our available working capital. Accordingly, we closely monitor the utilization and remaining available capacity under our credit facilities and actively pursue additional short-term firm contracts when we determine it is appropriate to maintain liquidity.

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Factors that Impact Our Business

Factors that impact the performance of specific components of our business from period to period include the following:

Market Conditions for Natural Gas Storage

During the ~~year~~first ~~ended~~half ~~March 31,~~of ~~2015~~fiscal 2016, the difference between ~~winter~~summer and ~~summer~~winter prices in the natural gas futures market, referred to as the seasonal spread, remained extremely narrow ~~and low levels of volatility persisted~~. ~~These~~This ~~were~~condition the result of numerous factors, including, but not limited to: (i) low opening inventories of natural gas in storage in North America due to the high drawdown in winter of fiscal 2014, which resulted in stronger demand for gas during the injection season and tightened the seasonal spread for fiscal 2015; (ii) strong injections into storage during the summer months of fiscal 2015, due in part to material year-over-year increase in natural gas production in the United States as well as Western Canada; (iii) regional weather patterns during the fiscal 2015 winter season which provided warmer than normal weather in Western North America and resulted in lower regional demand and volatility year over year; (iv) record supply growth in the United States which came online during the winter, and (v) the development of new pipeline infrastructure connecting new supply to markets. Our market opportunities were also limited due to the existence of sufficient natural gas supply to meet Eastern demand because material inventories from the West, where the majority of our capacity is located, were not needed to balance the North American market.

These market conditions negatively impacted our fiscal 2015 revenues by reducing the seasonal spread which lowered the price we charge for long-term contracts as well as reducing the profitability of our short-term firm and optimization activities, where we make hedged natural gas purchases for our own account. As long-term contracts expire in future years, we may enter into new contracts at lower rates than the expiring contracts, and the impact on revenues could be material. If low levels of volatility and narrow seasonal spreads persist, our future revenues and profitability will be materially adversely affected. We are unable to predict the timing or magnitude of such events nor can we predict the ultimate impact they may have on our results of operations. 48

Market conditions for natural gas storage can change rapidly as a result of a number of factors, including overall storage levels across North America and in the markets we serve, current and anticipated levels of natural gas supply and demand, constraints on pipeline infrastructure capacity, and weather patterns. Accordingly, current market conditions may not be a reliable predictor of future market conditions. Long term, we believe several factors may contribute to meaningful growth in North American natural gas demand, including: (i) growth in base-load industrial demand; (ii) fuel switching for electricity generation from coal to natural gas; (iii) construction of new gas-fired power plants; (iv) growing exports of natural gas to Mexico; and (v) exports of North American Liquefied Natural Gas, or LNG, all of which could bolster the demand for, and the commercial value of, natural gas storage.

During the year ended March 31, 2015, we concluded that a number of factors, including the continued narrow seasonal spread combined with the significant reduction in natural gas price volatility, and a strong decline in our equity market capitalization were impairment indicators. We made this determination because these factors had a material negative effect on our financial performance, and we were unable to predict if and when these factors will reverse. We performed a goodwill impairment test and concluded the remaining balance of our goodwill was fully impaired, and therefore a non-cash impairment charge of $245.6 million was recorded.

Working Gas Storage Capacity

Changes in working gas capacity are expected to impact the level of our revenue. For the fiscal year ended March 31, 2015, our gas storage capacity remained unchanged from the prior year. On

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~~April 1,~~resulted ~~2015~~from numerous factors, ~~our~~including, ~~contract~~but ~~for~~not ~~5.6~~limited ~~Bcf~~to: of(i) production ~~the~~curtailments ~~8.5~~in ~~Bcf~~Alberta ~~leased~~due ~~capacity~~to prolonged compressor outages on ~~NGPL~~the ~~expired,~~TransCanada ~~thereby~~Alberta ~~reducing~~System ~~our~~and high cash prices at PG&A Citygate during injection season; (ii) lower levels of natural gas in storage ~~capacity~~which led to ~~approximately~~increased ~~244.9~~demand in the cash market; (iii) ~~Bcf.~~real Weor doperceived ~~not~~changes ~~expect~~in ~~this~~overall ~~change~~supply ~~will~~and ~~cause~~demand afundamentals; ~~significant~~(iv) the ~~reduction~~development of new pipeline infrastructure connecting new supply to ~~future~~markets; ~~earnings~~(v) the weather during the first part of winter being milder than normal; and (vi) a material year-over-year increase in natural gas production in the United States as well as in Western Canada during the winter withdrawal season. These market conditions have negatively impacted our revenues during the year ended March 31, 2016 by eroding the prices we can charge for long and short-term firm contracting services, as well as reducing the profitability of our optimization activities, where we make economically hedged natural gas purchases for our own account.

The combination of reductions in natural gas prices, collateral required to support our retail marketing operations, costs associated with the requirements for temporary reservoir pressure support and unfavorable market conditions which have prevented us from realizing additional revenues and earnings have reduced the liquidity available under our credit facilities. Continued reduction in amounts available under our credit facilities may continue to restrict our ability to pursue optimization strategies. The inability to pursue such revenue strategies may have a material adverse effect on the Company's revenues and profitability.

Market conditions for natural gas storage can change rapidly as a result of a number of factors, including weather patterns, overall storage levels across North America in the markets we serve, current and anticipated levels of natural gas supply and demand, and constraints on pipeline infrastructure capacity. Accordingly, current market conditions may not be a reliable predictor of future market conditions. Longer term, we believe several factors may contribute to meaningful growth in North American natural gas demand, including: (i) exports of North American Liquefied Natural Gas; (ii) fuel switching for power generation from coal to natural gas; (iii) construction of new gas-fired power plants; (iv) growing exports to Mexico; and (v) growth in base-load industrial demand, all of which could bolster the demand for, and the commercial value of, natural gas storage. We are unable to predict the timing or magnitude of such events nor can we predict the ultimate impact they may have on our results of operations.

Working Gas Storage Capacity

Changes in working gas capacity are expected to impact the level of our revenue. For the fiscal year ended March 31, 2016, our contract for 5.6 Bcf of the 8.5 Bcf leased capacity on NGPL expired thereby reducing our gas storage capacity to approximately 244.9 Bcf . On May 1, 2016, 1.0 Bcf of the remaining 2.9 Bcf leased capacity on NGPL expired, thereby reducing our gas storage capacity to approximately 243.9 Bcf. We do not expect these changes will cause a significant reduction to future earnings.

Carried Inventory

When winter gas prices fall below forward prices for the following summer, ~~which is referred to as a contango market,~~ we may defer the withdrawal of proprietary optimization inventory until the next fiscal year in order to reduce operating costs and add incremental margin and economic value, independent of the period in which that revenue is earned. This ~~results~~may result in the deferral of realized earnings and cash flow from one fiscal year to the next. This was evident during the ~~fiscal~~ year ended March 31, 2015, when increased gas supply in the United States resulted in a reduction in the demand for natural gas in storage and resulted in aan ~~significant~~ overall decline in near-term natural gas prices. Due to the contango position of the forward market, we deferred the withdrawal of proprietary optimization inventory until fiscal 2016. ~~Proprietary~~As a result, proprietary optimization inventory at March 31, 2015 was ~~approximately 48 Bcf. In fiscal 2014, beginning and ending proprietary optimization inventories were~~ relatively ~~low~~high ~~(approximately 27 Bcf~~ at ~~March 31, 2013 and~~ approximately 1948 ~~Bcf~~MDth, atas compared to March 31, ~~2014)~~2016 ~~as a~~proprietary ~~result~~inventory levels of ~~late-winter~~26 ~~cold~~MDth. ~~weather~~The inyear ~~March~~over ~~2013~~year ~~and~~decrease ~~extraordinarily~~in ~~cold~~proprietary ~~weather throughout the winter of 2014.~~

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optimization was driven by a reduction in capacity allocated to the strategy in the current period, offset by an increased allocation to fee-based transactions.

Cushion Migration and Pressure Support

Cushion migration occurs when hydrocarbons move to an area of the storage reservoir where effective support in cycling a facility's working gas is no longer provided. During the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014, we recorded charges to depreciation expense of $6424.75 million, $64.7 million ~~nil~~ and $~~9.5 million~~nil, respectively, related to 6.2.4 Bcf, ~~nil~~6.2 Bcf and ~~1.6~~nil Bcf of proprietary cushion estimated to have migrated at our Canadian facilities. We currently estimate that ongoing cushion migration could require an annual expenditure of approximately $64.0 million to $106.0 million to replace the cushion gas that has migrated. These estimates include assumptions about storage levels and cycling requirements which can vary significantly depending on operating conditions.

~~Our~~In addition, our storage facilities may ~~also~~ require additional natural gas to provide temporary pressure support during periods of high activity to meet cycling requirements and performance ~~demands~~ demands related to our gas in storage. These volumes fluctuate from year to year along with our cycling requirements~~, which are dependent on market conditions~~. These cycling requirements are managed through a combination of strategies which are adapted to changes in natural gas market conditions. Typically, the use of gas to provide temporary pressure support results in net revenue gains because the cost to acquire natural gas in the nearer term is lower than the price of natural gas for future delivery.

Backwardation, a condition where the price of natural gas in the near term is higher than the price for future delivery, occurred in the winter of fiscal 2014 and spring of fiscal 2015. This increased our costs to manage our cycling requirements, which include the purchase or lease of natural gas used for temporary pressure support. The cost of temporary pressure support gas was approximately $402.2 million in fiscal ~~2015,~~2016 ~~substantially~~(fiscal ~~all of which were recognized as part of inventory write-downs~~2015—$40.0 million). Over the upcoming ~~five~~four years, the expected cumulative cost of temporary pressure support gas is $6 5.5 million which relates to our commitments to lease certain volumes of natural gas to address our future temporary pressure support needs. In the event that natural gas storage market conditions become more favorable, the cost of managing our operational requirements could be reduced. However, if the conditions deteriorate, the cost of managing our operational requirements will increase.

Material Agreements

In May 2014, we entered into a new contract with TransCanada, our largest volumetric customer. This new contract replaced a previous storage agreement which provided TransCanada with approximately 40 Bcf of storage capacity at our AECO facilities and had a term that extended to 2030. Under the previous storage agreement both parties had the option to terminate at the end of defined five-year intervals, including April 1, 2015. TransCanada elected to terminate this agreement and entered into a new agreement with us which extends until 2020. The new agreement provides TransCanada with an initial storage capacity of approximately 40 Bcf which will be reduced to approximately 20 Bcf on April 1, 2017. By exercising its early termination rights, TransCanada was obligated to make an early termination payment to us of $26.0 million. This payment was recognized in long-term firm revenue in fiscal 2015. The new rate under the renegotiated contract is lower than the rate previously in effect in prior fiscal periods, resulting in a decrease to LTF revenues in fiscal 2016.

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approximately 40 Bcf of storage capacity at our AECO facilities and had a term that extended to 2030. Under the previous storage agreement both parties had the option to terminate at the end of defined five-year intervals, including April 1, 2015. TransCanada elected to terminate this agreement and entered into a new agreement with us which extends until 2020. The new agreement provides TransCanada with an initial storage capacity of approximately 40 Bcf which will be reduced to approximately 20 Bcf on April 1, 2017. By exercising its early termination rights, TransCanada was obligated to make an early termination payment to us of $26.0 million. This payment has been recognized in long-term firm revenue in fiscal 2015. The new rates under the renegotiated contract are lower than the rate in effect for the current fiscal year and are expected to reduce LTF revenues by approximately $13 million in fiscal 2016 compared to revenues recognized in fiscal 2015.

Variable Costs

The variable operating costs of our facilities are primarily comprised of ~~fuel~~ costs associated with natural gas and electricity for compressor operations. Our operating costs are affected by the amount and price of energy used to inject and withdraw natural gas from our facilities and by the number and timing of gas injections and withdrawals. For example, if we experience large injections of natural gas in the early summer (instead of a steady rate of injections throughout the summer), we would have higher costs in our first quarter and lower than expected costs in the second quarter. A mild winter could lead to less withdrawals in total, and therefore lower overall fuel and power costs because less injections would occur in filling our storage facilities. These cost variances could be partially offset by similar variances in long-term contract revenues. During the year ended March 31, 2015, operating expenses were lower than the year ended March 31, 2014, principally due to lower average fuel and electricity prices. In fiscal 2014, higher natural gas prices and strong demand during the winter led to higher cycled volumes across all facilities which increased fuel and electricity consumption.

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in the early summer (instead of a steady rate of injections throughout the summer), we would have higher costs in our first quarter and lower than expected costs in the second quarter. A mild winter could lead to less withdrawals in total, and therefore lower overall fuel and power costs because less injections would occur in filling our storage facilities. These cost variances could be partially offset by similar variances in long-term contract revenues. During the year ended March 31, 2016, operating expenses were lower than the year ended March 31, 2015, principally due to lower facility utilization, and lower average fuel and electricity prices.

Carrying Costs and Availability of Liquidity

Our cost of capital and the amount of our available working capital impacts the amount of capacity utilized for proprietary optimization as compared to STF contracts. Proprietary optimization requires us to purchase inventory, which is financed by cash on hand and our credit facilities. A higher cost of capital relative to that of our customers will generally lead to lower volume used for proprietary optimization transactions. In general, higher carrying costs for us or our customers result in lower margins for us. During the ~~2015~~2016 fiscal year, the combination of reductions in natural gas prices, margin amounts required to support our retail marketing operations, ~~costs~~unfavorable ~~associated~~market ~~with~~conditions ~~the~~and ~~requirements~~a ~~for~~reduction ~~temporary~~in our ~~reservoir~~net ~~pressure~~credit ~~support~~facility ~~and~~availability ~~unfavorable~~has ~~market conditions which~~ prevented us from realizing additional revenues and earnings ~~have reduced the liquidity available under our $400~~.~~0 million~~ ~~revolving credit facilities.~~ Continued reduction in amounts available under the ~~revolving~~ credit facilities may restrict our ability to pursue optimization strategies. The inability to pursue such revenue strategies may have a material adverse effect on our revenues and profitability.

Customer Usage Patterns

Incremental revenue opportunities in the form of STF or proprietary optimization transactions may arise for us if capacity usage by our LTF customers is underutilized or offset by other LTF customers.

Supply and Demand for Natural Gas

During the past several years, North America has experienced a dramatic increase in the supply of natural gas, principally from the development of unconventional natural gas sources, including shale gas. These increases in supply have been coupled with build-outs of natural gas pipeline capacity in certain areas of the United States, which generally have the effect of increasing deliverability of natural gas to more North American markets and dampening the price differentials for natural gas between geographic markets, including those served by us. We are unable to determine or predict the direct impact on our business from these developments. However, we believe that the market will return to a more balanced level because gas demand is expected to increase in the medium term due to (1) a forecasted increase in base load industrial demand, (2) construction of new gas fired power plants and coal to gas switching (3) increased exports to Mexico, and (4) exports of LNG.

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geographic markets, including those served by us. We are unable to determine or predict the direct impact on our business from these developments. However, we believe that the market will return to a more balanced level because gas demand is expected to increase in the medium term due to (1) a forecasted increase in base load industrial demand, (2) construction of new gas fired power plants and coal to gas switching (3) increased exports to Mexico, and (4) exports of LNG.

Changes in the Value of the Canadian Dollar versus the U.S. Dollar

Our functional currency is the U.S. dollar. We generate revenues from our Canadian operations in Canadian dollars. Cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. The majority of our hedges are transacted in U.S. dollars on the New York Mercantile Exchange (NYMEX). Our financial instruments, principally our Common Units, Senior Notes and ~~Revolving~~credit ~~Credit Facilities~~facilities, are ~~principally~~ predominantly denominated in U.S. dollars. We hedge our net exposure to the Canadian dollar by entering into currency hedges for the substantial majority of net exposure for our transactions. We do not hedge our net Canadian dollar exposure for potential future transactions, ~~because~~as the timing and amount of those transactions, which include proprietary optimization purchases and sales, are difficult to predict. During fiscal ~~2015~~ 2016, the decline in the value of the Canadian dollar did not materially impact ~~our results of operations because of our hedging strategy.~~

In the intermediate term, any declines in value of the Canadian dollar versus the U.S. dollar will reduce cash flows measured in U.S. dollars to the extent we are not able to hedge these transactions. Because of the matters discussed above, we are unable to predict the impact of any such declines should they occur. 51

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our results of operations because its impact on revenues has been offset by lower expenses and hedging gains realized during the period.

Inflation

Inflation has been relatively low in recent years and did not have a material impact on our results of operations for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014. Although the impact of inflation has been insignificant in recent years, it remains a factor in the current economy.

Segment Information

Our process for the identification of reportable segments involves examining the nature of services offered, the types of customer contracts entered into and the nature of the economic and regulatory environment. Since our inception, we have operated along functional lines in our commercial, engineering and operations teams for operations in Alberta, northern California and the U.S. midcontinent. All functional lines and facilities offer the same services: fee-based revenue and optimization. All services are delivered using reservoir storage. All facilities have the same types of customers: major companies in the energy industry, industrial, commercial, and local distribution companies and municipal energy consumers. We also have a marketing business which is an extension of our proprietary optimization activities. Proprietary optimization activities occur when we purchase, store and sell natural gas for our own account in order to utilize or optimize storage ~~capacity~~ capacity that is not contracted or available to third party customers. We measure profitability consistently along all functional lines based on revenues and earnings before interest, taxes, depreciation and amortization, and unrealized risk management gains and losses. We have aggregated our functional lines and facilities into one reportable segment as at and for the fiscal years ended March 31, ~~2015~~ 2016, ~~2014~~2015 and ~~2013~~2014.

Information pertaining to our fee-based and proprietary optimization revenues is presented in the consolidated statements of earnings (loss) and comprehensive income (loss).

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Results of Operations

Fiscal Year Ended March 31, ~~2015~~2016 Compared to Fiscal Year Ended March 31, ~~2014~~2015

•: Revenue. Revenues include fee-based revenue and optimization, net. Fee-based revenue consists of long-term contracts for storage fees that are generated when we provide storage services on a monthly basis and short-term fees associated with specified injections and withdrawals of natural gas. Optimization revenue results from the purchase of natural gas inventory and its forward sale to future periods through energy trading contracts, with our facilities being used to store the inventory between the purchase and sale of the natural gas inventory.

Details of our revenue include:

	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
	(in thousands)
Long-term contract revenue	$	8036,~~781~~263		$	8380,~~940~~781		$	~~108~~83,~~615~~940
Short-term contract revenue		1118,~~559~~471			5111,~~416~~559			5451,~~710~~416

Total fee-based revenue		9254,~~340~~734			~~135~~92,~~356~~340			~~163~~135,~~325~~356

Realized optimization, net		3820,~~085~~477			8538,~~372~~085			8985,~~524~~372
Unrealized risk management gains (losses)		31,694			(8,732	)		(89,873	)
Unrealized risk management (losses) gains		(16,566	)		31,694			(8,732	)
Write-downs of inventory		(634,~~800~~300	)		(463,~~600~~800	)		(224,~~281~~600	)

Total optimization revenue		~~5,979~~(389	)		725,~~040~~979			~~(22~~72,~~630~~040	)

Total revenue	$	9854,~~319~~345		$	~~207~~98,~~396~~319		$	~~140~~207,~~695~~396

The change in revenue was primarily attributable to the following:

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hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. The components of optimization revenues are as follows:

Realized optimization revenues include revenues from our natural gas marketing operations of $13.0 million and $9.7 million in fiscal 2015 and 2014, respectively. Revenue from the marketing business increased last year as a result of a stronger residential market in Western Canada.

	Year Ended March 31,
	2015		2014		2013
	(in thousands)
Lease costs and property taxes	$	15,521	$	13,945	$	13,627
Fuel and electricity		11,157		13,152		6,335
Salaries and benefits		5,797		7,771		7,014
Maintenance		3,790		3,033		3,176
General operating costs		2,965		2,933		2,383

Total operating expenses	$	39,230	$	40,834	$	32,535

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~~Operating~~The ~~expenses~~change in ~~fiscal~~revenue ~~2015~~was ~~decreased~~primarily byattributable ~~$1.6 million (4%) compared~~ to the ~~prior~~following: year. Fuel and electricity costs declined by $2.0 million on account of lower average facility utilization, combined with declines in fuel and electricity prices. Salaries and benefits were reduced as a result of lower incentive compensation accruals. These reductions were partially offset by higher lease costs due to leasing additional cushion to manage our temporary pressure support requirements.

•

LTF Revenues. Fiscal 2016 LTF revenues declined by $44.5 million (55%) from fiscal 2015. The decrease in revenue was primarily due to a one-time, early termination payment of $26.0 million received from TransCanada in fiscal 2015, for which there was no corresponding amounts in fiscal 2016. The remainder of the decrease in revenues largely resulted from lower contract rates that caused revenues to decline by $14.2 million, and lower customer utilization that resulted in a decrease in variable fees of $2.9 million. In addition, fluctuations in exchange rates between the Canadian and U.S. dollar decreased revenues by $3.3 million compared to last year. The declines were partially offset by higher allocated capacity of 7.4 Bcf to LTF revenues, resulting in an increase of $1.9 million. The realized margins were $0.37 per Mcf of storage capacity in fiscal 2016 compared to $0.89 per Mcf in fiscal 2015. Excluding the one-time, early termination payment of $26.0 million, realized margin would have been $0.60 per Mcf in fiscal 2015.

•

STF Revenues. STF revenues increased by $6.9 million (60%) compared to fiscal 2015. During fiscal 2016, we increased the storage capacity allocated to this revenue strategy by 16.5 Bcf. In addition, during the year ended March 31, 2014, certain transactions with lower contract rates were entered into to mitigate withdrawal risk during the winter of fiscal 2014, the effects of which continued into the first quarter of fiscal 2015. The lack of similar transactions in the year ended March 31, 2016 resulted in higher STF revenue when compared to the prior fiscal year. Realized margins were $0.20 per Mcf in fiscal 2016 compared to $0.15 per Mcf in fiscal 2015.

•

Optimization Revenues. Total optimization revenues, including realized and unrealized gains and losses, along with write-downs of proprietary optimization inventories, decreased to a loss of $0.4 million in fiscal 2016 compared to income of $6.0 million in fiscal 2015. When evaluating the performance of our optimization business, we focus on our realized optimization margins, excluding the impact of unrealized economic hedging gains and losses and inventory write-downs. For financial reporting purposes, our net optimization revenues include the impact of unrealized economic hedging gains and losses and inventory write-downs, which cause our reported revenues to fluctuate from period to period. The components of optimization revenues are as follows:

•

Realized Optimization Revenues. Net realized optimization revenues decreased by $17.6 million compared to fiscal 2015. During fiscal 2016, storage capacity allocated to this revenue strategy was reduced by 29.5 Bcf and the average realized margin for optimization activities was $0.37 per Mcf in fiscal 2016 compared to $0.45 per Mcf in fiscal 2015. The profitability realized per Mcf of optimization capacity was reduced in the current year as a result of the suppressed spread environment and a lack of market volatility of natural gas across North American markets during fiscal 2016.

	Year Ended March 31,
	2015		2014		2013
	(in thousands)
Compensation costs	$	12,624	$	26,107	$	23,130
General costs, including office and IT costs		4,433		4,123		4,448
Legal, audit and regulatory costs		9,776		9,707		10,984

Total general and administrative expenses	$	26,833	$	39,937	$	38,562

Realized optimization revenues include revenues from our natural gas marketing operations of $15.3 million and $13.0 million in fiscal 2016 and 2015, respectively. Revenue from the marketing business increased compared to last year as a result of a stronger residential market in Western Canada as well as our commercial market in Eastern Canada.

•

Unrealized Risk Management (Losses) Gains. Unrealized risk management losses for the fiscal year ended March 31, 2016 were $16.6 million compared to gains of $31.7 million in fiscal 2015. Unrealized losses in fiscal 2016 were due to decreases in the value of financial hedges resulting from decreases in the prices of forward purchase contracts of natural gas. Gains in fiscal 2015 were mainly due to increases in the value of financial hedges resulting from decreases in forward sales price of natural gas relative to our contracts. Unrealized risk management gains and losses from our natural gas marketing operations amounted to losses of $1.9 million and $0.6 million in fiscal 2016 and 2015, respectively.

General and administrative expenses decreased by $13.1 million (33%) in fiscal 2015 compared to fiscal 2014 as a result of lower incentive accruals related to short- and long-term compensation plans.

	Year ended March 31,
	2015		2014		2013
Interest on Senior Notes	$	37,374	$	56,526	$	57,136
Interest on revolving credit facilities		9,603		5,617		8,451
Amortization of deferred financing costs		3,652		3,354		3,411
Other interest		707		818		940
Capitalized interest		—		—		(2,928	)

Total interest expense	$	51,336	$	66,315	$	67,010

Interest expense for the year ended March 31, 2015 decreased by $15.0 million (23%) compared to the year ended March 31, 2014. Interest on our Senior Notes was reduced as a result of a lower interest rate and lower outstanding balances during the current fiscal year compared to the prior year. During fiscal 2015, the Senior Notes consisted of $575.0 million of 6.50% Senior Notes due in 2019. During fiscal 2014, the Senior Notes consisted of $643.8 million of 8.875% Senior Notes, which were redeemed in March 2014. These decreases were partially offset by higher interest on our revolving credit facilities due to higher utilization.

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•: Write-Down of Inventory. Natural gas prices fell during the years ended March 31, 2016 and 2015. This reduction increased the value of our economic hedges and decreased the value of the proprietary optimization inventory underlying those hedges. With the realization of hedging gains positioned in the current fiscal year and the positioning of new hedges at lower values in future periods, the estimated market value of our inventories became less than its carrying cost. Accordingly, we wrote down our proprietary inventories by $4.3 million in fiscal 2016 and $63.8 million during fiscal 2015.

•: Earnings (Loss) before Income Taxes. Loss before income taxes for the fiscal year ended March 31, 2016 was $115.1 million compared to $382.3 million in fiscal 2015. The decrease was attributable to the change in net revenue as discussed above, plus the following:
•: Operating Expenses. Operating expenses consisted of the following:

Fiscal Year Ended March 31, 2014 Compared to Fiscal Year Ended March 31, 2013

	Year Ended March 31,

	2016		2015		2014
	(in thousands)
Lease costs and property taxes	$	12,593	$	15,521	$	13,945
Fuel and electricity		5,475		11,157		13,152
Salaries and benefits		5,529		5,797		7,771
Maintenance		2,470		3,790		3,033
General operating costs		3,739		2,965		2,933

Total operating expenses	$	29,806	$	39,230	$	40,834

~~The~~Operating expenses ~~change~~for fiscal 2016 decreased by $9.4 million (24%) compared to the prior year. Reductions in ~~revenue~~operating expenses for fiscal 2016 were principally the result of lower facility utilization which reduced fuel and electricity consumption. Additionally, leased storage capacity was ~~primarily~~reduced ~~attributable~~by 5.6 Bcf at April 1, 2015, resulting in a decrease in lease costs. Maintenance costs in the prior period were higher due to heavy equipment usage during the ~~following:~~winter of fiscal 2014 resulting in significantly higher equipment repairs throughout fiscal 2015. In addition, a weaker Canadian dollar reduced expenses associated with our Canadian facilities by $1.6 million for 2016.

•: General and Administrative Expenses. General and administrative expenses consisted of the following:

	Year Ended March 31,

	2016		2015		2014
	(in thousands)
Compensation costs	$	13,501	$	12,624	$	26,107
General costs, including office and IT costs		3,757		4,433		4,123
Legal, audit and regulatory costs		12,735		9,776		9,707

Total general and administrative expenses	$	29,993	$	26,833	$	39,937

General and administrative expenses increased by $3.2 million (12%) in fiscal 2016 compared to fiscal 2015. Legal, audit and regulatory costs for fiscal 2016 included $4.5 million of expenses related to the Transaction. Excluding the costs associated with the Transaction, total general and administrative expenses for fiscal 2016 would have been $25.5 million. Compensation costs were higher in fiscal 2016 due to cost recoveries realized in fiscal 2015 as a result of the reversals of prior-year incentive compensation accruals and retention incentive plan accruals related to the Transaction. The increases in general and administrative expenses in fiscal 2016 were offset by a reduction in costs of $2.8 million resulting from the impact of a weaker Canadian dollar.

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•: Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended March 31, 2016 decreased by $59.9 million (51%) compared to the prior year. Depreciation expense for the year ended March 31, 2016 and 2015 included $24.5 million and $64.7 million, respectively, related to migration of cushion gas at our Canadian facilities for our estimated costs associated with proprietary cushion gas that no longer provides effective pressure support. After experiencing unprecedented deliverability requirements in fiscal 2014, an evaluation of facility performance, cycling capabilities, and costs associated with maintaining those capabilities was undertaken in fiscal 2015 determining that 6.2 Bcf of cushion gas had migrated and no longer provided effective cushion support. During fiscal 2016, 2.4 Bcf of cushion gas was estimated to have migrated.

~~During~~Amortization ~~fiscal~~of ~~2013,~~intangible weassets ~~wrote~~during ~~down~~fiscal ~~our~~2015 ~~proprietary~~included ~~optimization inventories by~~ $2211.37 million ~~due to a decrease in natural gas prices. The decrease in prices resulted from the unseasonably warm winter~~ of ~~2013~~amortization ~~which~~related ~~led~~ to athe ~~steepening~~termination of the ~~forward~~prior ~~curve~~storage ~~and~~agreement awith ~~repositioning~~TransCanada ofand ~~our inventory deliveries to capture incremental opportunities related to these changes in~~ the ~~natural~~establishment ~~gas~~of ~~market.~~a new contract.

•: Interest Expense. Interest expense consisted of the following:

Seasonality and Quarterly Fluctuations

	Year ended March 31,

	2016		2015		2014
Interest on Senior Notes	$	37,375	$	37,374	$	56,526
Interest on credit facilities		10,229		9,603		5,617
Amortization of deferred financing costs		4,076		3,652		3,354
Other interest		621		707		818

Total interest expense	$	52,301	$	51,336	$	66,315

~~Our~~Interest expense ~~business~~for isthe ~~highly~~year ~~seasonal.~~ended ~~In general~~March 31, ~~revenue~~2016 isincreased ~~expected~~by to$1.0 million ~~be highest during our third and fourth fiscal quarters~~ (~~October through March~~2%), ~~during~~compared ~~the~~to ~~peak of~~ the ~~natural~~year ~~gas~~ended ~~storage winter withdrawal season~~March 31, ~~when~~2015. weHigher ~~typically~~average ~~sell~~interest ~~most~~rates ofwere ~~our~~partially ~~optimization~~offset ~~inventory to serve the seasonal demand created~~ by the ~~North American~~impacts ~~residential~~of ~~market which uses natural gas to heat their homes. Revenue is typically~~ lower inaverage ~~the~~balances ~~natural~~of ~~gas~~our ~~storage~~credit ~~summer~~facilities ~~months~~compared ~~(April through October), when natural gas prices are generally lower and we shift~~ to the ~~storage~~level ~~injection~~of ~~season~~drawings ~~and~~during ~~replenish~~fiscal ~~our natural gas inventory~~2015.

•: Impairment of Goodwill. During fiscal 2015, we concluded that a number of factors, including the continued narrow seasonal spread environment, combined with the significant reduction in natural gas price volatility, and a strong decline in our market capitalization were impairment indicators. As a result of this determination, we performed an impairment test and concluded the remaining balance of our goodwill was fully impaired, and therefore an impairment charge of $245.6 million was recorded.
•: Income Tax Expense (Benefit). Income tax benefit decreased by $19.9 million compared to the year ended March 31, 2015. This change was primarily due to lower taxable losses as well as an increase in Canadian provincial income tax rate in fiscal 2016 both of which impacted certain Canadian taxable entities.

We ~~purchase~~ Fiscal ~~natural~~Year ~~gas~~Ended ~~and build inventories in the summer months. We position sales in the winter months~~March 31, ~~which~~2015 ~~results~~Compared into ~~the~~Fiscal ~~peak~~Year ~~borrowing~~Ended ~~on our revolving credit facilities being highest in the middle of our third fiscal quarter~~March 31, ~~while our peak accounts receivable collections typically occur in~~ 2014

The change in revenue was primarily attributable to the following:

•: LTF Revenues. Fiscal 2015 LTF revenues declined by $3.2 million (4%) from fiscal 2014. The decrease in revenues resulted from lower fees realized, as well as lower storage capacity allocated to our LTF strategy. During fiscal 2015, lower rates caused revenues to decline by $14.9 million, and allocated capacity being lower by 18.8 Bcf contributed to a decrease of $12.0 million compared to fiscal 2014. In addition, fluctuations in exchange rates between the Canadian and U.S. dollar decreased revenues by $2.3 million compared to fiscal 2014. These were partially offset by a one-time, early termination payment of $26.0 million received from TransCanada. Realized margins were $0.89 per Mcf of storage capacity in fiscal 2015 compared

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~~our~~to ~~fourth fiscal quarter~~$0.77 Inper ~~addition,~~Mcf ~~LTF~~in ~~revenue during the first quarter of~~ fiscal ~~2015~~2014. ~~included~~Excluding athe one-time, ~~contract~~early termination payment of $26.0 million, ~~for~~realized ~~termination~~margin ofwould ~~the~~have ~~prior storage~~been ~~service~~$0.60 ~~agreement~~per ~~with~~Mcf ~~TransCanada.~~in fiscal 2015.

•

STF Revenues. STF revenues decreased by $39.9 million (78%) compared to fiscal 2014. During fiscal 2015, STF rates were negatively affected by a suppressed spread environment. To a lesser degree, STF revenue was also impacted by certain transactions with lower contract rates that were entered into during the fourth quarter of fiscal 2014 to mitigate withdrawal risk. The effect of these contracts, which continued into the first quarter of fiscal 2015, resulted in lower STF revenue when compared to fiscal 2014. During fiscal 2015, the amount of capacity utilized for STF contracts increased by 0.7 Bcf. Realized margins were $0.15 per Mcf in fiscal 2015 compared to $0.69 per Mcf in fiscal 2014.

•

•: Realized Optimization Revenues. Net realized optimization revenues decreased by $47.3 million compared to fiscal 2014. The average realized margin for optimization activities was $0.45 per Mcf in fiscal 2015 compared to $1.29 per Mcf in fiscal 2014. The profitability of realized optimization was reduced in fiscal 2015 as a result of the suppressed spread environment and a lack of market volatility. Gains during the fiscal 2014 were driven by higher levels of volatility in North American natural gas markets, which resulted from changes in pipeline pricing in our Canadian markets during the summer and autumn of 2013. In addition, cold winter weather significantly increased demand for natural gas across North American markets in the latter part of 2013 and the first three months of 2014, which created significant opportunities.

~~The~~Realized ~~following~~optimization ~~table~~revenues ~~illustrates~~include ~~the~~revenues ~~differences~~from our natural gas marketing operations of $13.0 million and $9.7 million in fiscal 2015 and 2014, respectively. Revenue from the marketing ~~recognition~~business increased as a result of ~~revenue~~a ~~associated~~stronger ~~with~~residential ~~our~~market ~~revenue~~in ~~strategies.~~Western Canada.
•: Unrealized Risk Management Gains (Losses). Unrealized risk management gains for the fiscal year ended March 31, 2015 were $31.7 million compared to losses of $8.7 million in fiscal 2014. Unrealized gains in fiscal 2015 were due to increases in the value of financial hedges resulting from decreases in forward sales price of natural gas relative to our contracts. Losses in fiscal 2014 were due to prices rising after financial hedges were transacted in prior periods. Unrealized risk management gains and losses from our natural gas marketing operations amounted to a loss of $0.6 million and a gain of $0.8 million in fiscal 2015 and 2014, respectively.
•: Write-Down of Inventory. Natural gas prices fell during the year ended March 31, 2015. This reduction increased the value of our economic hedges and decreased the value of the proprietary optimization inventory underlying those hedges. With the realization of hedging gains positioned in fiscal 2015 and the positioning of new hedges at lower values in the then future periods, the estimated market value of our inventories became less than its carrying cost. Accordingly, we wrote down our proprietary inventories by $63.8 million during fiscal 2015.

•

Earnings (Loss) before Income Taxes. Loss before income taxes for the fiscal year ended March 31, 2015 was $382.3 million compared to a loss before income taxes of $19.2 million in

	Year Ended March 31, 2015
	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue	$	40,482		$	14,101		$	13,373		$	12,825		$	80,781
STF revenue		2,272			1,532			2,255			5,500			11,559

		42,754			15,633			15,628			18,325			92,340
Realized optimization:
Realized optimization, net		13,774			4,458			7,013			12,840			38,085

Total realized revenue		56,528			20,091			22,641			31,165			130,425
Realized quarterly revenue as a percentage of total realized annual revenue		43.3	%		15.4	%		17.4	%		23.9	%		100.0	%

	Year Ended March 31, 2014
	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue	$	20,596		$	20,287		$	21,278		$	21,779		$	83,940
STF revenue		10,875			12,910			9,206			18,425			51,416

		31,471			33,197			30,484			40,204			135,356
Realized optimization:
Realized optimization, net		5,600			17,298			24,296			38,178			85,372

Total realized revenue		37,071			50,495			54,780			78,382			220,728
Realized quarterly revenue as a percentage of total realized annual revenue		16.8	%		22.9	%		24.8	%		35.5	%		100.0	%

Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities as discussed below under Operating Activities and borrowings under our senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (the "revolving credit facilities" or the "credit agreement"). We depend on the revolving credit facilities to provide liquidity when our cash from operations is insufficient to fund our proprietary inventory purchases. Borrowings under the revolving credit facilities are limited by a borrowing base. The credit agreement provides that we may borrow only up to the lesser of the level of our then current borrowing base and our committed maximum borrowing capacity, which is currently $400.0 million. Our borrowing base was $271.4 million as of June 1, 2015.

Our primary short-term liquidity needs are to make interest and principal payments under our credit agreement and our 6.50% Senior Notes, to fund our operating expenses and maintenance capital, and to pay for the acquisition of proprietary optimization inventory along with associated margin requirements. We fund these expenditures through a combination of cash on hand, cash from operations and borrowings under our credit agreement.

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~~During~~ fiscal ~~2015, the combination of reductions in natural gas prices and associated margin amounts required to support our retail marketing operations, costs~~ associated with our requirements for temporary reservoir pressure support and unfavourable market conditions which prevented the Company from realizing additional profit have reduced the liquidity available under the $400.0 million revolving credit facilities from $236.1 million at March 31, 2014 ~~to $80~~.~~2 million~~ atThe ~~March 31,~~increase 2015. In addition, the Company's aggregate borrowing base, which can be greater than the maximum borrowing amount of $400.0 million decreased from $396.4 million at March 31, 2014 to $294.4 million at March 31, 2015. Continued reduction in ~~amounts~~loss ~~available~~before ~~under~~income ~~the~~taxes ~~Company's~~was ~~revolving~~primarily ~~credit~~attributable ~~facilities may restrict the Company's ability~~ to ~~pursue~~lower ~~its~~net ~~optimization strategies. The inability of the Company to pursue such~~ revenue ~~strategies~~as ~~may~~discussed ~~have~~above, aplus ~~material adverse effect on~~ the ~~Company's~~following: ~~revenues and profitability.~~

•: Operating Expenses. Operating expenses in fiscal 2015 decreased by $1.6 million (4%) compared to the prior year. Fuel and electricity costs declined by $2.0 million on account of lower average facility utilization, combined with declines in fuel and electricity prices. Salaries and benefits were reduced as a result of lower incentive compensation accruals. These reductions were partially offset by higher lease costs due to leasing additional cushion to manage our temporary pressure support requirements.
•: General and Administrative Expenses. General and administrative expenses decreased by $13.1 million (33%) in fiscal 2015 compared to fiscal 2014 as a result of lower incentive accruals related to short-and long-term compensation plans.
•: Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended March 31, 2015 increased by $76.0 million (184%) compared to the prior year. The increase reflected provisions for cushion migration totaling $64.7 million related to 6.2 Bcf of proprietary cushion estimated to have migrated at our facilities, and a provision of $11.7 million for amortization of intangible assets related to the termination of a contract with TransCanada.
•: Interest Expense. Interest expense for the year ended March 31, 2015 decreased by $15.0 million (23%) compared to the year ended March 31, 2014. Interest on our Senior Notes was reduced as a result of a lower interest rate and lower outstanding balances. During fiscal 2015, the Senior Notes consisted of $575.0 million of 6.50% Senior Notes due in 2019. During fiscal 2014, the Senior Notes consisted of $643.8 million of 8.875% Senior Notes, which were redeemed in March 2014. These decreases were partially offset by higher interest on our revolving credit facilities due to higher utilization.
•: Impairment of Goodwill. During fiscal 2015, we concluded that a number of factors, including the continued narrow seasonal spread environment, combined with the significant reduction in natural gas price volatility, and a strong decline in our market capitalization were impairment indicators. As a result of this determination, we performed an impairment test and concluded the remaining balance of our goodwill was fully impaired, and therefore an impairment charge of $245.6 million was recorded.
•: Income Tax Expense (Benefit). The income tax benefit in the current year is primarily due to the tax planning strategies undertaken in connection with certain taxable Canadian entities and the recognition of losses in those entities.

~~The~~ ~~credit agreement contains customary covenants, including a covenant that requires the maintenance of a fixed charge coverage ratio ("FCCR") of 1.1 to 1.0 at the end of each fiscal~~ ~~quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities. Thus, when the Company's FCCR~~ ~~is below 1.1 to 1.0, the Company will be unable to borrow the last 15% of availability under the revolving credit facilities without triggering an event of default. Our FCCR is calculated quarterly on~~ ~~a trailing-twelve months basis by dividing Adjusted EBITDA (defined substantially the same as presented herein) by fixed charges, which are measured as interest expense plus the amount of interest~~ ~~capitalized, but giving pro forma credit for all the previous twelve months for certain debt purchases and acquisitions. As of March 31, 2015, the Company's FCCR was 1.3 to 1.0. The Company's~~ ~~FCCR is impacted by a number of factors, the most important of which are realized revenues, operating costs and expenses and~~ ~~maintenance~~Seasonality ~~capital expenditures. These factors, particularly the amount~~ and ~~timing~~Quarterly of realized revenues, can be difficult to accurately forecast. These factors, or a combination of these factors, may cause the FCCR to fall below 1.1 to 1.0, which would prevent the Company from using the last 15% availability under both revolving credit facilities. The reduction in revolving credit availability could negatively impact our liquidity and our ability to fund operations. We expect that the Company's fixed charge coverage ratio will likely fall below 1.1 to 1.0 in the quarter ending June 30, 2015, which would result in the last 15% of the Company's borrowing base becoming unavailable for borrowing. The Company is pursuing strategies, which include reductions in operating and general and administrative costs as well as management of the components of the borrowing base, which should assist the Company in maintaining adequate liquidity despite this covenant provision. Fluctuations

Our ~~medium-to-long-term~~ ~~liquidity~~business ~~needs~~is ~~primarily~~highly ~~relate~~seasonal. toIn ~~the~~general, ~~funding~~revenue ofis ~~proprietary~~expected ~~optimization~~to ~~inventories,~~be ~~organic~~highest ~~growth~~during ~~opportunities~~our third and, ~~potentially,~~fourth ~~asset~~fiscal ~~acquisitions.~~quarters We(October ~~expect~~through toMarch), ~~finance~~during the ~~cost~~peak of ~~any~~the ~~significant~~natural ~~expansion~~gas ~~projects~~storage orwinter ~~acquisitions~~withdrawal ~~from~~season, ~~borrowings~~when ~~under~~we ~~our~~typically ~~existing~~sell ormost ~~possible~~of ~~future~~our ~~credit~~optimization ~~facilities~~inventory orto aserve ~~mix~~the ofseasonal ~~borrowings~~demand ~~and~~created ~~additional~~by ~~equity~~the North ~~offerings,~~American asresidential ~~well~~market aswhich ~~cash~~uses onnatural ~~hand~~gas ~~and~~to ~~cash~~heat ~~from~~their ~~operations~~homes. AsRevenue ofis ~~March 31,~~typically ~~2015,~~lower wein ~~deferred~~ the ~~development~~natural ofgas ~~Starks in Southwest Louisiana as a hydrocarbon liquids~~ storage ~~facility~~summer ~~and Sundance~~months in(April ~~Western~~through ~~Alberta~~October), aswhen a natural gas ~~storage~~prices ~~project~~are generally ~~due~~lower toand ~~unfavorable~~we ~~market~~shift ~~conditions,~~to ~~therefore,~~ the ~~amount~~storage ~~and~~injection ~~timing~~season ofand ~~any~~replenish ~~capital~~our ~~requirements~~natural ~~are~~gas ~~uncertain~~inventory.

~~Our~~We ~~credit~~purchase ~~agreement~~natural ~~has~~gas aand ~~maturity~~build ~~date~~inventories ofin ~~June 29,~~the ~~2016~~summer months. ~~Borrowing~~We ~~costs~~position sales in the winter months, which results in the peak borrowing under ~~this~~our ~~agreement~~$320 million ~~are~~Credit Agreement ~~based~~being ~~off~~highest in the middle of aour ~~pricing~~third ~~grid~~fiscal ~~which~~quarter, ~~relates~~while toour ~~certain~~peak ~~leverage~~accounts ~~levels~~receivable tocollections typically occur in our fourth fiscal quarter. During fiscal 2016, we experienced an ~~determine~~unusual ~~interest~~storage ~~rates~~season when we recognized revenue more evenly throughout the year.

On January 28 and May 6, 2015, our Board of Directors suspended the quarterly distribution to common unitholders for the fiscal third quarter and fiscal fourth quarter, respectively, in order to conserve cash and preserve liquidity. It is uncertain when market conditions will improve to a point that reinstatement of the distribution would be appropriate.

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WeThe ~~believe~~following ~~that~~table ~~our~~illustrates ~~existing~~the ~~sources~~differences ofin ~~liquidity~~the ~~described~~recognition ~~above,~~of ~~together~~revenue associated with our ~~efforts~~revenue ~~to reduce costs and conserve cash, will be sufficient to fund our short-term liquidity needs through March 31, 2016~~strategies.

Historical Cash Flows

	Year Ended March 31, 2016

	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue	$	9,645		$	8,928		$	8,754		$	8,936		$	36,263
STF revenue		4,617			3,724			4,473			5,657			18,471

		14,262			12,652			13,227			14,593			54,734
Realized optimization:
Realized optimization, net		5,314			5,065			6,686			3,412			20,477

Total realized revenue		19,576			17,717			19,913			18,005			75,211
Realized quarterly revenue as a percentage of total realized annual revenue		26.0	%		23.6	%		26.5	%		23.9	%		100.0	%

In addition to the underlying profitability of our business, our cash flows are significantly influenced by our level of natural gas inventory, margin deposits and related forward purchase and sale contracts or hedging positions at the end of each accounting period and may fluctuate significantly from period to period. In addition, our period-to-period cash flows are heavily influenced by the seasonality of our proprietary optimization activities. For example, we generally purchase significant quantities of natural gas during the summer months and sell natural gas during the winter months. The storage of natural gas for our own account can have a material impact on our cash flows from operating activities for the period we pay for and store the natural gas and the subsequent period in which we receive proceeds from the sale of natural gas. When we purchase and store natural gas for our own account, we use cash to pay for the natural gas and record the gas as inventory and thereby reduce our cash flows from operating activities. We typically borrow on our revolving credit facilities to fund these purchases, and these borrowings increase our cash flows from financing activities. Conversely, when we collect the proceeds from the sale of natural gas that we purchased and stored for our own account, the impact on our cash flows from operating activities is positive and the impact on our cash flows from financing activities is negative. Therefore, our cash flows from operating activities fluctuate significantly from period-to-period as we purchase natural gas, store it, and then sell it in a later period. In addition, we have margin requirements on our economically hedged positions. As the cash deposits we make to satisfy our margin requirements increase and decrease with our volume of derivative positions and changes in commodity prices, our cash flows from operating activities may fluctuate significantly from period to period.

	Year Ended March 31, 2015

	Qtr 1			Qtr 2			Qtr 3			Qtr 4			Total
	(in thousands)
Fee-based revenue:
LTF revenue(1)	$	40,482		$	14,101		$	13,373		$	12,825		$	80,781
STF revenue		2,272			1,532			2,255			5,500			11,559

		42,754			15,633			15,628			18,325			92,340
Realized optimization:
Realized optimization, net		13,774			4,458			7,013			12,840			38,085

Total realized revenue		56,528			20,091			22,641			31,165			130,425
Realized quarterly revenue as a percentage of total realized annual revenue		43.3	%		15.4	%		17.4	%		23.9	%		100.0	%

(1): LTF revenue during the first quarter of 2015 includes a one-time early termination payment of $26.0 million from TransCanada due to the termination of the previous storage agreement with TransCanada.

Liquidity and Capital Resources

The Company's available liquidity consists of amounts available under its Revolving Credit Facilities and its Short-Term Credit Facility. In February 2016, the Company completed an amendment and extension of its Credit Agreement, which reduced the maximum capacity to $320.0 million and extends the term of the original agreement from June 29, 2016 to September 30, 2016, and allows for an additional term extension to December 31, 2016 provided that the Transaction has closed. However, the Company's FCCR has been below 1.1:1.0 since the first quarter of fiscal 2016 and, as a result, the Company has been unable to utilize the last 15% of availability under the Revolving Credit Facilities without triggering an event of default.

In connection with the entry into the Merger Agreement, Brookfield agreed to lend up to $50.0 million to the Company under a short-term credit facility to be used for working capital purposes. During fiscal 2016, reduced liquidity resulting from lower profitability, and the absence of the last 15% of availability under the Revolving Credit Facilities was partially offset by the funds available under the Short-Term Credit Facility from Brookfield, as well as the liquidation of optimization inventories, and the return of a portion of posted margin deposits associated with the Company's marketing business.

As at March 31, 2016, available liquidity totaled $66.8 million, consisting of $56.9 million available under the Revolving Credit Facilities and $9.9 million available under the Short-Term Credit Facility

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~~The~~from ~~following~~Brookfield. ~~table~~At ~~summarizes~~June ~~our~~6, ~~sources~~2016, ~~and~~available ~~uses~~liquidity was $89.2 million, consisting of ~~cash~~$79.3 ~~for~~million available under the ~~fiscal~~Revolving ~~years~~Credit ~~ended~~Facilities ~~March 31,~~and ~~2015,~~$9.9 ~~2014~~million ~~and~~available ~~2013:~~under the Short-Term Credit Facility from Brookfield.

	Year Ended March 31,
	2015			2014			2013
	(in thousands)
Operating Activities
Net earnings (loss)	$	(350,656	)	$	(8,957	)	$	(43,601	)
Adjustments to reconcile net earnings to net cash (used in) provided by operating activities:
Unrealized foreign exchange loss (gains)		372			1,500			(252	)
Deferred income tax benefit		(34,251	)		(10,338	)		(17,528	)
Unrealized risk management (gains) losses		(31,694	)		8,732			89,851
Depreciation and amortization		117,323			41,286			50,409
Amortization of deferred financing costs		3,652			3,354			3,411
Loss on extinguishment of debt		—			36,697			599
(Gain) loss on disposal of assets		(64	)		—			14,927
Impairment of goodwill		245,604			—			—
Non-cash compensation expense		2,305			—			—
Write-downs of inventory		63,800			4,600			22,281
Changes in non-cash working capital		(55,835	)		15,033			42,033

Net cash (used in) provided by operating activities	$	(39,444	)	$	91,907		$	162,130



Net cash used in investing activities	$	(7,573	)	$	(5,166	)	$	(27,805	)



Net cash provided by (used in) financing activities	$	51,726		$	(89,244	)	$	(136,829	)



Other information:
Proprietary inventory (at year-end)	$	136,295		$	75,140		$	83,416

As we begin fiscal 2017, market conditions for natural gas storage are improving, with widening seasonal spreads. The Company estimates that, based on expected revenues, of which over 80% have already been transacted across all revenue strategies, and expected costs, the Company will generate sufficient cash flow to fund its operations for the next twelve months, except for the repayment of the outstanding balances of the Revolving Credit facilities and the Short-Term Credit Facility on their respective maturity dates. Failure to repay the Revolving Credit Facilities when due would also constitute an event of default under the terms of the 6.50% Senior Notes.

~~Operating~~ On June 9, ~~Activities. The~~2016, ~~variability~~the inCPUC ~~net~~issued ~~cash~~a ~~provided~~decision bywhich ~~operating~~approved ~~activities~~the istransfer ~~primarily~~of ~~due~~control of the Wild Goose facility to ~~(1) changes~~Brookfield, ineffective ~~market conditions~~immediately. The Company believes that it is ~~exist~~probable ~~during~~that ~~any~~the ~~given~~Merger ~~fiscal~~will ~~period~~be completed on or before July 31, 2016 at which ~~impacts~~time the ~~margins~~Company ~~earned~~will ~~under~~pursue ~~each~~replacement offinancing. ~~our~~Should ~~fee-based~~the ~~and~~merger ~~optimization~~not ~~activities;~~close ~~and~~as ~~(2) market~~anticipated, ~~conditions at~~ the ~~end~~maturity of the ~~any~~Revolving ~~given~~Credit ~~fiscal~~Facilities ~~period~~on September 30, ~~which~~ ~~impacts~~2016 ~~our~~would ~~decision~~require the Company to ~~sell~~seek ~~significant~~a ~~volumes~~further extension of ~~inventory~~the ormaturity ~~hold~~date ~~them~~or ~~over~~raise aadditional ~~fiscal~~funds ~~period~~to ~~end.~~repay ~~When~~the weamounts ~~purchase~~projected ~~and~~to ~~store~~be outstanding ~~natural~~at ~~gas,~~that wetime. ~~borrow~~We ~~under~~can ~~our~~provide ~~credit~~no ~~facilities~~assurance tothat ~~pay~~we ~~for~~will ~~it, which~~be ~~negatively~~able ~~impacts~~to ~~operating~~further ~~cash~~extend ~~flow.~~the ~~Cash~~maturity ~~flow~~date ~~from~~or ~~operating~~raise ~~activities~~additional ~~increases~~funds ~~when~~to werepay ~~collect~~our ~~the~~Revolving ~~cash~~Credit ~~from~~Facilities and the ~~sale~~Short-Term Credit ofFacility ~~inventories~~upon maturity.

~~Cash~~See ~~used~~also in"How ~~operating~~We ~~activities~~Evaluate ~~during~~Our ~~the year ended March 31~~Operations—Capitalization, ~~2015~~Leverage was $39.4 million compared to cash provided by operating activities of $91.9 million in the year ended March 31, 2014. The reduction in cash provided by operating activities was principally related to lower profitability and higher margining requirements associated with our retail business, combined with our decision to hold proprietary inventories over the end of fiscal 2015 in order to sell them in the next fiscal periodLiquidity." Cash flows from operating activities were materially impacted by the purchase of natural gas for our retail entities in a falling market as well as holding inventories in a contango market, where the price of natural gas for future deliveries is higher than the current price.

Historical Cash Flows

In addition to the underlying profitability of our business, our cash flows are significantly influenced by our level of natural gas inventory, margin deposits and related forward purchase and sale contracts or hedging positions at the end of each accounting period and may fluctuate significantly from period to period. In addition, our period-to-period cash flows are heavily influenced by the seasonality of our proprietary optimization activities. For example, we generally purchase significant quantities of natural gas during the summer months and sell natural gas during the winter months. The storage of natural gas for our own account can have a material impact on our cash flows from operating activities for the period we pay for and store the natural gas and the subsequent period in which we receive proceeds from the sale of natural gas. When we purchase and store natural gas for our own account, we use cash to pay for the natural gas and record the gas as inventory and thereby reduce our cash flows from operating activities. We typically borrow on our Revolving Credit Facilities to fund these purchases, and these borrowings increase our cash flows from financing activities. Conversely, when we collect the proceeds from the sale of natural gas that we purchased and stored for our own account, the impact on our cash flows from operating activities is positive and the impact on our cash flows from financing activities is negative. Therefore, our cash flows from operating activities fluctuate significantly from period-to-period as we purchase natural gas, store it, and then sell it in a later period. In addition, we have margin requirements on our economically hedged positions. As the cash deposits we make to satisfy our margin requirements increase and decrease with our volume of derivative positions and changes in commodity prices, our cash flows from operating activities may fluctuate significantly from period to period.

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~~During~~The ~~fiscal~~following ~~2014,~~table ~~colder~~summarizes ~~than~~our ~~average~~sources ~~winter temperatures over much of North America resulted in increased heating demands~~ and ~~high~~uses ~~withdrawals~~ of ~~natural~~cash ~~gas~~for ~~from~~the ~~Niska's~~fiscal ~~storage facilities.~~years ~~This~~ended ~~resulted in low levels of inventories as of~~ March 31, ~~2014~~2016, 2015 and ~~increased~~2014: ~~cash flow.~~

	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
	(in thousands)
Changes in non-cash working capital:
Operating Activities
Margin deposits	$	19,342		$	(14,137	)	$	(39,174	)
Net earnings (loss)	$	(103,331	)	$	(350,656	)	$	(8,957	)
Trade receivables		3,114			(3,383	)		(286	)
Adjustments to reconcile net earnings to net cash provided by (used in) operating activities:
Accrued receivables		110,484			(44,459	)		(40,203	)
Unrealized foreign exchange (gains) losses		(206	)		372			1,500
Natural gas inventory		(124,955	)		3,676			125,042
Deferred income tax benefit		(14,310	)		(34,251	)		(10,338	)
Deferred revenue		596			5,468			(10,667	)
Unrealized risk management losses (gains)		16,566			(31,694	)		8,732
Accrued liabilities		(63,709	)		68,106			8,456
Depreciation and amortization		57,435			117,323			41,286
Other		(707	)		(238	)		(1,135	)
Amortization of deferred financing costs		4,076			3,652			3,354
Loss on extinguishment of debt		—			—			36,697
Losses (gains) on disposals of assets		268			(64	)		—
Impairment of goodwill		—			245,604			—
Non-cash compensation expense		1,653			2,305			—
Write-downs of inventory		4,300			63,800			4,600
Changes in non-cash working capital		90,854			(55,835	)		15,033

Net changes in non-cash working capital	$	(55,835	)	$	15,033		$	42,033
Net cash provided by (used in) operating activities	$	57,305		$	(39,444	)	$	91,907



Net cash used in investing activities	$	(3,133	)	$	(7,573	)	$	(5,166	)



Net cash (used in) provided by financing activities	$	(55,807	)	$	51,726		$	(89,244	)



Other information:
Proprietary inventory (at year-end)	$	41,268		$	136,295		$	75,140

~~Working~~Operating ~~Capital~~Activities. ~~Working~~The ~~capital~~variability isin ~~defined~~net ascash ~~the~~provided ~~amount~~ by ~~which~~operating ~~current~~activities ~~assets~~is ~~exceed~~primarily ~~current~~due ~~liabilities.~~to ~~Our~~(1) changes ~~working~~in ~~capital~~market conditions isthat ~~affected~~exist byduring any given fiscal period, which impacts the ~~relationship~~ ~~between~~margins ~~unrealized~~earned ~~risk~~under ~~management hedges~~each ~~which~~of ~~are~~our ~~marked~~fee-~~to-market~~based onand aoptimization ~~monthly~~activities; ~~basis,~~and (2) market conditions at the ~~margin~~end ~~deposits~~of ~~required~~any bygiven fiscal period, which impacts our ~~brokers~~decision ~~for~~to ~~such~~sell ~~gains~~significant volumes of inventory or hold them over a fiscal period end. When we purchase and ~~losses~~store natural gas, ~~proprietary~~we ~~inventory~~borrow under our credit facilities to pay for it, which isnegatively ~~stored~~impacts inoperating ~~our~~cash ~~facilities~~flow. ~~and~~Cash flow from operating activities increases when we collect the cash ~~used~~from ~~to fund~~the ~~inventory~~sale ~~purchases~~of inventories.

AsCash ofprovided by operating activities for the year ended March 31, ~~2015,~~2016 wewas ~~had~~$57.3 million ~~net~~compared ~~working~~to ~~capital~~cash ofused ~~negative~~in operating activities of $2439.64 million ~~(working~~during ~~capital~~the year ~~ratio~~ended ofMarch 31, 02015.9 toThe ~~1.0,~~increase ~~which~~in iscash ~~calculated~~provided by ~~dividing~~operating ~~current~~activities ~~assets~~principally byreflects ~~current liabilities),~~the ~~representing~~decision to hold on to a significant ~~change~~volume ~~compared~~of toinventory ~~net~~at ~~working~~the ~~capital~~end of ~~$33.4 million~~fiscal ~~(working~~2015 ~~capital~~and sell ~~ratio~~that ofinventory ~~1.1~~during tofiscal 12016.0) atPositive ~~March 31,~~cash ~~2014.~~flows ~~The~~from ~~reduction~~operating inactivities ~~working~~were ~~capital principally~~offset ~~reflects~~by the ~~reduction~~lower in profitability inafter ~~fiscal~~non-cash ~~2015~~gains, losses and expenses were excluded.

Investing Activities. Most of the investing activities during the fiscal year ended March 31, 2015 were attributed to maintenance activities. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. The majority of investing activities in the fiscal years ended March 31, 2014 and 2013 were attributed to expansion capital expenditures at our storage facilities. These expenditures, as outlined in "—Capital Expenditures," have enabled us to increase our effective working gas capacity by 25.0 Bcf during the two year period ended March 31, 2014. Historically, maintenance capital expenditures have been modest, ranging between $1.5 million and $2.0 million each year during this same period. However, a significant drawdown of natural gas inventory in the fourth quarter of fiscal 2014 resulted in significant operational burdens on our facilities and therefore, required additional maintenance capital expenditures during fiscal 2015.

Financing Activities. Net cash provided by (used in) financing activities consists of debt incurred for the acquisition of assets, periodic optional and mandatory retirements of such debt, advances and repayments made on our previous credit facilities to fund proprietary inventory purchases, contributions of capital from our equity holders to fund expansion capital expenditures and debt retirements and distributions made to our equity holders.

In fiscal 2015, we used the net cash from our revolver drawing to finance inventory purchases. In fiscal 2014, we completed a private placement of $575.0 million senior unsecured notes due 2019. Proceeds from the offering, along with borrowings under the revolving credit facilities, were used to redeem the then existing $643.8 million outstanding principal amount of the 8.875% Senior Notes due 2018.

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During fiscal 2015, the reduction in cash provided by operating activities was principally related to lower profitability and higher margining requirements associated with our retail business, combined with our decision to hold proprietary inventories over the end of fiscal 2015 in order to sell them in fiscal 2016.

	Year Ended March 31,

	2016			2015			2014
	(in thousands)
Changes in non-cash working capital:
Margin deposits	$	52		$	19,342		$	(14,137	)
Trade receivables		(256	)		3,114			(3,383	)
Accrued receivables		8,629			110,484			(44,459	)
Natural gas inventory		90,727			(124,955	)		3,676
Prepaid expenses and other assets		(6,421	)		542			358
Deferred revenue		(6,212	)		596			5,468
Accrued liabilities		4,609			(63,709	)		68,106
Other		(274	)		(1,249	)		(596	)

Net changes in non-cash working capital	$	90,854		$	(55,835	)	$	15,033

Working Capital. Working capital is defined as the amount by which current assets exceed current liabilities. Our working capital is affected by the relationship between unrealized risk management hedges which are marked-to-market on a monthly basis, the margin deposits required by our brokers for such gains and losses, proprietary inventory which is stored in our facilities and cash used to fund inventory purchases.

As of March 31, 2016 we had a net working capital deficiency of $79.5 million (working capital ratio of 0.7 to 1.0, which is calculated by dividing current assets by current liabilities), compared to a net working capital deficiency of $24.6 million (working capital ratio of 0.9 to 1.0) as at March 31, 2015. The increase in cash flows from changes in working capital principally reflects the decision to hold on to a significant volume of inventory at the end of fiscal 2015 and sell that inventory during fiscal 2016.

Investing Activities. Most of the investing activities during the fiscal year ended March 31, 2016 and 2015 were attributed to maintenance activities. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. A significant drawdown of natural gas inventory in the fourth quarter of fiscal 2014 resulted in significant operational burdens on our facilities and therefore, required additional maintenance capital expenditures during fiscal 2016 and 2015.

Financing Activities. Net cash (used in) provided by financing activities consists of debt incurred for the acquisition of assets, periodic optional and mandatory retirements of such debt, advances and repayments made on our credit facilities to fund proprietary inventory purchases, and debt retirements and distributions made to our equity holders.

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Capital Expenditures

Our capital expenditures for the years ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014 were as follows:

	Year Ended March 31,
	2015			2014			2013
	2016			2015			2014
	(in thousands)
Maintenance capital	$	42,~~844~~926		$	14,~~575~~844		$	1,~~833~~575
Expansion capital		~~540~~81			~~4,010~~540			224,~~631~~010

Total capital expenditures		53,~~384~~007			5,~~585~~384			245,~~464~~585
Decrease (increase) in accrued capital expenditures		~~2,203~~126			(2,~~426~~203	)		5(2,~~551~~426	)
Purchase of customer contracts		—			~~2,007~~—			—2,007
Proceeds from sale of assets		~~(14~~—	)		—(14	)		~~(2,210~~—	)

Net cash used in investing activities	$	73,~~573~~133		$	57,~~166~~573		$	275,~~805~~166

Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives.

Expansion capital expenditures are investments that serve to increase operating income over the long term through greater capacity or improved efficiency in Niska's operations, whether through construction or acquisition.

InUnder ~~the~~our ~~fiscal~~current ~~year~~plan, ~~ended~~we ~~March 31,~~expect ~~2014,~~to wespend ~~received~~approximately ~~the~~$11.0 million ~~approval~~to ~~from~~$13.0 million ~~the~~in ~~California~~fiscal ~~Public~~2017 ~~Utilities~~for ~~Commission~~maintenance capital expenditures to ~~add~~maintain 25the ~~Bcf~~integrity atof our storage ~~Wild~~facilities ~~Goose~~and ~~facility~~ensure the reliable injection, ~~increasing~~storage ~~our~~and ~~capacity from~~withdrawal 50of ~~Bcf~~natural togas 75for ~~Bcf~~our customers. ~~Because~~Included ~~most~~in ofour ~~the~~estimated ~~equipment~~maintenance ~~required~~capital toexpenditures ~~support~~for ~~this~~fiscal ~~expansion~~2017 ~~had~~is $6.0 million ~~been~~related ~~purchased~~to ~~and~~expected ~~installed~~cushion ~~previously,~~gas ~~costs~~purchases. ~~required~~Expansion tocapital ~~complete~~for ~~this~~fiscal ~~expansion~~2017 ~~were~~is ~~not~~expected ~~significant~~to be less than $1.0 million.

Under our current plan, we expect to spend approximately $3.0 million to $5.0 million in fiscal 2016 for maintenance capital expenditures to maintain the integrity of our storage facilities and ensure the reliable injection, storage and withdrawal of natural gas for our customers. Expansion capital for fiscal 2016 is expected to be less than $1.0 million.

Our 6.50% Senior Notes Due 2019

OnWe ~~March 17,~~have ~~2014, we completed the private placement of~~ senior unsecured notes due 2019 (the "6.50% Senior Notes"). ~~Net proceeds~~or ~~from~~"Notes") ~~the~~for ~~offering~~which ofinterest ~~approximately~~is ~~$563.3 million,~~payable ~~after deducting underwriters' discounts and fees, along with borrowings under our asset~~semi-~~based~~annually ~~revolving credit facilities, were used~~on toOctober 1 ~~redeem~~and ~~the $643.8~~April ~~million~~1 ~~outstanding~~at ~~principal~~a ~~amount~~rate of ~~our 8~~6.~~875~~50% ~~Senior~~per ~~Notes~~year, ~~due 2018. Including call premium of approximately $28.6 million~~ and ~~the~~will ~~write-off~~mature ofon ~~unamortized deferred financing costs of $8.1~~April ~~million~~1, ~~the~~2019. ~~Company~~See ~~recognized a loss of $36.7~~Note ~~million,~~8 ~~which was recorded as a loss on extinguishment of debt. These losses were measured based on the amounts paid as well as on the carrying value of the redeemed~~ "—Senior Notes, ~~which~~due ~~included~~2019" ~~unamortized~~in ~~debt~~our ~~issue~~Consolidated ~~costs on the dates of redemption. The related accrued interests paid were recorded in~~Financial ~~interest~~Statements ~~expense.~~for ~~Costs~~more ~~directly related to the issuance of the 6~~information.~~50%~~ ~~Senior Notes were capitalized as deferred financing costs and will be amortized as additional interest expense over the term of the debt.~~

OnWe ~~December 3,~~are ~~2014,~~in ~~the~~compliance ~~SEC~~with ~~accepted~~all ~~and~~covenant ~~made~~requirements ~~effective~~under ~~our exchange offer whereby holders of~~ the 6.50% Senior Notes ~~were permitted to exchange such Senior Notes for a new freely transferable Senior Notes~~. ~~The terms of the new units are identical to the units issued on March 17, 2014; except that the new units are registered under the Securities Act and generally do not contain restriction on~~

61 Our $320 Million Revolving Credit Facilities

~~Table~~ We have senior secured asset-based revolving credit facilities, consisting of ~~Contents~~a U.S. and a Canadian revolving credit facility (the "Revolving Credit Facilities", or the "Credit Agreement"). These credit facilities in aggregate provide a maximum borrowing capacity of $320.0 million, and can be drawn on up to the lesser of the borrowing base asset or the maximum borrowing capacity. See Note 8 "—Revolving Credit Facilities" in our Consolidated Financial Statements for more information.

~~transfer.~~ Our ~~The~~most ~~exchange~~recently ~~offer~~calculated ~~was~~borrowing ~~completed~~base onas ~~January~~of June 76, ~~2015~~2016 was $233.4 million. We also had $100.0 million in borrowings outstanding under our Revolving Credit Facilities and ~~substantially~~had ~~all~~$19.1 million ~~the~~in ~~holders~~letters of ~~the~~credit ~~Senior~~issued. ~~Notes~~We ~~accepted~~are ~~the~~in ~~offer~~compliance with all covenant requirements under our Credit Agreement.

The 6.50% Senior Notes are senior unsecured obligations which are: (1) effectively junior to secured obligations to the extent of the value to the collateral securing such debt; (2) equal in right of payment with all existing and future senior unsecured indebtedness; and (3) senior in right of payment to any future subordinated indebtedness. The 6.50% Senior Notes are fully and unconditionally guaranteed by us and our direct and indirect subsidiaries on a senior unsecured basis, and are: (1) effectively junior to each guarantor's secured obligations; (2) equal in right of payment with all existing and future senior unsecured indebtedness of each guarantor and (3) senior in right of payment to any future subordinated indebtedness of each guarantor.

Interest on the 6.50% Senior Notes is payable semi-annually on October 1 and April 1 at a rate of 6.50% per year, and will mature on April 1, 2019.

Prior to October 1, 2016, we have the option to redeem up to 35% of the aggregate principal amount of the 6.50% Senior Notes using net cash proceeds from certain equity offerings at a price of 106.5% plus accrued and unpaid interest. We may also redeem all or a part of the 6.50% Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.25% during the twelve-month period beginning on October 1, 2016, 101.625% during the twelve-month period beginning on October 1, 2017 and at par beginning on October 1, 2018, plus accrued and unpaid interest, if any, to the applicable redemption date. The Company is not required to make mandatory redemptions or sinking fund payments with respect to the 6.50% Senior Notes.

The indenture governing the 6.50% Senior Notes limits our ability to pay distributions in respect of, repurchasing or paying dividends on our membership interests (or other capital stock) or making other restricted payments.

The indenture does not prohibit certain types or amounts of restricted payments, including a general basket of $75.0 million of restricted payments.

The indenture governing our 6.50% Senior Notes contains certain other covenants that, among other things, limit our and certain of our subsidiaries' ability to:

The occurrence of events involving us or certain of our subsidiaries may constitute an event of default under the indenture. Such events include failure to pay interest, principal, or the premium on the notes when due; failure to comply with the merger, asset sale or change of control covenants; certain defaults on other indebtedness; and certain insolvency proceedings. In the case of an event of default, the holders of the notes are entitled to remedies, including the acceleration of payment of the notes by request of the holders of at least 25% in aggregate principal amount of the Notes, and any action by the trustee to collect payment of principal, interest or premium in arrears.

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~~Upon~~ ~~the occurrence of a change of control together with a decrease in the ratings of the notes by either Moody's or S&P by one or more gradations within 90 days of the change of~~ ~~control~~ Our ~~event, we must offer to repurchase the 6.~~$50% Million ~~Senior~~Short-term ~~Notes~~Credit ~~at 101% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.~~ Facility

~~Our ability~~We tohave ~~repurchase~~an ~~the~~agreement ~~6.50%~~with ~~Senior~~Brookfield ~~Notes~~for ~~upon~~ a ~~change~~$50.0 million ofshort ~~control~~term ~~will~~credit befacility ~~limited~~(the by"Short-term ~~the~~Credit ~~terms~~Facility"), offor which ~~our~~borrowings ~~debt~~bear ~~agreements,~~interest ~~including~~at ~~our~~an ~~asset-based~~annual ~~revolving~~rate ~~credit~~of ~~facilities~~10%. ~~In addition,~~Interest weis ~~cannot~~payable ~~assure~~in ~~that~~cash weon ~~will~~a ~~have~~quarterly basis, unless the ~~financial~~Company ~~resources~~elects to ~~repurchase~~pay such interest in-kind by capitalizing accrued interest into the 6principal amount.~~50%~~ ~~Senior~~See ~~Notes~~Note 8 ~~upon~~"—Short-term aCredit ~~change~~Facility" ofin ~~control~~our Consolidated Financial Statements for more information.

As ~~Our~~of June 6, 2016, we had $~~400~~41.1 ~~Million~~million in borrowings outstanding under our Short-term Credit ~~Agreement~~ Facility and were in compliance with all covenant requirements.

Niska Partners, through its subsidiaries, Niska Gas Storage US, LLC and AECO Gas Storage Partnership entered into senior secured asset-based revolving credit facilities, consisting of a U.S. revolving credit facility and a Canadian revolving credit facility (the "revolving credit facilities" or the "credit agreement"). These revolving credit facilities provide for revolving loans and letters of credit in an aggregate principal amount of up to $200.0 million for each of a U.S. revolving credit facility and a Canadian revolving credit facility. Subject to certain conditions, each of the U.S. revolving credit facility and the Canadian revolving credit facility may be expanded up to a total of $100.0 million in additional commitments, and the commitments in each facility may be reallocated on terms and according to procedures to be determined. Loans under the U.S. revolving facility will be denominated in U.S. dollars and loans under the Canadian revolving facility may be denominated, at Niska Partners' option, in either U.S. or Canadian dollars. Each revolving credit facility matures on June 29, 2016.

Borrowings under our revolving credit facilities are limited to a borrowing base calculated as the sum of specified percentages of eligible cash equivalents, eligible accounts receivable, the net liquidating value of hedge positions in broker accounts, eligible inventory, issued but unused letters of credit, and certain fixed assets minus the amount of any reserves and other priority claims. Borrowings bear interest at a floating rate, which (1) in the case of U.S. dollar loans can be either LIBOR plus an applicable margin or, at our option, a base rate plus an applicable margin, and (2) in the case of Canadian dollar loans can be either the bankers' acceptance rate plus an applicable margin or, at our option, a prime rate plus an applicable margin. The credit agreement provides that we may borrow only up to the lesser of the level of our then current borrowing base and our committed maximum borrowing capacity, which is currently $400.0 million. Our borrowing base was $271.4 million as of June 1, 2015 and the availability under the credit facilities was $83.5 million.

Our obligations under our credit agreement are guaranteed by us and all of our direct and indirect wholly owned subsidiaries (subject to certain exceptions) and secured by a lien on substantially all of our and our direct and indirect subsidiaries' current and fixed assets (subject to certain exceptions). Certain fixed assets are required to be part of the collateral only to the extent such fixed assets are included in the borrowing base under the respective revolving credit facilities. The aggregate borrowing base under both revolving credit facilities includes $150.0 million (the "PP&E Amount") due to a first-priority lien on fixed assets granted to the lenders. The PP&E Amount will be reduced on a dollar-for-dollar basis upon the release of fixed assets having a value in excess of $50.0 million from such liens.

The following fees are applicable under each revolving credit facility: (1) an unused line fee, based on the unused portion of the respective revolving credit facility; (2) a letter of credit participation fee on the aggregate stated amount of each letter of credit equal to the applicable margin for LIBOR loans or bankers' acceptance loans, as applicable; and (3) certain other customary fees and expenses of the lenders and agents. We are required to make prepayments under our revolving credit facilities at any time when, and to the extent that, the aggregate amount of the outstanding loans and letters of credit under such revolving credit facility exceeds the lesser of the aggregate amount of commitments in respect of such revolving credit facility and the applicable borrowing base.

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Our credit agreement contains customary covenants, including, but not limited to, restrictions on our and our subsidiaries' ability to merge and consolidate with other companies, incur indebtedness, grant liens or security interests on assets subject to security interests under the credit agreement, make acquisitions, loans, advances or investments, pay distributions, sell or otherwise transfer assets, optionally prepay or modify terms of any subordinated indebtedness or enter into transactions with affiliates. Our revolving credit facilities require the maintenance of a fixed charge coverage ratio of 1.1 to 1.0 at the end of each fiscal quarter when excess availability under both revolving credit facilities is less than 15% of the aggregate amount of availability under both revolving credit facilities. Such fixed charge coverage ratio will be tested at the end of each quarter until such time as average excess availability exceeds 15% for thirty consecutive days.

Our credit agreement contains limitations on our ability to pay distributions in respect of, repurchase or pay dividends on our membership interests (or other capital stock) or make other restricted payments.

Our credit agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, material inaccuracies of representations and warranties, covenant defaults, cross-defaults to other material indebtedness, including our 6.50% Senior Notes, voluntary and involuntary bankruptcy proceedings, material money judgments, and material events relating to pension plans, certain change of control events and other customary events of default.

As of March 31, 2015, we had $199.3 million in borrowings and letters of credit issued under our revolving credit facilities, with a weighted average interest rate of 3.98%. As of June 11, 2015, we had $162.0 million in borrowings outstanding under our revolving credit facilities and had $24.7 million in letters of credit issued. We and our subsidiaries were in compliance with all covenant requirements under our credit facilities at June 1, 2015.

We expect that our fixed charge coverage ratio will likely fall below 1.1 to 1.0 in the quarter ending June 30, 2015, which would result in the last 15% of the Company's borrowing base becoming unavailable for borrowing. The Company is pursuing strategies, which include reductions in operating and general and administrative costs as well as management of the components of the borrowing base, which will assist the Company in maintaining adequate liquidity despite this covenant provision.

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Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, ~~2015~~2016:

	Payment due by period
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
	(in thousands)
Long term debt obligations	$	575,000	$	—	$	—575,000	$	~~575,000~~—	$	—
Interest on long term debt obligations		~~149~~112,~~500~~125		37,375		74,750		~~37,375~~—		—
Operating lease obligations		2014,~~303~~738		6,166		97,~~995~~162		41,~~142~~410		—
Capital lease obligations		1210,~~202~~545		1,657		3,~~313~~314		3,~~313~~314		32,~~919~~260
Leased storage contracts		~~2,349~~917		~~1,393~~917		~~956~~—		—		—
Mineral and surface leases		~~196~~192,~~690~~592		3,~~743~~892		7,~~687~~768		7,~~700~~885		~~177~~173,~~560~~047
Asset retirement obligations		5860,~~488~~565		—		—		—		5860,~~488~~565
Post-retirement obligation		2,500		—		—		—		2,500
Withholding taxes (including interest and penalties)		10,144		10,144		—		—		—
Deferred income tax		908		744		164		—		—
Deferred income tax		781		781		—		—		—
Withholding taxes (including interest and penalties)		4,751		4,751		—		—		—
Purchase obligations(1)		1,~~484~~018,~~809~~000		~~981~~629,~~883~~022		~~491~~377,~~828~~890		11,~~098~~088		—

Total	$	21,~~512~~992,~~766~~641	$	1684,~~043,142~~524	$	~~588~~1,~~529~~046,048	$	~~638~~23,~~628~~697	$	~~242~~238,~~467~~372

(1)Purchase obligations ~~consist~~consisted of forward physical and financial commitments related to future purchases of proprietary natural gas inventory and cushion gas. As we economically hedge substantially all of our natural gas purchases, there are forward sales that offset these commitments ~~that~~which are not included in the above table. As at March 31, ~~2015~~ 2016, forward physical and financial sales for all future periods related to proprietary gas totaled $1994.5 million. As at March 31,~~485~~ 2016, forward financial sales for all future periods relating to cushion gas totaled $7.3 million.

Off-Balance Sheet Arrangements

In ~~accordance with GAAP, there is no carrying value recorded for our credit facilities until we borrow from~~ the ~~facilities. In the~~ future we may use off-balance sheet arrangements such as undrawn credit facility commitments, including letters of credit, to finance portions of our capital and operating needs. See "—Contractual Obligations" for more information.

On January 1, 2010, we entered into an operating lease for compression and other equipment related to the development of an expansion project at Wild Goose. See "Note 1920—Commitments and Contingencies" for more information.

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Critical Accounting Estimates and Policies

The historical financial statements included in this document have been prepared in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires our judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Our judgments and estimates are based on what we believe are the best and most relevant information available to us at the time our financial statements are prepared.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the application of GAAP. These estimates affect, among other items, revenue recognition and expense accruals, migration of cushion, assessing income tax expense including the requirement for a valuation allowance against deferred income tax assets, calculating unit-based compensation, valuing of risk management assets and liabilities, inventory and identified intangible assets.

Description		Judgments and Uncertainties

*Revenue Recognition*
See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of our revenue recognition policies. Revenues are recognized when collectability is reasonably assured. Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.		Our revenue recognition accounting process contains uncertainties because it requires us to make a judgment on the collectability of revenue at the outset of an arrangement. In addition, our revenue also includes unrealized risk management gains and losses which require us to estimate fair value of our risk management contracts.

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Description		Judgments and Uncertainties

*Fair Value of Risk Management Assets and Liabilities*
We use natural gas derivatives and other financial instruments to manage our exposure to changes in natural gas prices and foreign exchange rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included into one of three categories based on a fair value hierarchy. The fair value of our derivative contracts are recorded as risk management assets and liabilities, which are classified as either current assets, non-current assets, or liabilities based upon the anticipated settlement date of the contracts. The determination of the fair value of these derivative contracts reflects the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.		There are uncertainties in our methodology in the determination of fair value since it requires us to consider various factors, including over-the-counter quotations, location differentials and closing foreign exchange rates underlying the contracts. Although the fair value of our risk management assets and liabilities may fluctuate, such fluctuations are offset by equivalent changes in the value of our physical inventory. Our policy is for our inventory and purchases to be economically hedged, within small tolerances permitted under our risk management policy, so we are not exposed economically to the risk of fluctuating commodity prices.
*Inventory*
Our inventory is natural gas injected into storage and held for resale. Inventory is valued at the lower of average cost or market. Adjustments to write down the costs of inventory to market are recorded as an offset to optimization revenues while costs to store the gas are recognized as operating expenses in the period the costs are incurred.		At the end of each reporting period we determine whether a write-down is required to reduce inventory to the lower of cost or market value. This determination has built-in uncertainties since it requires judgment in estimating fair market values in the periods to which our inventory is economically hedged and the level of a normal margin compared to selling price in those periods.
*Cushion Effectiveness*
Certain volumes of cushion are required for maintaining a minimum field pressure. Cushion is considered a component of the facility and as such is not depreciated. Cushion is monitored to ensure that it provides effective pressure support. In the event that natural gas moves to another area of the reservoir where it does not provide effective pressure support, charges against cushion are included in depreciation in an amount equal to the cost of estimated volumes that have migrated.		Cushion requirements and its effectiveness are estimated using pressure and volumetric data accumulated over many years of storage operation. The data is added into a complex reservoir model which accounts for different dynamic phenomena occurring within the reservoir. The information incorporated into the model includes pressure gradients within the reservoir, water encroachment due to an active aquifer, tight reservoir components which slowly capture and release back some of the gas stored and a cushion migration component. These phenomena influence one another and the level of uncertainty of the estimate of cushion present in a reservoir.

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compensation, valuing of risk management assets and liabilities, inventory and identified intangible assets.

Description		Judgments and Uncertainties

*Impairment of Intangible Assets*
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of our policy regarding Intangible assets. Intangible assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of intangible assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.		These types of analyses contain uncertainties because they require management to make assumptions and apply judgment to estimate future cash flows, the profitability of future business strategies, industry conditions and other economic factors.
*Income taxes*
We are not a taxable entity in the United States. Income taxes are the responsibility of the individual partners and have accordingly not been recorded in the consolidated financial statements. We have corporate subsidiaries, which are taxable corporations subject to Canadian federal and provincial income taxes, which are included in the consolidated financial statements. See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of policy in accounting for income taxes.		Our accounting for income taxes has inherent uncertainties since it requires us to estimate the timing of the realization of our tax assets and liabilities, including the allocation of income among different entities and tax jurisdiction, and also requires us to make assumptions on the estimated probabilities of utilization of deferred tax assets and on the determination of tax exposures associated with our tax filing positions.

Description		Judgments and Uncertainties
Revenue Recognition
See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of our revenue recognition policies. Revenues are recognized when collectability is reasonably assured. Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectability is not considered reasonably assured at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.		Our revenue recognition accounting process contains uncertainties because it requires us to make a judgment on the collectability of revenue at the outset of an arrangement. In addition, our revenue also includes unrealized risk management gains and losses which require us to estimate fair value of our risk management contracts.
Fair Value of Risk Management Assets and Liabilities
We use natural gas derivatives and other financial instruments to manage our exposure to changes in natural gas prices and foreign exchange rates. These financial assets and liabilities, which are recorded at fair value on a recurring basis, are included into one of three categories based on a fair value hierarchy. The fair value of our derivative contracts are recorded as risk management assets and liabilities, which are classified as either current assets, non-current assets, or liabilities based upon the anticipated settlement date of the contracts. The determination of the fair value of these derivative contracts reflects the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.		There are uncertainties in our methodology in the determination of fair value since it requires us to consider various factors, including over-the-counter quotations, location differentials and closing foreign exchange rates underlying the contracts. Although the fair value of our risk management assets and liabilities may fluctuate, such fluctuations are offset by equivalent changes in the value of our physical inventory. Our policy is for our inventory and purchases to be economically hedged, within small tolerances permitted under our risk management policy, so we are not exposed economically to the risk of fluctuating commodity prices.
Inventory
Our inventory is natural gas injected into storage and held for resale. Inventory is valued at the lower of average cost or market. Adjustments to write down the costs of inventory to market are recorded as an offset to optimization revenues while costs to store the gas are recognized as operating expenses in the period the costs are incurred.		At the end of each reporting period we determine whether a write-down is required to reduce inventory to the lower of cost or market value. This determination has built-in uncertainties since it requires judgment in estimating fair market values in the periods to which our inventory is economically hedged and the level of a normal margin compared to selling price in those periods.

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Description		Judgments and Uncertainties
Cushion Effectiveness
Unit-based compensation
Certain volumes of hydrocarbons defined as cushion are required for maintaining a minimum field pressure. Cushion is considered a component of the facility and as such is not depreciated. Cushion is monitored to ensure that it provides effective pressure support. In the event that natural gas moves to another area of the reservoir where it does not provide effective pressure support, charges against cushion are included in depreciation in an amount equal to the cost of estimated volumes that have migrated.		Cushion requirements and its effectiveness are estimated using pressure and volumetric data accumulated over many years of storage operation. The data is added into a complex reservoir model which accounts for different dynamic phenomena occurring within the reservoir. The information incorporated into the model includes pressure gradients within the reservoir, water encroachment due to an active aquifer, tight reservoir components which slowly capture and release back some of the gas stored and a cushion migration component. These phenomena influence one another and the level of uncertainty of the estimate of cushion present in a reservoir.
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of policy in accounting for unit-based compensation. The fair value of unit-based awards that are expected to be settled in cash is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each re-measurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested adjusted for (1) the passage of time and (2) the payout threshold associated with the performance targets which we expect to achieve compared to our established peers. Compensation expense is calculated as the re-measured expected payout less previously-recognized compensation expense.		There are uncertainties in our calculation of unit-based compensation since it requires us to make assumptions and judgments on the estimated probabilities of meeting our performance measures, forfeiture rate and unit price at settlement date.
Impairment of Goodwill and Other Intangible Assets
The fair value of unit-based awards that are expected to be settled in units is determined on the date of grant and is amortized into equity using the straight-line method over the vesting period.
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of our policy regarding goodwill and other intangible assets. In evaluating goodwill for impairment, the Company has the option to first assess qualitative factors to determine whether it is more likely than not that goodwill is impaired. The result of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the quantitative impairment test. The performance of the quantitative impairment test involves a two-step process. The first step involves comparing the fair values of the applicable reporting units with their aggregate carrying values, including goodwill. If the carrying amount exceeds the fair value of the reporting unit, we perform the second step of the goodwill impairment test to determine the amount of impairment loss. The second step of the goodwill impairment test involves comparing the implied fair value of the affected reporting unit's goodwill with the carrying value of that goodwill.		Determining the fair value of a reporting unit is judgmental in nature and requires the use of significant estimates and assumptions. These assumptions are dependent on several subjective factors including the timing of future cash flows and future growth rates. The fair value of our reporting units is determined based on a weighting of multiples of potential earnings approaches which is classified under Level 3 fair value measurement. The multiples of earnings approach estimates fair value by applying multiples of potential earnings, working gas capacity, and cyclability of similar entities. Results using the multiples of potential earnings and the multiples of gas capacity and cyclability are given equal weighting when determining the valuation using this approach. The future operating projections are based on consideration of past performance and the projections and assumptions used in our current operating plans adjusted for market participant assumptions as appropriate. We then assign a weighting to the multiple or earnings to derive the fair value of the reporting unit.

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Description		Judgments and Uncertainties
Other intangible assets are reviewed for impairment as impairment indicators arise. When such events or circumstances are present, the recoverability of intangible assets is assessed by determining whether the carrying value will be recovered through the expected undiscounted future cash flows. In the event that the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset's carrying value over its fair value is recorded.		These types of analyses contain uncertainties because they require management to make assumptions and apply judgment to estimate future cash flows, the profitability of future business strategies, industry conditions and other economic factors.
Income taxes
We are not a taxable entity in the United States. Income taxes are the responsibility of the individual partners and have accordingly not been recorded in the consolidated financial statements. We have corporate subsidiaries, which are taxable corporations subject to Canadian federal and provincial income taxes, which are included in the consolidated financial statements. See Note 2, Significant Accounting Policies, of our Consolidated Financial Statements for a complete discussion of policy in accounting for income taxes.		Our accounting for income taxes has inherent uncertainties since it requires us to estimate the timing of the realization of our tax assets and liabilities, including the allocation of income among different entities and tax jurisdiction, and also requires us to make assumptions on the estimated probabilities of utilization of deferred tax assets and on the determination of tax exposures associated with our tax filing positions.
Unit-based compensation
See Note 2, Significant Accounting Policies, on our Consolidated Financial Statements for a complete discussion of policy in accounting for unit-based compensation. The fair value of unit-based awards that are expected to be settled in cash is determined on the date of grant and is re-measured at each reporting period until the settlement date. The fair value at each re-measurement date is equal to the settlement expected to be incurred based on the anticipated number of units vested adjusted for (1) the passage of time and (2) the payout threshold associated with the performance targets which we expect to achieve compared to our established peers. Compensation expense is calculated as the re-measured expected payout less previously-recognized compensation expense. The fair value of unit-based awards that are expected to be settled in units is determined on the date of grant and is amortized into equity using the straight-line method over the vesting period.		There are uncertainties in our calculation of unit-based compensation since it requires us to make assumptions and judgments on the estimated probabilities of meeting our performance measures, forfeiture rate and unit price at settlement date.

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Recent Accounting Pronouncements

Please refer to Note 3 of our Consolidated Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risks.

The term "market risks" refers to the risk of loss arising from changes in commodity prices, price risk associated with compliance with environmental regulations, currency exchange rates, interest rates, counterparty credit and liquidity. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

To mitigate exposure to changes in commodity prices, we enter into purchases and sales of natural gas inventory and concurrently match the volumes in these transactions with offsetting forward contracts or other hedging transactions.

Derivative contracts used to manage market risk generally consist of the following:

•: Forwards and futures are contractual agreements to purchase or sell a specific financial instrument or natural gas at a specified price and date in the future. We enter into forwards and futures to mitigate the impact of natural gas price volatility. In addition to cash settlement, exchange traded futures may also be settled by physical delivery of natural gas.

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•: Swap contracts are agreements between two parties to exchange streams of payments over time according to specified terms. Swap contracts require receipt of payment for the notional quantity of the commodity based on the difference between a fixed price and the market price on the settlement date. We enter into commodity swaps to mitigate the impact of changes in natural gas prices.
•: Option contracts are contractual agreements to convey the right, but not the obligation, for the purchaser of the option to buy or sell a specific physical or notional amount of a commodity at a fixed price, either at a fixed date or at any time within a specified period. We may enter into option agreements to mitigate the impact of changes in natural gas prices.

In order to manage our exposure to commodity price fluctuations, our policy is to promptly enter into a forward sale contract or other hedging transaction for every proprietary purchase contract we enter into. Therefore, inventory purchases are matched with forward sales or are otherwise economically hedged so that there are no speculative positions beyond the minimal operational tolerances specified in our risk policy.

At March 31, ~~2015~~2016, 47we have 25.25 ~~Bcf~~MDth of natural gas inventory ~~was~~of ~~economically~~which ~~hedged,~~25.3 ~~representing~~MDth 98or 99.62% ofwas ~~our~~economically ~~total current inventory~~hedged. ~~However,~~Because ~~because~~ inventory is recorded at the lower of cost or market, not fair value, if the price of natural gas increased by $1.00 per ~~Mcf~~MMBtu the value of that inventory would increase by $4725.95 million, but the fair value or mark-to-market value of our hedges would decrease by $4725.23 million, because 10.48% (0.72 ~~Bcf~~MDth) of that inventory that was not economically hedged. Conversely, if the price of natural gas declined by $1.00 per ~~Mcf~~ MMBtu, the value of that inventory would decrease by $4725.95 million while the fair value of our hedges would increase by only $4725.23 million, due to the non-economically hedged position. Fuel gas included in the volumes above that is used for operating our facilities is not offset. Total volume of our fuel gas was 0.3 MDth and 0.0 ~~Bcf~~MDth as of March 31, ~~2015~~2016 and ~~2014~~2015, respectively.

~~Although~~In ~~the~~addition ~~intent~~to ofthe ~~our~~volumes ~~risk-management~~mentioned ~~strategy~~above, isas toat ~~protect~~March 31, ~~our~~2016, ~~margins~~we ~~and~~have ~~manage~~entered ~~our~~into ~~liquidity~~forward ~~risk~~purchase oncontracts ~~related~~for ~~margin~~1.5 ~~deposit~~MDth ~~requirements,~~of wenatural dogas ~~not~~representing ~~qualify~~42% ~~any~~ of our estimated ~~derivatives~~cushion ~~for~~purchases ~~hedge~~in ~~accounting~~fiscal 2017. ~~Changes~~As ina result of the ~~fair~~unhedged ~~values~~portion of ~~these~~expected ~~derivatives~~cushion ~~receive~~gas ~~mark-~~purchases, a $1.00 per MMBtu increase or decrease would have a corresponding increase or decrease to~~-market~~ ~~treatment~~the net incost of our cushion gas purchase by approximately $2.1 million.

69 Although the intent of our risk-management strategy is to protect our margins and manage our liquidity risk on related margin deposit requirements, we do not qualify any of our derivatives for hedge accounting. Changes in the fair values of these derivatives receive mark-to-market treatment in current earnings and result in greater potential for earnings volatility. This accounting treatment is discussed further under Note 2 of our Consolidated Financial Statements.

Price Risk Associated with Compliance with Environmental Regulations

One of Niska Partners' operating facilities, the Wild Goose storage facility, is located in California. In 2006, California adopted AB 32, the Global Warming Solutions Act of 2006, with a goal of reaching: (i) 1990 greenhouse gases ("GHG") emissions levels by the year 2020; (ii) 80% of 1990 levels by 2050; and (iii) a mandatory emission reporting program. AB 32 required the California Air Resources Board ("ARB") to develop a scoping plan describing the approach California will take to reduce GHGs to achieve the goal of reducing emissions to 1990 levels by 2020 (the "2020 Goal"). The scoping plan was first approved by the ARB in 2008 which identifies a cap-and-trade program as one of the strategies California will employ to meet the 2020 Goal. In 2010, ARB approved that cap and trade program and it came into effect on January 1, 2013.

Entities are subject to compliance obligations if they exceed certain ARB-defined emission thresholds. During each year of the program, the ARB issues emission allowances (i.e., the rights to

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~~current~~emit ~~earnings~~GHGs) ~~and~~equal ~~result~~to inthe ~~greater~~amount ~~potential~~of GHG emissions allowed for ~~earnings~~that ~~volatility~~year. ~~This~~Emitters ~~accounting~~can ~~treatment~~obtain isallowances ~~discussed~~from ~~further~~the ARB at quarterly auctions, from third parties or exchanges. Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside the industry sectors covered under ~~Note~~the cap through ARB-qualified offset projects such as reforestation or biomass projects. During fiscal 2016, the Company determined that it had exceeded its allowed emissions threshold and became subject to compliance obligations whereby it must purchase allowances or offset credits. As of March 231, 2016, the Company had $0.8 million of ~~our~~accrued ~~Consolidated~~emission ~~Financial~~allowances ~~Statements~~and offset credits, and the Company was exposed to risks associated with changes in the price of credits for GHG reductions.

Foreign Currency Risk

Our cash flow relating to our Canadian operations is reported in the U.S. dollar equivalent of such amounts measured in Canadian dollars. Monetary assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the actual exchange rate or the average exchange rate in effect during the reporting period.

~~Because~~Canadian adollar ~~portion~~cash inflows from revenues are offset, in part, by natural gas inventory purchases, operating, general and administrative and capital costs that are also transacted in Canadian dollars. We hedge the substantial majority of our ~~Canadian~~remaining ~~business~~net isexposure ~~conducted~~to inthe Canadian ~~dollars,~~dollar weby ~~use~~entering ~~certain~~into ~~financial~~currency ~~instruments~~hedges for existing transactions to minimize the risks of changes in the exchange rate. These instruments ~~include~~ ~~forward~~are primarily swaps ortransacted ~~spot~~to ~~swaps~~purchase ~~buying~~ or ~~selling~~sell U.S. dollars, as required. ~~Options~~As ~~may~~a ~~also~~result beof ~~used~~our inhedging ~~the~~program, ~~future.~~we ~~All~~do ofnot believe that a change in the ~~financial~~Canadian exchange ~~instruments~~rate ~~utilized~~would ~~are~~have ~~placed~~a ~~with~~significant ~~large~~impact ~~brokers~~on ~~and~~the ~~financial institutions~~results of our operations.

At March 31, ~~2015~~2016, we had forward currency exchange contracts for a notional value of $1938.63 million. The ~~values~~value of the forward currency contracts ~~ware~~were in a net ~~assets~~liability position of ~~$3.2 million~~ ~~and~~ $20.41 million as of March 31, 2016 (2015—net ~~and~~asset ~~2014,~~of ~~respectively~~$3.2 million), and were recorded in derivative assets and derivative liabilities accounts on the consolidated balance sheets. These contracts expire on various dates between April ~~2015~~2016 and ~~June~~February ~~2016~~2017 and were for the exchange of $2149.29 million Canadian dollars into $1938.63 million U.S. dollars.

Interest Rate Risk

We are exposed to interest rate risk due to variable interest rates under our ~~$400.0 million~~Revolving ~~credit~~Credit ~~agreement~~Facilities. All such borrowings under the ~~our~~Credit ~~credit~~Agreement ~~facilities~~ bear interest at different rates. As of March 31, ~~2015~~2016, we had $~~199~~115.36 million in borrowings and letters of credit issued under ~~our~~the ~~revolving~~Revolving ~~credit facilities.~~Credit ~~The~~Facilities, ~~credit~~and it ~~facilities~~ currently ~~provide~~provides an interest rate on borrowings between 34.9019% and 6.5075%, depending on whether a fixed term or floating rate option is chosen. In the future, we may borrow under fixed rate and variable rate debt instruments that also give rise to interest rate risk. Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. A hypothetical increase or decrease in interest rates by 1% would have changed our interest expense by approximately $21.49 million for the fiscal year ended March 31, ~~2015~~2016.

Counterparty Credit Risk

Counterparty credit risk is the risk of financial loss if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. Credit risk associated with trade ~~accounts~~and ~~receivable~~accrued receivables is mitigated by the high ~~percentage of investment grade customers, collateral support of receivables and our ability to take ownership of customer-owned natural gas stored in its facilities in the event of non-payment.~~

Margin deposits, or letters of credit in lieu of deposits, are required on derivative instruments utilized to manage our counterparty credit risk. As commodity prices increase or decrease, the fair value of our derivative instruments changes thereby increasing or decreasing our margin deposit requirements. Rising commodity prices or an expectation of rising prices could increase the cash needed to manage our commodity price exposure and thereby increase our liquidity requirements, limit amounts available to us through borrowing and reduce the volume of natural gas we may purchase. Exchange traded futures and options have minimal credit exposure as the exchanges guarantee every contract will be margined on a daily basis. In the event of any default, our account on the exchange would be absorbed by other clearing members. Because every member posts an initial margin, the exchange can protect the exchange members if or when a clearing member defaults. 69

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percentage of investment grade customers, collateral support of receivables and our ability to take ownership of customer-owned natural gas stored in its facilities in the event of non-payment.

Liquidity Risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they become due. Our approach to managing liquidity risk is to contract a substantial part of our facilities to generate constant cash flow and to ensure that ~~they~~we always have sufficient cash and credit facilities to meet ~~their~~our obligations ~~when~~ when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to reputation. See "—Liquidity and Capital Resources" for more information.

Fair Value Measurement

The fair values of the derivative instruments are based on quoted market prices obtained from NYMEX or ICE and from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the instrument, which approximates the gain or loss that would have been realized if the contracts had been closed out at a specified time. We utilize observable market data when available, or models that utilize observable market data when determining fair value.

Risk Management Policy and Practices

We have in place risk management practices that are intended to quantify and manage risks facing our business. These risks include, but are not limited to, market, credit, environmental regulation compliance, foreign exchange, operational, and liquidity risks. Our hedging practices mitigate our exposure to commodity price and foreign exchange risks. Strict open position limits are enforced, and physical inventory is offset with forward hedges. Our counterparty strategy ensures we have a strong mix of quality customers. We have models in place to monitor and manage operational and liquidity risks.

The Risk Management Committee, or RMC, is comprised of members of our management team. The RMC provides oversight of our commercial activities. The committee reviews the adequacy of controls to ensure compliance with the risk policy. Our RMC meets weekly to review and respond to risks facing our business. The RMC oversees the analysis of positions and exposures provided by our risk management function, which provides daily and weekly reporting to facilitate understanding of these exposures. The RMC assesses and manages the potential for loss in our positions through these reports. If limits are exceeded, the RMC is informed and appropriate action is taken to review and remedy. The risk management function is independent of the Marketing and Optimization groups and reports through our chief financial officer.

Optimization activities can only be executed by employees authorized to transact under the risk policy. All commercial personnel are annually required to read and certify that they will adhere to the principles purported within the policy. Each person authorized to make transactions is subject to internal volume limits. Counterparties are subject to credit limits as approved by our credit department.

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principles purported within the policy. Each person authorized to make transactions is subject to internal volume limits. Counterparties are subject to credit limits as approved by our credit department.

Our commercial and risk functions operate independently to ensure proper segregation of duties. Critical deal information for every transaction is entered into our deal capture systems and confirmed with counterparties.

Despite the policies, procedures and controls described above, there can be no assurance that our risk management systems will prevent losses that would negatively affect our business, results of operations, cash flows and financial condition. See "Risk Factors—Risks Inherent in Our Business—Our risk management policies cannot eliminate all commodity price risk." In addition, any non-compliance with our risk management policies could result in significant financial losses.

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Item 8. Financial Statements and Supplementary Data.

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-4 through F-5049 of this Annual Report on Form 10-K and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

(a): Disclosure Controls and Procedures.

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of March 31, 2016. For purposes of this section, the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's ~~(a) Disclosure~~management, ~~Controls~~including its principal executive and ~~Procedures~~principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(b): Management's Report on Internal Control over Financial Reporting.

Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of March 31, 2015. For purposes of this section, the term "disclosure controls and procedures" means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

(b) Management's Report on Internal Control over Financial Reporting.

Management's report on internal control over financial reporting is set forth on page F-2 of this Annual Report on Form 10-K and is incorporated herein by reference.

(c): Attestation Report of the Registered Public Accounting Firm.

The attestation report of our registered public accounting firm with respect to internal controls over financial reporting is set forth on page F-3 of this Annual Report on Form 10-K and is incorporated herein by reference.

(d): Changes in Internal Control Over Financial Reporting.

(d) Changes in Internal Control Over Financial Reporting.

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Management of Niska Gas Storage Partners LLC

Our manager has sole responsibility for conducting our business and for managing our operations. Pursuant to our Operating Agreement, our manager has delegated the power to conduct our business and manage our operations to our board. Our manager may revoke this delegation and resume control of our business at any time. Our manager and our board are not elected by our unitholders and will not be subject to re-election on a regular basis in the future. As long as the delegation of authority is in effect, our manager will appoint all members to our board. Unitholders will not be entitled to elect our directors or directly or indirectly participate in our management or operation. Our Operating Agreement provides that our manager must act in "good faith" when making decisions on our behalf.

Whenever our manager makes a determination or takes or declines to take an action in its individual, rather than representative, capacity or in its sole discretion, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us or any member, and our manager is not required to act in good faith or pursuant to any other standard imposed by our Operating Agreement or under the Delaware Act or any other law. Examples include the exercise of its limited call rights, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation. Actions of our manager which are made in its individual capacity or in its sole discretion will be made by a majority of the owners of our manager.

In selecting and appointing directors to our board, our manager does not apply a formal diversity policy or set of guidelines. However, when appointing new directors, our manager considers each individual director's qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board as a whole.

Directors and Executive Officers

Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the member of our manager. Our executive officers serve at the discretion of our board. There are no family relationships among any of the directors or executive officers. The following table shows information as of June 9, 2016, regarding our current directors and executive officers.

Name		Position

William H. Shea, Jr.	61	Chairman, President, Chief Executive Officer and Director
Vance E. Powers	59	Chief Financial Officer
Mark D. Casaday	55	Chief Operating Officer
Rick J. Staples	53	Executive Vice President and Chief Commercial Officer
Robert B. Wallace	55	Vice President, Finance and Corporate Development
Jason A. Dubchak	43	Vice President, General Counsel and Corporate Secretary
Bruce D. Davis, Jr.(1)	59	Former Vice President and Chief Administrative Officer
Ralph Alexander	61	Director
Michael Hennigan	56	Director
James G. Jackson	52	Director
E. Bartow Jones	40	Director
Stephen C. Muther	67	Director
Andrew W. Ward	49	Director
Olivia C. Wassenaar	36	Director

(1): On July 31, 2015, Bruce D. Davis, Jr., former Vice President and Chief Administrative Officer was terminated without cause.

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~~There are~~ William noH. ~~family~~Shea, ~~relationships~~Jr.—Mr. Shea ~~among~~is ~~any~~our Chairman, President and Chief Executive Officer and a member of our board and the board of directors orof our ~~executive~~manager ~~officers~~and also serves on the compensation committee. ~~The~~Mr. Shea ~~following~~served ~~table~~as ~~shows~~a ~~information~~director of PVR GP, LLC, the general partner of PVR Partners L.P. and Chief Executive Officer of Penn Virginia Resource Partners, L.P. from March 2010 to March 2014, as Chief Executive Officer of PVR GP, LLC from March 2010 to June 2012 and as President and Chief Executive Officer of PVR 12GP, LLC ~~2015~~since June 2012. Previously, ~~regarding~~Mr. Shea ~~our~~served ~~current~~as the ~~directors~~Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership from May 2004 to July 2007, as President and ~~executive~~Chief ~~officers~~Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. Kayne Anderson MLP Investment Company, and USA Compression Holdings LLC and as Chief Executive Officer of Mainline Energy Partners, LLC. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.

Name		Position
William H. Shea, Jr.(1)	60	Chairman, President, Chief Executive Officer and Director
Simon Dupéré(1)	52	Former President and Chief Executive Officer and Former Director
Vance E. Powers	58	Chief Financial Officer
Mark D. Casaday(1)	54	Chief Operating Officer
Rick J. Staples	52	Executive Vice President and Chief Commercial Officer
Robert B. Wallace(1)	54	Vice President, Finance and Corporate Development
Jason S. Kulsky(2)	48	Former Vice President, Business Development
Jason A. Dubchak	42	Vice President, General Counsel and Corporate Secretary
Bruce D. Davis, Jr.(1)	58	Vice President and Chief Administrative Officer
Ralph Alexander(3)	60	Director
Michael Hennigan(4)	55	Director
Olivia C. Wassenaar(5)	35	Director
James G. Jackson	51	Director
E. Bartow Jones	39	Director
Stephen C. Muther	66	Director
George A. O'Brien(3)	66	Former Director
Andrew W. Ward	48	Director

(1)On May 7, 2014, Simon Dupéré, President and Chief Executive Officer of the Company, resigned from his employment with the Company and from his membership on the Company's Board of Directors. In addition, the Board appointed William H. Shea, Jr., as the Company's Chairman and President and Chief Executive Officer, Mark D. Casaday, as the Company's Chief Operating Officer, Robert B. Wallace, as the Company's Vice President, Finance and Corporate Development, and Bruce D. Davis, Jr., as the Company's Vice President, Chief Administrative Officer. (2)On June 25, 2014, Jason Kulsky, former Vice President of Business Development, resigned from his employment with the Company and his office of Vice President of Business Development. (3)On December 31, 2014, George O'Brien resigned from the Board of Directors and all committees of the Company. In addition, the Board appointed Ralph Alexander as a director and a member of the Compensation Committee. (4)On September 10, 2014, Michael Hennigan was appointed to the Board of Directors as well as a member of the Audit and Compensation Committees. On January 27, 2015 Mr. Hennigan was appointed Chair of the Compensation Committee. (5)On July 30, 2014, Olivia C. Wassenaar was appointed to the Board of Directors and as a member of the Finance Committee.

William H. Shea, Jr.—Mr. Shea is our Chairman, President and Chief Executive Officer and a member of our board and the board of directors of our manager and also serves on the compensation committee. Mr. Shea served as a director of PVR GP, LLC, the general partner of PVR Partners L.P. and Chief Executive Officer of Penn Virginia Resource Partners, L.P. from March 2010 to March 2014, as Chief Executive Officer of PVR GP, LLC from March 2010 to June 2012 and as President and Chief Executive Officer of PVR GP, LLC since June 2012. Previously, Mr. Shea served as the Chairman of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., a refined petroleum products pipeline partnership from May 2004 to July 2007, as President and Chief Executive Officer of Buckeye GP LLC from September 2000 to July 2007 and as President and Chief Operating Officer of Buckeye GP LLC

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from July 1998 to September 2000. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea also serves as a director of Kayne Anderson Energy Total Return Fund, Inc. Kayne Anderson MLP Investment Company, and USA Compression Holdings LLC. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of Carlyle/Riverstone Funds' portfolio companies.

Mr. Shea's experiences as an executive with both PVR and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him valuable knowledge about our industry. In addition, Mr. Shea has valuable experience overseeing the strategy and operations of publicly-traded partnerships, which are similar to us. As a result of this experience and resulting skills set, we believe Mr. Shea is an asset to our business.

Vance E. Powers—Mr. Powers is our Chief Financial Officer. Mr. Powers has served as our Chief Financial Officer since January 1, 2011. Mr. Powers has over 25 years of experience in senior financial, accounting, and reporting positions. From April 2010 until commencing service as Niska's Chief Financial Officer, Mr. Powers served as a finance management consultant to Niska, assisting in the completion of Niska's initial public offering, its transition to a publicly-traded company and its establishment of an investor relations function. From May 2009 to March/April 2010, Mr. Powers was an individual investor. From December 2003 to May 2009, Mr. Powers served as Vice President, Finance and Controller of Buckeye GP LLC, the general partner of Buckeye Partners, L.P. (NYSE: BPL), one of the largest refined petroleum products pipeline and terminal companies in the United States, where he was a key member of the senior executive team and was principally responsible for Buckeye's accounting, financial reporting, planning and analysis and treasury functions. He also served Buckeye GP LLC as Acting Chief Financial Officer from July 2007 until November 2008, where he was additionally responsible for capital markets activities and investor relations. He held similar positions with MainLine Management LLC, the general partner of Buckeye GP Holdings L.P. (NYSE: BGH), and participated in BGH's initial public offering in August 2006. Mr. Powers holds a MBA degree from Lehigh University and a BA from Gettysburg College. He is also a Certified Public Accountant in Pennsylvania.

Mark D. Casaday—Mr. Casaday is our Chief Operating Officer. He served as an Executive Vice President of Penn Virginia Resource GP LLC at PVR Partners LP from June 2012 to March 2014 and its Chief Operating Officer—Midstream of Penn Virginia Resource GP LLC from January 2013 to March 2014. Mr. Casaday served as Chief Operating Officer, Midstream of Marcellus at Penn Virginia Resource GP LLC, the General Partner of Penn Virginia Resource Partners LP from June 2012 to January 2013. From 1998 to February 2012, Mr. Casaday served as President and Chief Executive Officer of Pentex Natural Gas Company. Mr. Casaday also serves as Chief Operating Officer of Mainline Energy Partners, LLC.

Rick J. Staples—Mr. Staples is our Executive Vice President and Chief Commercial Officer, responsible for the marketing, trading and commercial operation of our natural gas storage assets. Previously, Mr. Staples was in the role of Senior Vice President, Commercial Operations from May 2006 to April 2012. He has 28 years of experience in the energy industry, with a primary focus on the midstream sector, including natural gas storage. Prior to joining us in 2006, Mr. Staples served as Director of Gas Storage with TransCanada Pipelines Ltd. from 2001 to 2006. Mr. Staples graduated from the University of Alberta with a degree in Mechanical Engineering. Mr. Staples also graduated from the Queens Executive program (Queens School of Business) in 1997. 73

Robert B. Wallace—Mr. Wallace is our Vice President of Finance and Corporate Development. He served as the Chief Financial Officer and Executive Vice President of PVG GP LLC from March 2010 to March 2014. Mr. Wallace served as Chief Financial Officer and Executive Vice President of Penn Virginia Resource GP LLC, the General Partner of Penn Virginia GP Holdings LP and Penn Virginia

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~~Resource Partners LP~~ Rick ~~since~~J. ~~March 2010~~Staples—Mr. Staples Heis ~~served~~our asExecutive ~~Senior~~ Vice President ~~of Finance~~ and Chief ~~Financial~~Commercial Officer, ofresponsible ~~Buckeye~~for ~~Pipe~~the ~~Line Company LLC~~marketing, atrading ~~general~~and ~~partner~~commercial operation of ~~Buckeye Partners LP~~our ~~since~~natural ~~September 1,~~gas ~~2004~~storage assets. Previously, Mr. ~~Wallace~~Staples ~~served~~was asin ~~Senior~~the ~~Vice~~role ~~President~~ of ~~Finance~~Senior ~~and~~Vice ~~Chief Financial Officer of Buckeye GP LLC~~President, ~~the~~Commercial ~~prior~~Operations ~~general~~from ~~partner of~~May ~~Buckeye~~2006 ~~Partners LP~~to ~~since~~April ~~September 2004 and served as its Principal Accounting Officer~~2012. He ~~served~~has as30 years ~~Senior~~of experience ~~Vice~~in ~~President~~the ofenergy ~~Finance~~industry, ~~and~~with ~~Chief~~a ~~Financial~~primary ~~Officer~~focus ofon ~~MainLine Management LLC,~~ the ~~General~~midstream ~~Partner~~sector, ofincluding ~~Buckeye GP~~natural ~~Holdings LP~~gas ~~since September 1, 2004~~storage. Prior to ~~UBS~~joining us in 2006, Mr. ~~Wallace~~Staples ~~held~~served ~~senior~~as ~~positions~~Director atof ~~Dean~~Gas ~~Witter~~Storage ~~Reynolds, and~~with ~~Shearson~~TransCanada ~~Lehman~~Pipelines Ltd. ~~Brothers~~from in2001 ~~New~~to ~~York~~2006. ~~He has more than 20~~Mr. ~~years~~Staples ofgraduated ~~corporate~~from ~~finance experience, was an Executive Director in~~ the ~~UBS~~University ~~Energy~~of ~~Group~~Alberta ~~from~~with ~~September 1997 to February 2004 and~~ a ~~private~~ ~~investor~~degree ~~and~~in ~~consultant~~Mechanical ~~to Buckeye GP LLC from February 2004 to September 2004~~Engineering. Mr. ~~Wallace~~Staples ~~received~~also agraduated ~~Masters of Business Administration~~ from ~~New~~the Queens ~~York~~Executive ~~University~~program ~~and~~(Queens ~~a Bachelor~~School of ~~Arts~~Business) ~~from~~in St1997. ~~Lawrence~~ ~~University.~~

Robert B. Wallace—Mr. Wallace is our Vice President of Finance and Corporate Development. He served as the Chief Financial Officer and Executive Vice President of PVG GP LLC from March 2010 to March 2014. Mr. Wallace served as Chief Financial Officer and Executive Vice President of Penn Virginia Resource GP LLC, the General Partner of Penn Virginia GP Holdings LP and Penn Virginia Resource Partners LP since March 2010. He served as Senior Vice President of Finance and Chief Financial Officer of Buckeye Pipe Line Company LLC, a general partner of Buckeye Partners LP since September 1, 2004. Mr. Wallace served as Senior Vice President of Finance and Chief Financial Officer of Buckeye GP LLC, the prior general partner of Buckeye Partners LP since September 2004 and served as its Principal Accounting Officer. He served as Senior Vice President of Finance and Chief Financial Officer of MainLine Management LLC, the General Partner of Buckeye GP Holdings LP since September 1, 2004. Prior to UBS, Mr. Wallace held senior positions at Dean Witter Reynolds, and Shearson Lehman Brothers in New York. He has more than 20 years of corporate finance experience, was an Executive Director in the UBS Energy Group from September 1997 to February 2004 and a private investor and consultant to Buckeye GP LLC from February 2004 to September 2004. Mr. Wallace also serves as Chief Financial officer of Mainline Energy Partners, LLC. Mr. Wallace received a Masters of Business Administration from New York University and a Bachelor of Arts from St. Lawrence University.

Jason A. Dubchak—Mr. Dubchak is our Vice President, General Counsel and Corporate Secretary. Mr. Dubchak has served as our Vice-President, General Counsel and Corporate Secretary since September 2007. Prior to assuming this role, Mr. Dubchak was Associate General Counsel and was continuously with the natural gas storage division of EnCana Corporation and its predecessor, Alberta Energy Company Ltd., respectively, since 2001. He has a Bachelor of Arts (Honors) from the University of Calgary and a Bachelor of Laws from the University of Alberta.

~~Bruce~~Ralph ~~D. Davis~~Alexander—Mr. ~~Davis~~Alexander is a member of our ~~Chief~~board ~~Administrative~~and ~~Officer~~serves on the compensation committee. He is a Partner of Riverstone Holdings LLC and joined Riverstone in September 2007. During 2007, Mr. Alexander served as a ~~Vice~~consultant ~~President~~to TPG Capital. For nearly 25 years, Mr. Alexander served in various positions with subsidiaries and affiliates of BP plc, one of the ~~Company~~ world's largest energy firms. HeFrom June 2004 until December 2005, he served as anChief Executive ~~Vice~~Officer ~~President~~of Innovene, ~~Secretary~~BP's $20 billion olefins and ~~General~~derivatives ~~Counsel~~subsidiary. From 2001 until June 2004, he served as Chief Executive Officer of ~~PVR GP LLC~~BP's Gas, ~~General~~Power ~~Partner~~and Renewables and Solar segment and was a member of ~~PVR~~the ~~Partners LP~~BP group ~~from~~executive ~~June~~committee. ~~2010~~Prior to ~~March~~that, ~~2014~~Mr. Alexander He served as a Group Vice President in BP's Exploration and Production segment and BP's Refinery and Marketing segment. He held ~~Secretary~~responsibilities for various regions of the world, ~~General~~including ~~Counsel~~North America, Russia, the Caspian, Africa and ~~Vice~~Latin ~~President~~America. ofPrior ~~Sunoco~~to ~~Partners~~these positions, Mr. ~~LLC~~Alexander held various positions in the upstream, downstream and finance groups of BP. In addition to serving on the ~~General~~boards ~~Partner~~of a number of ~~Sunoco~~Riverstone ~~Logistics~~portfolio companies and their affiliates, Mr. Alexander is a director of EP Energy Corporation since September 2013 and is on the Board of the general partner of Enviva Partners, LP, ~~from~~which ~~November~~had ~~2003~~an toIPO ~~June~~in ~~2010~~2015. ~~From~~He ~~September~~previously ~~2000~~served toon ~~November~~the board of Stein Mart Corporation, ~~2003~~KiOR Inc., heAmyris, Inc., ~~was~~Foster ~~Associate~~Wheeler ~~General~~AG ~~Counsel~~and ~~for~~Anglo ~~Mirant~~American plc. ~~Corporation~~He holds a B.S. ~~From~~and ~~July~~M.S. ~~1992~~in tonuclear ~~September~~engineering ~~2000,~~from heBrooklyn ~~served~~Polytech as(now ~~Associate~~NYU ~~General~~Polytechnic) ~~Counsel~~and ~~for~~holds ~~Constellation~~an ~~Energy~~M.S. in ~~Group~~management science from Stanford University. He ~~serves~~is ascurrently aChairman ~~Member~~ of the Board of ~~Directors~~NYU ofPolytechnic ~~National~~and ~~Adoption~~is ~~Center~~a New York University Trustee. The

Ralph Alexander—Mr. Alexander is a member of our board and serves on the compensation committee. He is a Partner of Riverstone Holdings LLC and joined Riverstone in September 2007. During 2007, Mr. Alexander served as a consultant to TPG Capital. For nearly 25 years, Mr. Alexander served in various positions with subsidiaries and affiliates of BP plc, one of the world's largest energy firms. From June 2004 until December 2005, he served as Chief Executive Officer of Innovene, BP's $20 billion olefins and derivatives subsidiary. From 2001 until June 2004, he served as Chief Executive Officer of BP's Gas, Power and Renewables and Solar segment and was a member of the BP group executive committee. Prior to that, Mr. Alexander served as a Group Vice President in BP's Exploration and Production segment and BP's Refinery and Marketing segment. He held responsibilities for various regions of the world, including North America, Russia, the Caspian, Africa and Latin America. Prior to these positions, Mr. Alexander held various positions in the upstream, downstream and finance groups of BP. In addition to serving on the boards of a number of Riverstone portfolio companies and their affiliates, Mr. Alexander is a director of Stein Mart Corporation since May 2007 and of EP Energy Corporation since September 2013. He previously served on the board of KiOR Inc., Amyris, Inc., Foster Wheeler AG and Anglo American plc. He holds a B.S. and M.S. in nuclear engineering from Brooklyn Polytech (now NYU Polytechnic) and holds an M.S. in management science from Stanford University. He is currently Chairman of the Board of NYU Polytechnic and is a New York University Trustee. The Company believes Mr. Alexander's extensive experience with the energy industry enables him to provide essential guidance to the board of directors. 74

Michael J. Hennigan—Mr. Hennigan is a member of our board and serves on both the audit committee and the compensation committee (as Chairman). Mr. Hennigan has been the Chief Executive Officer of Sunoco Partners LLC, a General Partner of Sunoco Logistics Partners L.P. since

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March 1, 2012 and its President since June 2010. Mr. Hennigan is responsible for all operations and business activities, including setting the direction, strategy and vision for Sunoco Logistics. He has nearly 25 years of experience with Sunoco. He served as the President of Sunoco Partners LLC since July 1, 2010. He served as the Chief Operating Officer of Sunoco Partners LLC from July 1, 2010 to March 1, 2012 and Sunoco Logistics Partners since July 1, 2010. He served as Vice President of Business Development for Sunoco Partners LLC from May 2009 to June 2010. Prior to joining Sunoco Logistics, he served as Senior Vice President of Business Improvement at Sunoco, Inc., from October 2008 to May 15, 2009 and served as its Vice President of Business Development since May 2009. He serves as a Director of Philadelphia Energy Solutions LLC. He has been a Director of Sunoco Partners LLC, a General Partner of Sunoco Logistics Partners L.P. since April 27, 2010. He served as a Director of SunCoke Energy Inc., of Jewell Coke Company~~, L.P. from June 2011 to January 17, 2012. He is Chairman of the Advisory Council for~~ ~~the College of Engineering. Mr. Hennigan holds a BS degree in Chemical Engineering from Drexel University in 1982. The Company~~ believes Mr. ~~Hennigan~~Alexander's ~~ongoing~~extensive ~~role at Sunoco Logistics Partners L.P. and past~~ experience inwith ~~Director roles in~~ the energy ~~business~~industry ~~provides~~enables ~~unique~~him ~~and~~to ~~valued~~provide essential guidance to the board of directors.

~~James~~Michael GJ. ~~Jackson~~Hennigan—Mr. ~~Jackson~~Hennigan is a member of our board and serves on both the audit ~~(as~~committee ~~Chairman),~~and the compensation ~~and~~committee ~~finance~~(as ~~committees~~Chairman). Mr. ~~Jackson~~Hennigan has been the Chief ~~Financial~~Executive Officer of ~~BreitBurn~~Sunoco Partners ~~GP,~~ LLC, ~~the~~a ~~general~~General ~~partner~~Partner of ~~BreitBurn~~Sunoco ~~Energy~~Logistics Partners L.P. ~~("BreitBurn")~~ since ~~July~~March 1, ~~2006~~2012 and anits ~~Executive Vice~~ President since June ~~October~~2010. ~~2007~~Mr. Hennigan ~~BreitBurn~~ is aresponsible ~~publicly~~for ~~traded~~all ~~master~~operations ~~limited~~and ~~partnership~~business ~~focused~~activities, onincluding setting the ~~acquisition~~direction, ~~exploitation~~strategy and ~~development~~vision for Sunoco Logistics. He has 25 years of experience ~~oil~~with ~~and~~Sunoco. ~~gas~~He ~~properties~~served inas the ~~United~~President ~~States. Mr.~~of Sunoco Partners ~~Jackson~~LLC ~~also~~since ~~currently~~July 1, ~~serves~~2010. He served as the Chief ~~Financial~~Operating Officer of ~~the~~Sunoco ~~general~~Partners LLC ~~partner~~from ~~of Pacific Coast Energy Company~~July ~~L.P.~~1, 2010 ~~("PCEC").~~to ~~PCEC~~March 1, ~~which~~2012 isand ~~BreitBurn's~~Sunoco ~~predecessor,~~Logistics isPartners ~~a privately~~since ~~held~~July 1, ~~limited~~2010. ~~partnership~~He ~~engaged~~served inas ~~the~~Vice ~~production~~President ~~and~~of ~~development~~Business ofDevelopment ~~oil~~for ~~and~~Sunoco ~~gas~~Partners LLC from ~~properties~~May ~~located~~2009 into ~~California~~June 2010. Prior ~~Before~~to joining ~~BreitBurn~~Sunoco Logistics, ~~Mr. Jackson~~he served as aSenior ~~Managing Director~~Vice inPresident ~~Merrill~~of ~~Lynch~~Business Improvement at Sunoco, ~~& Co~~Inc.'s, ~~Global~~from ~~Markets~~October 2008 to May 15, 2009 and ~~Investment~~served ~~Banking~~as ~~Group.~~its ~~Mr. Jackson~~Vice ~~joined~~President ~~Merrill~~of Business ~~Lynch~~Development insince ~~1992~~May ~~and~~2009. ~~was~~He ~~elected~~serves ~~Managing~~as a Director inof ~~2001~~Philadelphia Energy Solutions LLC. ~~Previously~~He has been a Director of Sunoco Partners LLC, a General Partner of Sunoco Logistics MrPartners L.P. since April ~~Jackson~~27, ~~was~~2010. He served as a ~~Financial~~Director ~~Analyst~~of ~~with~~SunCoke ~~Morgan~~Energy Inc., ~~Stanley~~of Jewell Coke Company, ~~& Co~~L.P. from ~~1986~~June 2011 to ~~1989~~January 17, ~~and~~2012. ~~was~~He anis ~~Associate~~Chairman of in the ~~Mergers~~Advisory ~~and~~Council ~~Acquisitions~~for ~~Group~~the College of ~~the~~Engineering. ~~Long-Term~~Mr. Hennigan ~~Credit~~holds ~~Bank~~a ofBS ~~Japan~~ degree in Chemical Engineering from ~~1989~~Drexel toUniversity ~~1990~~in 1982. The Company believes Mr. ~~Jackson~~Hennigan's ~~obtained~~ongoing role aat Sunoco BLogistics Partners L.SP. and past experience in ~~Business~~Director ~~Administration~~roles ~~from~~in ~~Georgetown~~the ~~University~~energy ~~and~~business anprovides ~~M.B.A.~~unique ~~from~~and ~~the~~valued ~~Stanford~~guidance ~~Graduate~~to ~~School~~the board of ~~Business~~directors.

James G. Jackson—Mr. Jackson is a member of our board and serves on the audit, compensation and finance committees. Mr. Jackson has been the Chief Financial Officer of BreitBurn GP, LLC, the general partner of BreitBurn Energy Partners L.P. ("BreitBurn") since July 2006 and an Executive Vice President since October 2007. BreitBurn is a publicly traded master limited partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. On May 15, 2016, BreitBurn and its affiliates filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. Mr. Jackson also currently serves as the Chief Financial Officer of the general partner of Pacific Coast Energy Company L.P. ("PCEC"). PCEC, which is BreitBurn's predecessor, is a privately held limited partnership engaged in the production and development of oil and gas from properties located in California. Before joining BreitBurn, Mr. Jackson served as a Managing Director in Merrill Lynch & Co.'s Global Markets and Investment Banking Group. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.

Mr. Jackson's background and experience with BreitBurn GP, LLC, BreitBurn Energy Partners L.P. and PCEC has provided him with valuable experience and familiarity with master limited partnerships and, more specifically, the natural gas business. These skills coupled with his broad investment banking, acquisition and financing experience brings additional depth to our board's collective expertise, and therefore makes Mr. Jackson well suited to serve as a member of our board of directors.

E. Bartow Jones—Mr. Jones is a member of our board, the board of directors of our manager, the board of supervisors of Niska Holdings, which is our parent and also serves on the finance committee. Mr. Jones is currently a Partner of Riverstone Holdings LLC where he served as a Managing director from 2010 to 2014 and as a Principal from 2007 to 2010. Mr. Jones has been with Riverstone since 2001. Mr. Jones currently serves on the boards of directors of ~~Foresight Reserves, L.P., or Foresight,~~ Vantage Energy, ~~LLC~~ Inc, or Vantage, Targe Energy, LLC, or Targe and other private companies, and he previously served on the boards of directors of the general partner of PVR Partners, L.P., Buckeye GP LLC, the general partner of Buckeye Partners, L.P., and MainLine Management LLC, the general partner of Buckeye GP Holdings L.P.

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~~Management~~directors ~~has~~of ~~given~~the ~~him~~general ~~both~~partner ~~an understanding~~ of ~~the~~PVR ~~broader~~Partners, L.P., ~~energy~~Buckeye GP LLC, ~~business~~the ~~and~~general partner of ~~the~~Buckeye ~~unique~~Partners, L.P., ~~issues~~and ~~related~~MainLine toManagement LLC, ~~operating~~the ~~publicly-traded~~general partner ~~limited~~of ~~partnerships~~Buckeye GP Holdings L.P., ~~which~~and ~~are~~Foresight ~~similar to us~~Reserves L.P.

Mr. Jones has worked closely with us since our inception. Mr. Jones's experience in evaluating the financial performance and operations of companies in our industry, as well as his leadership skills and business acumen, provide him with the necessary skills to serve as a member of our board. In addition, Mr. Jones's work with PVR Partners, L.P., Buckeye, Vantage, Targe and MainLine Management has given him both an understanding of the broader energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.

Stephen C. Muther—Mr. Muther is a member of our board and serves on both the audit committee (as Chairman) and the compensation committee. Mr. Muther served as President of the general partner of Buckeye Partners, L.P. ("BPL") and the general partner of Buckeye GP Holdings L.P. ("BGH") from October 25, 2007 until his retirement in February 2009. BPL is a publicly-traded master limited partnership that is principally engaged in the transportation, terminalling, marketing and storage of refined petroleum products for major integrated oil companies, large refined products marketing companies and major end users of petroleum products. BGH is a publicly-traded master limited partnership that owns 100% of the general partner of BPL. From February 2007 to November 2007, Mr. Muther served as Executive Vice President, Administration and Legal Affairs of the general partners of BPL and BGH, and from May 1990 to February 2007, Mr. Muther held the position of Senior Vice President, Administration, General Counsel and Secretary of the general partner of BPL. Prior to joining Buckeye, Mr. Muther was Associate Litigation and Antitrust Counsel for General Electric Company from July 1984 to May 1990. Mr. Muther was an associate attorney with Debevoise & Plimpton in New York City from February 1975 to June 1984. Mr. Muther graduated from Princeton University in 1971 and from the University of Virginia School of Law in 1974.

As a result of his service to BPL and BGH, Mr. Muther gained extensive experience in overseeing the strategy, operations, and governance of major public companies. Mr. Muther was also selected to serve as a director of our board due to his valuable legal expertise and his knowledge of the energy industry. Mr. Muther's experience has also given him knowledge of the unique issues related to operating publicly-traded limited partnerships, which are similar to us. We believe this background and skill set makes Mr. Muther well-suited to serve as a member of our board.

Andrew W. Ward—Mr. Ward is a member of our board, the board of directors of our manager, the board of supervisors of Niska Holdings, which is our parent and also serves on the finance committee. Mr. Ward has served as a member of the board of supervisors of Niska Holdings since May 2006. He is currently a Partner of Riverstone Holdings LLC where he served as a Principal from March 2002 to December 2004. Mr. Ward currently serves on the board of directors of the general partner of USA Compression Partners, LP (NYSE:USAC) and various private companies and has previously served on the boards of directors of the general partner of PVR Partners, L.P., Buckeye GP LLC, the general partner of Buckeye Partners, L.P., and MainLine Management LLC, the general partner of Buckeye GP Holdings L.P., and Gibson Energy.

Mr. Ward has served as a director since our inception. Mr. Ward's experience in evaluating the financial performance and operations of companies in our industry, combined with his leadership skills and business acumen, makes him a valuable member of our board. In addition, Mr. Ward's work with PVR Partners L.P., USA Compression Partners LP, Gibson Energy, GEP Midstream, Buckeye and MainLine Management and various private companies has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly-traded limited partnerships, which are similar to us.

Olivia C. Wassenaar—Ms. Wassenaar is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Ms. Wassenaar also serves on the finance committee. She is currently a Managing Director of Riverstone Holdings LLC where she served as a Vice President from 2008 to 2010, was promoted to a Principal in 2010, and has served as a Managing Director since 2014. In this capacity, she invests in and monitors investments in the midstream and exploration and production sectors of the energy industry. Ms. Wassenaar also serves on the board of directors of Eagle Energy Exploration LLC, Northern Blizzard Resources Inc., Talos Energy LLC, and USA Compression Partners, LP (NYSE: USAC). Prior to joining Riverstone, Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources 76

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~~investment~~ Olivia C. Wassenaar—Ms. Wassenaar is a member of our board, the board of directors of our manager and the board of supervisors of Niska Holdings, which is our parent. Ms. Wassenaar also serves on the finance committee. She is currently a Managing Director of Riverstone Holdings LLC where she served as a Vice President from 2008 to 2010, was promoted to a Principal in 2010, and has served as a Managing Director since 2014. In this capacity, she invests in and monitors investments in the midstream and exploration and production sectors of the energy industry. In addition to serving on the boards of a number of private Riverstone portfolio companies and their affiliates, Ms. Wassenaar also serves on the boards of directors of USA Compression Partners, LP (NYSE: USAC) and Northern Blizzard Resources Inc. (TSX: NBZ) Prior to joining Riverstone, Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earned an M.B.A. from the Wharton School of the University of Pennsylvania.

Our Independent Directors

Our board has determined that Stephen C. Muther, James G. Jackson and Michael J. Hennigan are independent directors under the listing standards of the NYSE. Our board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE in determining that neither of these directors has any material relationship with us, our management, our general partner or its affiliates or our subsidiaries.

We hold regularly scheduled meetings of our independent directors. In accordance with our Corporate Governance Guidelines, Mr. James Jackson presides as lead director over meetings of our independent directors.

The procedure by which any interested party may communicate directly with an independent director is set forth in our Corporate Governance Guidelines, which is available on our website at www.niskapartners.com.

Audit Committee

Our board has established an audit committee to assist it in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee is comprised of Mr. Muther, Mr. Jackson and Mr. Hennigan.

The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee discussed with our independent registered accounting firm the matters required to be discussed by Auditing Standards No. 16. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee. In addition, the audit committee has the authority to review our procedures for internal auditing, review the adequacy of internal controls and engage the services of any other advisors and accountants as the committee deems advisable. Based on the reviews and discussions referred to above, the Audit Committee recommended to the board of directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended March 31, ~~2015~~2016 for filing with the SEC.

We have designated Mr. Muther, Mr. Jackson and Mr. Hennigan as audit committee financial experts. Mr. Muther has been appointed the Chairman of the audit committee.

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Compensation Committee; Compensation Committee Interlocks and Insider Participation

As a controlled company that is listed on the NYSE, we are not required to have a compensation committee. See "—Significant Differences in Corporate Governance Standards" for a further explanation. In order to conform to best governance practices, however, our board has established a compensation committee to, among other things, oversee the compensation plans described below. The compensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibility to determine and approve, or make recommendations to the board with respect to, the compensation and benefits of our board and executive officers.

The compensation committee is composed of Mr. Shea, Mr. Muther, Mr. Jackson, Mr. Hennigan and Mr. Alexander. Mr. Hennigan has been appointed the Chairman of the compensation committee. Mr. Muther, Mr. Jackson and Mr. Hennigan are independent directors (as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act). All members of the compensation committee are non-employee directors (as that term is defined in Rule 16b-3 of the Exchange Act) except Mr. Shea, the Chairman, President and Chief Executive Officer. None of our executive officers has served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our board during 2016, 2015 or 2014.

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applicable NYSE rules and Rule 10A-3 of the Exchange Act). All members of the compensation committee are non-employee directors (as that term is defined in Rule 16b-3 of the Exchange Act) except Mr. Shea, the Chairman, President and Chief Executive Officer. None of our executive officers has served as a director or member of a compensation committee of another entity that has or has had an executive officer who served as a member of our board during 2015, 2014 or 2013.

Conflicts Committee

Whenever a conflict arises between our manager or its affiliates, on the one hand, and us or any unaffiliated member, on the other, our board will resolve that conflict. Our board may establish a conflicts committee to review specific matters that our board refers to it. Our board may, but is not required to, seek the approval of such resolution from the conflicts committee. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. Such a committee would consist of a minimum of two members, none of whom can be officers or employees of our manager or directors, officers or employees of its affiliates (other than us and our subsidiaries) and each of whom must meet the independence standards for service on an audit committee established by the NYSE and the SEC. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our manager of any duties it may owe us or our unitholders.

If our board does not seek approval from the conflicts committee, and the board determines that the resolution or course of action taken with respect to the conflict of interest is either (1) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (2) fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us, then it will be presumed that, in making its decision, our board acted in good faith, and in any proceeding brought by or on behalf of us or any member, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Reimbursement of Expenses of Our Manager

Our manager does not receive any management fee or other compensation for providing management services to us. Our manager will be reimbursed for any expenses incurred on our behalf. There is no limit on the amount of expenses for which our manager may be reimbursed.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that applies to all of our officers, directors and employees.

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Available on our website at www.niskapartners.com are copies of our Audit Committee Charter, our Compensation Committee Charter, our Code of Business Conduct and Ethics and our Corporate Governance Guidelines, all of which also will be provided to unitholders without charge upon their written request to Niska Gas Storage Partners LLC, 170 Radnor Chester Road, Suite 150 Radnor, PA 19087, Attention: General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act requires our officers and directors, and persons who own more than ten percent of a registered class of our equity securities, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the Securities and Exchange Commission. Officers, directors and greater-than-ten-percent shareowners are required by regulations promulgated by the Securities and Exchange Commission to furnish us with copies of all Forms 3, 4 and 5 they file.

80 Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during fiscal 2014 and upon a review of Forms 5 and amendments thereto furnished to us with respect to fiscal 2016, or upon written representations received by us from certain reporting persons that no Forms 5 were required for those persons, we believe that no director, executive officer or greater-than-ten-percent shareholder failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during, or with respect to, fiscal 2016.

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Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to us during fiscal 2014 and upon a review of Forms 5 and amendments thereto furnished to us with respect to fiscal 2015, or upon written representations received by us from certain reporting persons that no Forms 5 were required for those persons, we believe that no director, executive officer or greater-than-ten-percent shareholder failed to file on a timely basis the reports required by Section 16(a) of the Exchange Act during, or with respect to, fiscal 2015.

Significant Differences in Corporate Governance Standards

•: the requirement that a majority of the board consist of independent directors;
•: the requirement that we have a nominating or corporate governance committee, composed entirely of independent directors, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;
•: the requirement that we have a compensation committee of the board, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer's performance in light of the goals and objectives, determination and approval of the chief executive officer's compensation, making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity- based plans that are subject to board approval and producing a report on executive compensation to be included in an annual proxy statement or Form 10-K filed with the SEC;
•: the requirement that we conduct an annual performance evaluation of the nominating, corporate governance and compensation committees; and
•: the requirement that we have written charters for the nominating, corporate governance and compensation committees addressing the committees' responsibilities and annual performance evaluations.

In reliance on these exemptions, our board is not comprised of a majority of independent directors, nor do we maintain a nominating/corporate governance committee.

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Item 11. Executive Compensation.

Compensation Discussion and Analysis

This section describes the objectives and elements of our compensation program for the fiscal year ended March 31, ~~2015~~2016 (referred to as the "~~2015~~2016 fiscal year") for our named executive officers. This section should be read together with the compensation tables that follow, which disclose the compensation awarded to, earned by or paid to the named executive officers with respect to the ~~2015~~2016 fiscal year, as well as for certain elements of compensation paid to the named executive officers for the fiscal years ending on March 31, ~~2013~~2014 and March 31, ~~2014~~2015. See the section entitled "Executive Compensation" below. The "named executive officers" for the 2016 fiscal year, along with the title that each officer held during the 2016 fiscal year, were as follows:

Name		Title

William H. Shea, Jr.		Chairman, President and Chief Executive Officer
Vance E. Powers		Chief Financial Officer
Mark D. Casaday		Chief Operating Officer
Rick J. Staples		Executive Vice President and Chief Commercial Officer
Robert B. Wallace		Vice President, Finance and Corporate Development
Bruce D. Davis, Jr.(1)		Vice President, Chief Administrative Officer (through July 31, 2015)

~~Table~~ (1)Mr. Davis was terminated from his position of ~~Contents~~Vice President and Chief Administrative Officer on July 31, 2015.

~~Compensation"~~ ~~below.~~ Objectives ~~The~~of ~~"named~~Our ~~executive~~Executive ~~officers"~~Compensation ~~for~~Program ~~the~~and ~~2015~~Impact ~~fiscal~~of ~~year, along with~~ the ~~title that each officer held during the 2015 fiscal year, were as follows:~~ Transaction

Name		Title
William H. Shea, Jr.		Chairman, President and Chief Executive Officer
Simon Dupéré		Former President and Chief Executive Officer (through May 7, 2014)
Vance E. Powers		Chief Financial Officer
Mark D. Casaday		Chief Operating Officer
Bruce D. Davis, Jr.		Vice President, Chief Administrative Officer
Rick J. Staples		Executive Vice President and Chief Commercial Officer
Robert B. Wallace		Vice President, Finance and Corporate Development

The objectives of our executive compensation program have historically been to:

•: attract and retain the highest quality executive officers in our industry;
•: reward the executive officers as a group for the company's performance (measured among other things in terms of Adjusted EBITDA and certain non-financial health, safety and environmental measures); and
•: reward executive officers for their individual performance and contributions to our success.

On May 7, 2014, Mr. Dupéré resigned from his employment with us and from his membership on our board. In addition, on May 7, 2014, the board appointed Messrs. Shea, Casaday, Davis and Wallace to serve in the roles indicated above.

Objectives of Our Executive Compensation Program

The objectives of our executive compensation program are to:

We believe that these objectives are best met by providing a mix of cash and equity-based compensation to our executives. We believe that this mix of compensation elements provides us with a successful compensation program because it allows us to attract and retain a quality team of executives while motivating them to provide a high level of performance to us.

While these objectives remained important to us during the 2016 fiscal year, our ability to provide certain elements of compensation to our named executive officers was impacted by the impending Transaction. The Merger Agreement generally states that following the execution of that agreement on June 14, 2015, we were restricted from granting equity-based compensation awards or other incentive compensation awards that were not already outstanding as of that date. Due to the terms of the Merger Agreement, we did not grant equity-based compensation awards to any of the named executive officers during the 2016 fiscal year. The Merger Agreement also stated that our employees, including the named executive officers, generally could not receive an increase in compensation or employee benefits following the signing date of the Merger Agreement. As we had already put our annual cash bonus program in place prior to signing the Merger Agreement, the named executive officers remained eligible to receive potential bonuses under the STIP described below. The compensation restrictions set forth in the Merger Agreement will remain in place until the Transaction is completed (or the termination of the Transaction), therefore our ability to implement our historical compensation program objectives were somewhat limited by the terms of the Merger Agreement during the 2016

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fiscal year, and could continue to be limited following the 2016 fiscal year depending upon the closing date or the termination date of the Transaction, as applicable.

Setting Executive Compensation

Our manager and our board, as its delegate, ~~manage~~historically have managed our operations and activities and ~~make~~made decisions on our behalf. While our board has been delegated the authority to oversee our operations from our manager, our board has established a compensation committee to determine and set compensation practices or to make recommendations to the full board regarding compensation matters that the board has reserved final authority over, as applicable. Our Chairman, President and Chief Executive Officer is also consulted by the compensation committee and the full board regarding the compensation of the named executive officers other than himself. ~~Except~~The ~~with respect to Class D Units issued by Niska Holdings to certain of our named executive officers, the~~ compensation of each of our named executive officers for the ~~2015~~ 2016 fiscal year was originally determined and implemented solely by our compensation committee. As noted above, following our entry into the Merger Agreement, compensation decisions for the named executive officers were dictated by the terms of the Merger Agreement.

82 Effective July 1, 2015, certain of our named executive officers spend a portion of their professional time providing services to a related entity, Mainline Energy Partners LLC ("Mainline"), under a Management Services Agreement. Pursuant to the Management Services Agreement, Mainline is obligated to provide reimbursement to us or our subsidiaries for a portion of the compensation and benefit expenses incurred by us and our subsidiaries associated with the named executive officers' services, but Mainline does not provide any additional compensation to the applicable named executive officers and the Management Services Agreement has not impacted the compensation levels or compensation decisions that we make regarding the applicable named executive officers. The compensation disclosures contained herein, including the executive compensation tables that follow this Compensation Discussion and Analysis, reflect the full amount of compensation we provide to our named executive officers with no reduction for any amounts reimbursed by Mainline. For more information regarding the Management Services Agreement, please see "Certain Relationships and Related Party Transactions" below.

Our board and the compensation committee each holds the authority to engage an outside compensation consultant if it appears at any time that such assistance would be appropriate. Our compensation committee has formally engaged Frederic W. Cook and Co., Inc. ("FW Cook"), an outside compensation consultancy, to provide advice regarding our overall compensation structure, including short term and long term compensation. Although we did not seek any advice from FW Cook with respect to the 2016 fiscal year, the compensation of our named executive officers for fiscal 2016 remained substantially the same as the compensation provided to them for fiscal 2015, as a result of and subject to the compensation restrictions set forth in the Merger Agreement, and FW Cook did provide executive compensation advice to our compensation committee for the 2015 fiscal year. The compensation committee determined that the services provided by FW Cook to the compensation committee during the 2015 fiscal year did not give rise to any potential conflicts of interest. The compensation committee made this determination by assessing the independence of FW Cook under the six independence factors adopted by the SEC and incorporated into the New York Stock Exchange Corporate Governance Listing Standards.

Our board and compensation committee, with input from management employees, has historically compared certain aspects of our compensation program to the compensation programs in place at companies that we consider to be our peers. For 2015, FW Cook reviewed the most recent list of peer companies that we were using to determine if FW Cook agreed that the group continued to be appropriate for our use in evaluating compensation. The peer group that we and FW Cook determined to be appropriate for us with respect to compensation for the 2015 fiscal year includes companies in the United States market for which we believe we compete for executive talent in the energy sector. At

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~~Our board and~~ the ~~compensation committee each holds the authority to engage an outside compensation consultant if it appears at any time that such assistance~~ would be appropriate. On September 15, 2010, Cogent Compensation Partners ("Cogent") was formally engaged by our compensation committee to review our overall compensation structure, including short term and long term compensation. Cogent was acquired by Frederic W. Cook and Co., Inc. ("FW Cook"), another outside compensation consultancy, in 2012. The team that we worked with at Cogent remained intact as part of the acquisition, and FW Cook became our compensation consultant firm on and after the 2012 acquisition, including with respect to the 2015 fiscal year. The compensation committee has determined that the services provided by FW Cook to the compensation committee during the 2015 fiscal year did not give rise to any potential conflicts of interest. The compensation committee made this determination by assessing the independence of FW Cook under the six independence factors adopted by the SEC and incorporated into the New York Stock Exchange Corporate Governance Listing Standards. Our board and compensation committee, with input from management employees, has historically compared certain aspects of our compensation program to the compensation programs in place at companies that we consider to be our peers. For 2015, FW Cook reviewed the most recent list of peer companies that we were using to determine if FW Cook agreed that the group continued to be appropriate for our use in evaluating compensation. The peer group that we and FW Cook determined to be appropriate for us with respect to compensation for the 2015 fiscal year includes companies in the United States market for which we believe we compete for executive talent in the energy sector. At the beginning of the 2015 fiscal year, the compensation committee approved certain changes to the 2014 compensation peer group in establishing the peer group for 2015 fiscal year compensation purposes. Specifically, the compensation committee approved the addition of Crestwood Equity Partners LP and Summit Midstream Partners LP to the compensation peer group and removed Eagle Rock Energy Partners and El Paso Pipeline Partners from the compensation peer group for the 2015 fiscal year. Upon approval of these changes, the 2015 compensation peer group (the "Peer Group") included the following companies:

•: Altagas Ltd
•: Atlas Pipeline Partners LP
•: BlueKnight Energy Partners LP
•: Boardwalk Pipeline Partners LP
•: Buckeye Partners LP
•: Crestwood Equity Partners LP
•: DCP Midstream Partners LP
•: Enlink Midstream Partners LP
•: Genesis Energy LP
•: Keyera Corp
•: Markwest Energy Partners LP
•: Pembina Pipeline Corp
•: Regency Energy Partners LP
•: Spectra Energy Partners LP
•: Summit Midstream Partners LP

We have also in prior fiscal years utilized a separate peer group of companies for purposes of certain performance-based PUPP awards, which are measured based on our relative total unitholder return ("TUR") over a designated performance period. For purposes of performance-based Phantom Unit Performance Plan ("PUPP") awards granted prior to the 2015 fiscal year, the compensation committee moved from measuring TUR verses this designated performance peer group of companies to measuring TUR against the companies in the Alerian Natural Gas MLP Index for the duration of the applicable performance period.

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return ("TUR") over a designated performance period. For purposes of performance-based Phantom Unit Performance Plan ("PUPP") awards granted prior to the 2015 fiscal year, the compensation committee moved from measuring TUR verses this designated performance peer group of companies to measuring TUR against the companies in the Alerian Natural Gas MLP Index for the duration of the applicable performance period.

Elements of Compensation

The compensation program established by the compensation committee, in conjunction with FW Cook, for the ~~2015~~2016 fiscal year was implemented effective April 1, ~~2014~~2015. For the 2016 ~~2015~~ fiscal year, the compensation program for our named executive officers was comprised of the following key elements:

•: base salary;
•: discretionary cash bonus awards; and
•: retirement, health and welfare and related benefits.

Although we did not grant equity-based incentive awards to the named executive officers during the 2016 fiscal year due to the restrictions set forth in the Merger Agreement, the named executive officers continue to hold outstanding equity-based awards that were granted in previous years under the

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PUPP and the Niska Gas Storage Partners LLC 2010 Long Term Incentive Plan (the "LTIP") and pursuant to arrangements with Niska Holdings, all of which are described in greater detail below.

Base Salary

The compensation committee establishes base salaries for the named executive officers based on various factors, including the amounts it considers necessary to attract and retain high quality executives in our industry along with the responsibilities of the named executive officers. The compensation committee is also responsible for approving any significant changes to executive salaries. Salaries for the named executive officers are generally adjusted on an annual basis to remain competitive as compared to the market, or in connection with significant changes in duties or authorities.

84 For the 2016 fiscal year, the compensation committee determined that in light of the prior year's financial results and the challenging economics of the market over the past year, the annual base salaries for the named executive officers would remain at the rates that were approved for the 2015 fiscal year. The 2015 and 2016 fiscal year salaries were as follows:

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Name	2015 and 2016 Fiscal Year Base Salary

	(in U.S. dollars)
William H. Shea, Jr.	$	400,000
Vance E. Powers	$	298,700
Mark D. Casaday	$	320,000
Rick J. Staples(1)	$	247,815
Robert B. Wallace	$	257,680
Bruce D. Davis, Jr.(2)	$	257,680

~~For~~ (1)As a Canadian-based executive, Mr. Staples' base salary was set as $324,450 CDN for the 2015 and 2016 fiscal ~~year,~~years. ~~the~~The ~~annual~~amount ~~base~~set ~~salaries~~forth ~~for~~in the ~~named~~table above ~~executive~~reflects ~~officers~~conversion ~~(other~~to ~~than~~U.S. dollars based on an exchange rate of 0.7638 for the 2016 fiscal year. (2)Mr. ~~Dupéré,~~Davis was ~~who~~terminated ~~resigned~~from his position of Vice President and Chief Administrative Officer on ~~May~~July 731, ~~2014) were~~2015. as ~~follows:~~

Name	2014 Fiscal Year Base Salary (in U.S. dollars)(1)	2015 Fiscal Year Base Salary (in U.S. dollars)		Rationale
William H. Shea, Jr.	n/a	$	400,000	Established at time of hire consistent with compensation marketplace and as necessary to attract the officer
Vance E. Powers	$290,000	$	298,700	Reflects changes in the compensation marketplace compared to similarly situated officers in the Peer Group
Mark D. Casaday	n/a	$	320,000	Established at time of hire consistent with compensation marketplace and as necessary to attract the officer
Bruce D. Davis, Jr.	n/a	$	257,680	Established at time of hire consistent with compensation marketplace and as necessary to attract the officer
Rick J. Staples(2)	$277,358	$	285,678	Reflects outstanding performance during the 2014 fiscal year and changes in the compensation marketplace compared to similarly situated officers in the Peer Group
Robert B. Wallace	n/a	$	257,680	Established at time of hire consistent with compensation marketplace and as necessary to attract the officer

The base salary amounts paid to our named executive officers for the 2016 fiscal year are set forth in the "Salary" column of the Summary Compensation Table for 2016. As the compensation restrictions set forth in the Merger Agreement have not yet lapsed, we have not made any base salary increases for any of the named executive officers following the end of the 2016 fiscal year.

(1)Messrs. Shea, Casaday, Davis and Wallace were hired on May 7, 2014 and were not employed by the company during the 2014 fiscal year. (2)As a Canadian-based executive, Mr. Staples' base salary was set as $315,000 CDN for the 2014 fiscal year and increased to $324,450 CDN for the 2015 fiscal year. The amounts set forth in the table above reflect conversion to U.S. dollars based on an exchange rate of 0.8805.

The base salary amounts paid to our named executive officers for the 2015 fiscal year are set forth in the "Salary" column of the Summary Compensation Table for 2015.

Discretionary Bonus Awards

A significant portion of the potential compensation our named executive officers may earn for a fiscal year is determined pursuant to our discretionary annual cash bonus program. While base salaries offer an important retention element by providing a guaranteed income stream to our employees, we hope to motivate our employees to strive for both individual and overall company success by providing a substantial portion of compensation only when performance for the year calls for an additional compensatory award. Our industry has historically relied heavily on cash bonuses to compensate executive officers for performance, and we intend to compensate our executives in line with our industry trends and practices.

The annual cash bonus ~~awards~~award targets for the ~~2015~~2016 fiscal year were ~~granted~~communicated to our named executive officers pursuant to our Short Term Incentive Plan ("STIP"). While the ultimate amount of any cash bonus paid to our named executive officers under the STIP is determined at the discretion of ~~our compensation committee, the STIP awards are tied to the achievement of company financial and non-financial performance targets and a target bonus amount for each officer. The company~~

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our compensation committee, the STIP awards are tied to the achievement of company financial and non-financial performance targets and a target bonus amount for each officer. The company performance targets and each officer's target bonus amount are established by the compensation committee each year and act as guidelines for determining the amount of the bonus that may be paid to the named executive officer for that year.

We communicate the target bonus amount to our named executive officers as a certain percentage of their base salary, clearly noting that company performance on certain financial and non-financial performance targets may significantly impact what percentage of the target bonus amount is actually paid. For the ~~2015~~2016 fiscal year, the target bonus amounts for the named executive officers ~~(other than Mr. Dupéré, who resigned on May 7, 2014 and was not eligible to earn a STIP award for the 2015 fiscal year)~~ were set as follows:

Name	Target Bonus Amount ~~(in U.S. dollars)~~
	(in U.S. dollars)
William H. Shea, Jr.	$	400,000
Vance E. Powers	$	179,220
Mark D. Casaday	$	240,000
Bruce D. Davis, Jr.	$	193,260
Rick J. Staples(1)	$	185,860
Rick J. Staples(1)	$	214,259
Robert B. Wallace	$	193,260
Bruce D. Davis, Jr.(2)	$	193,260

(1)As a Canadian-based executive, Mr. Staples' target bonus amount set forth above reflects conversion to U.S. dollars based on an exchange rate of 0.~~8805~~7638. (2)Mr. Davis was terminated from his position of Vice President and Chief Administrative Officer on July 31, 2015.

The company performance metrics for the ~~2015~~2016 fiscal year STIP were a combination of financial (weighted at ninety percent (90%)) and non-financial measures (weighted at ten percent (10%)). The target goals for each company performance metric are based on internal company target goals and may be adjusted throughout the year by the compensation committee as determined appropriate upon the advice of the management team. The compensation committee has broad discretion to vary or modify any particular performance goals, which may vary between performance goals and participants.

Financial Measure. For the ~~2015~~2016 fiscal year, the company financial performance metric was net earnings before interest, income taxes, depreciation and amortization, unrealized risk management gains and losses, foreign exchange gains and losses, unrealized inventory impairment write downs, gains and losses on asset disposition, asset impairments and other income, or "Adjusted EBITDA." We believe that paying a bonus tied to our Adjusted EBITDA aligns the interests of our executives with those of our unitholders and motivates them to provide a high level of performance for us. Generally, in order for there to be any payout under the STIP for the ~~2015~~2016 fiscal year (including any payout with respect to the non-financial measures component of the STIP described below), we must first meet a minimum performance threshold of eighty-seven percent (87%) of the Adjusted EBITDA target set for the year (the "Threshold"). If we achieve the Adjusted EBITDA Threshold for the year, the payout for this component of the STIP is expected to equal fifty percent (50%) of the officer's target bonus amount attributable to the company financial measure component; if we achieve one hundred percent (100%) of the Adjusted EBITDA target set for the year, the payout for this component of the STIP is expected to equal one hundred percent (100%) of the officer's target bonus amount attributable to the company financial measure component; and if we achieve one hundred thirteen percent (113%) of the Adjusted EBITDA target set for the year, the payout for this component of the STIP is expected to equal two hundred percent (200%) of the officer's target bonus amount attributable to the company financial measure component. The achievement of the company financial performance goal between these levels will be determined using straight line interpolation.

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Non-Financial Measures. For the ~~2015~~2016 fiscal year, the company non-financial performance metrics were:

Metric	Description

Total Recordable Incident Rate ("TRIR")	Work related injuries or illnesses that must be recorded as per OSHA definition	2.5	%
Environmental Incidents	Reportable incidents that include spills, non-operational gas releases, public environmental complaints, and public odor complaints	2.5	%
Operational Availability	Measurement of the number of days our facilities are available for service, calculated as 365 days less the sum of planned or unplanned outages, divided by 365 days	2.5	%
Risk Violations	Violations assessed on "impact value," with any violation whose impact is greater than $50,000 (in U.S. dollars) included. The categories to which violations are assigned are credits, procedural, product, term, volume and open position	2.5	%

Like the financial measure component described above, the compensation committee establishes threshold, target and maximum achievement levels for each non-financial performance measure for the fiscal year. If we achieve the threshold target for the year, the payout for each non-financial metric component of the STIP is expected to equal fifty percent (50%) of the officer's target bonus amount attributable to that non-financial metric; if we achieve one hundred percent (100%) of the target for the year, the payout for each non-financial metric component of the STIP is expected to equal one hundred percent (100%) of the officer's target bonus amount attributable to that non-financial metric; and if we achieve the maximum target for the year, the payout for each non-financial metric component of the STIP is expected to equal two hundred percent (200%) of the officer's target bonus amount attributable to that non-financial metric. The achievement of the company non-financial performance goals between these levels will be determined using straight line interpolation.

Based on our actual results for the fiscal year, the compensation committee then determines the amounts to be paid to each of the named executive officers. In doing so, it reviews each officer's individual performance and also takes into account advice from FW Cook as well as from the Chairman, President and Chief Executive Officer (with respect to the other named executive officers). While the achievement of the company financial and non-financial performance targets as described above serves as a guideline for determining the annual bonus amounts for the named executive officers, the ultimate amount paid to the named executive officers under the STIP is determined at the discretion of the compensation committee, and the compensation committee may award a greater or lesser amount without regard to the achievement of the company performance targets. In exercising this discretion, the compensation committee takes into account such subjective and qualitative factors that it deems appropriate. Such factors may include, but are not limited to, extenuating market or other circumstances, individual performance, overall business performance, and the equity of STIP awards and other compensation.

Following the end of the 2015 fiscal year, the compensation committee determined that we had not achieved the Adjusted EBITDA Threshold for the 2015 fiscal year. As a result, even though we met the target level of achievement for each of the four non-financial measures, no payout under the STIP 85

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~~was~~ Following the end of the 2016 fiscal year, the compensation committee determined that we had not achieved the Adjusted EBITDA Threshold for the 2016 fiscal year. As a result, even though we met the target level of achievement for each of the four non-financial measures, no payout under the STIP was earned with respect to the company performance metrics for the ~~2015~~2016 fiscal year. The compensation committee then considered the totality of the circumstances and determined that there were no compelling reasons to exercise its discretion to adjust the percentage of the respective target bonus amounts that each named executive officer would receive based on our company's performance on the financial and non-financial measures for the ~~2015~~2016 fiscal year. Therefore, the total payout to each named executive officer under the STIP for the ~~2015~~2016 fiscal year was 0% of the officer's respective target bonus amount, and no payments were made to the named executive officers with respect to annual cash bonus awards under the STIP for the ~~2015~~2016 fiscal year.

Long Term Equity-Based Incentives

WePursuant ~~adopted~~to the ~~PUPP~~restrictions onset ~~March 24,~~forth ~~2011,~~in ~~and~~ the ~~PUPP~~Merger ~~plan document is filed as Exhibit 10.1 to our Form 8-K filed with the SEC on March 30~~Agreement, ~~2011.~~we ~~The~~did ~~PUPP~~not isgrant ~~a long~~equity-~~term~~based ~~phantom~~incentive ~~unit~~awards ~~plan for our employees and certain directors. A principal purpose of the PUPP is~~ to ~~further align~~ the ~~interests of participants, including our~~ named executive officers, ~~with~~during the ~~interests~~2016 offiscal ~~our~~year. ~~unitholders~~However, bythe ~~providing~~named ~~for~~executive ~~the~~officers ~~grant~~currently ofhold ~~phantom~~outstanding ~~unit~~equity-based awards. Athat ~~phantom~~were ~~unit~~granted isin aprevious ~~notional~~years ~~unit granted~~ under the PUPP ~~that~~ ~~represents~~and the ~~right~~Niska toGas ~~receive~~Storage Partners LLC an2010 ~~amount~~Long ~~equal~~Term Incentive toPlan (the ~~value of a common unit of the Company (a~~ "~~Unit~~LTIP"), ~~following~~and ~~the~~pursuant ~~satisfaction~~to ofarrangements ~~certain~~with ~~time-~~Niska ~~and/or performance-based criteria~~Holdings. ~~On June 7,~~The ~~2012,~~description ~~the~~provided ~~board~~below ~~approved~~is anintended ~~amendment~~ to ~~the~~provide ~~PUPP~~background toinformation ~~waive~~solely ~~the~~for ~~minimum~~awards ~~quarterly~~granted ~~distribution~~prior ~~requirement~~to ~~for~~the ~~PUPP~~2016 fiscal ~~awards~~year.

Phantom Unit Performance Plan ("PUPP"). We adopted the PUPP on March 24, 2011, and the PUPP plan document is filed as Exhibit 10.1 to our Form 8-K filed with the SEC on March 30, 2011. The PUPP is a long-term phantom unit plan for our employees and certain directors. A principal purpose of the PUPP is to further align the interests of participants, including our named executive officers, with the interests of our unitholders by providing for the grant of phantom unit awards. A phantom unit is a notional unit granted under the PUPP that represents the right to receive an amount equal to the value of a common unit of the Company (a "Unit"), following the satisfaction of certain time- and/or performance-based criteria. On June 7, 2012, the board approved an amendment to the PUPP to waive the minimum quarterly distribution requirement for PUPP awards.

The PUPP is primarily administered by our compensation committee under the overall direction of our board. The compensation committee determines all of the terms and conditions of each award pursuant to the PUPP, subject to the terms and conditions required by the PUPP, and grants phantom units to eligible participants at such times as the compensation committee determines to be appropriate. Such terms and conditions are set forth in an individual phantom unit award agreement at the time of each grant of phantom units.

WeIn previous years we have typically ~~grant~~granted PUPP awards to the named executive officers and certain other key employees each fiscal year. For the 2015 fiscal year, the compensation committee determined that one hundred percent (100%) of a named executive officer's total target annual PUPP award would be based solely on time-based vesting conditions (a "time-based PUPP award"). Although in past fiscal years a portion of the total target annual PUPP awards to the named executive officers was also based upon performance-based vesting conditions (a "performance-based PUPP award"), the compensation committee determined that time-based PUPP awards were appropriate for the 2015 fiscal year in order to retain executive talent under challenging industry conditions and to align executives' interests with those of our unitholders. In addition, while PUPP awards granted in prior years provide for settlement in the form of a cash payment, the PUPP awards for the 2015 fiscal year will be settled upon vesting in our Units (granted pursuant to the LTIP) in order to create further alignment with our unitholders and to preserve available cash. Please see "—Unit Ownership Requirements" below for a discussion of certain Unit ownership guidelines adopted during the 2015 fiscal year and applicable to our named executive officers.

For the 2015 fiscal year, the compensation committee granted time-based PUPP awards in amounts intended to place each named executive officer at the median total target compensation level for similarly situated officers in the Peer Group. The dollar amount used for determining the number of Units subject to each named executive officer's time-based PUPP award for the 2015 fiscal year was based upon a percentage of the officer's base salary, as follows: (i) Mr. Shea—475%, (ii) Mr. Powers—209%, (iii) Mr. Casaday—236%, (iv) Mr. Davis—258%, (v) Mr. Staples—205%, and (vi) Mr. Wallace—258%. 86

Time-and performance-based PUPP awards are typically measured over a full three-year time period, except for awards granted during the three-year ramp-in period following the adoption of the PUPP (the 2014 fiscal year being the last year of this period). With respect to the time-based PUPP

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Time- and performance-based PUPP awards that have been granted in previous years are typically measured over a full three-year time period, except for awards granted during the three-year ramp-in period following the adoption of the PUPP (the 2014 fiscal year being the last year of this period). With respect to the time-based PUPP awards made during the 2015 fiscal year, the awards will cliff vest in three years from the date of grant and will accumulate distribution equivalent rights ("DERs") from the date of grant until payout at vesting, in each case, subject to continued employment by the named executive officer. The compensation committee has broad discretion to vary or modify any particular performance goals applicable to any performance-based PUPP awards, which may vary between performance goals and participants.

The performance-based PUPP awards granted to the named executive officers for the years prior to the 2015 fiscal year vest and are earned based upon our relative TUR measured at the end of of each annual performance period in the three-year vesting period. For annual performance periods ending after April 1, 2014, the compensation committee moved from measuring TUR verses the designated performance peer group to measuring TUR against the Alerian Natural Gas MLP Index. If we rank below the thirty-third percentile (33%) at the end of an annual performance period, the applicable portion of the performance-based PUPP awards will not vest. If we rank at the thirty-third percentile (33%) or above, a certain percentage of the applicable portion of the performance-based PUPP awards will vest in accordance with the following chart:

TUR Ranking at End of Annual Performance Period	Performance Level

75th Percentile	Maximum	200	%
50th Percentile	Target	100	%
33rd Percentile	Threshold	50	%

In addition to the satisfaction of the TUR vesting conditions described above with respect to the performance-based PUPP awards, participants must also generally be providing services to us or one of our affiliates at the end of the applicable performance period in order for the applicable portion of the performance-based PUPP award to become vested. For the 2015 time-based PUPP awards, participants must generally be providing services to us or one of our affiliates continuously through the applicable vesting date, which, as discussed above, is the third anniversary of the date of grant of the award. The compensation committee has authority to provide for accelerated vesting provisions in the event of a termination of employment or a change in control. Generally, in the event of a participant's death, disability, retirement, or termination of employment without cause, unvested PUPP awards will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates on and after the date of grant versus the number of days in the entire vesting period for the award. With respect to performance-based PUPP awards, a "target" level of performance will be applied upon any acceleration of vesting, such that a maximum of 100% of the target performance-based PUPP award will become vested. Unless otherwise provided in an individual award agreement, if we undergo a change in control and the participant's employment is terminated for certain reasons, the PUPP awards will also receive accelerated vesting and, with respect to performance-based PUPP awards, a "target" level of performance will be applied to any acceleration of vesting. ~~Please see "Executive Compensation—Potential Payments Upon Termination or Change in Control—PUPP" for additional information.~~

The previously granted PUPP awards include distribution equivalent rights or DERs. During the period the PUPP award is outstanding, any distribution that we pay to unitholders generally will also be credited to the participant in the form of additional PUPP awards. The number of additional phantom units to be credited to a participant's PUPP account will be determined by dividing the full amount of the distribution we would have made to the participant if the phantom units were non-restricted Units, by the fair market value of a Unit on the payment date of any distribution.

Portions of the performance-based PUPP awards granted in the 2013 and 2014 fiscal years during the ramp-in period described above may become eligible to vest at the end of certain annual ~~performance~~ ~~periods, including at the end of the 2015 fiscal year. Upon reviewing the relative TUR~~

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performance periods, including at the end of the 2016 fiscal year. Upon reviewing the relative TUR performance of our company for the ~~2015~~2016 fiscal year, the compensation committee determined that, with respect to the applicable portion of the performance-based PUPP awards granted in the 2013 and 2014 fiscal years, we did not achieve the threshold performance level and therefore these portions of the performance-based PUPP awards have been forfeited.

~~Niska~~2010 ~~Predecessor~~Long ~~Class B~~Term ~~Units~~Incentive Plan. InWe ~~2006,~~adopted ~~Niska~~the ~~Predecessor~~LTIP ~~issued~~in ~~Class B~~connection ~~Units~~with ~~to some of~~ our ~~employees,~~initial ~~including~~public ~~the named executive officers then employed by us~~offering. ~~The~~This ~~Class B~~plan ~~Units~~provides for ~~represented~~the ~~profits~~grant ~~interests~~of inunit ~~Niska Holdings~~options, ~~and~~unit ~~entitle~~appreciation ~~the~~rights, ~~holders~~restricted tounits, ~~share~~phantom inunits, ~~distributions~~unit byawards, ~~Niska~~performance ~~Holdings~~or ~~once~~incentive ~~the Class A~~awards ~~Units~~and inother ~~Niska~~unit-based ~~Predecessor~~awards. ~~have~~Due ~~received distributions equal~~ to ~~their~~certain ~~contributed~~adverse ~~capital~~tax consequences ~~plus~~that anmay 8%accompany ~~rate of return. As of March 31, 2010,~~ the ~~risk~~grant of ~~forfeiture~~an ~~had~~award ~~lapsed~~that ~~on all~~is ofsettled ~~the~~in ~~Class B~~actual Units ~~upon~~to ~~the~~Canadian ~~completion~~citizens, ofthis ~~the~~plan ~~time~~is ~~limitations~~largely orreserved ~~the~~for ~~achievement~~grants of ~~the~~awards ~~performance~~to ~~conditions~~our ~~associated with the units~~employees, asconsultants ~~applicable,~~ and ~~certain of our named~~ ~~executive~~directors ~~officers~~who ~~continue~~are toUnited ~~hold~~States ~~these~~citizens, ~~vested~~but ~~units~~the ~~and~~LTIP may ~~receive~~also ~~certain~~be ~~distributions~~used ~~with respect~~ to ~~these~~settle PUPP awards. Noin ~~grants of Class B Units occurred during~~ the ~~2015~~form ~~fiscal~~of ~~year. The Class B Units are equity interests in Niska Holdings and do not relate directly to~~ our Units, ~~and~~rather ~~our~~than ~~company is not responsible for making any payments, distributions or settlements to any holder relating to the Class B Units~~cash.

Niska Predecessor Class B Units. In 2006, Niska Predecessor issued Class B Units to some of our employees, including the named executive officers then employed by us. The Class B Units represented profits interests in Niska Holdings, and entitle the holders to share in distributions by Niska Holdings once the Class A Units in Niska Predecessor have received distributions equal to their contributed capital plus an 8% rate of return. As of March 31, 2010, the risk of forfeiture had lapsed on all of the Class B Units upon the completion of the time limitations or the achievement of the performance conditions associated with the units, as applicable, and certain of our named executive officers continue to hold these vested units and may receive certain distributions with respect to these awards. No grants of Class B Units occurred during the 2016 fiscal year. The Class B Units are equity interests in Niska Holdings and do not relate directly to our Units, and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class B Units.

Class D Units in Niska Holdings. In connection with their respective appointments to serve as executive officers of the company, Niska Holdings issued Class D Units to Messrs. Shea, Casaday, Davis and Wallace. The Class D Units are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle the holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. The Class D Units vest over a five-year period, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. Certain additional information regarding the Class D Units awarded to Messrs. Shea, Casaday, Davis and Wallace during the 2015 fiscal year, which we have classified as "Option Awards" for purposes of these disclosures, is provided in the section entitled "Executive Compensation" below. However, as the Class D Units are equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements to all holders relating to the Class D Units.

2010 Long Term Incentive Plan. We adopted the 2010 Long Term Incentive Plan in connection with our initial public offering. This plan provides for the grant of unit options, unit appreciation rights, restricted units, phantom units, unit awards, performance or incentive awards and other unit-based awards. Due to certain adverse tax consequences that may accompany the grant of an award that is settled in actual Units to Canadian citizens, this plan is largely reserved for grants of awards to our employees, consultants and directors who are United States citizens.

Other Compensation Items

Health and Welfare Benefits. All of our regular full-time employees, including our named executive officers, receive certain health and welfare benefits. The benefits include a health and dental plan, a short- and long-term disability plan, basic and optional life insurance, and basic and optional accidental death and dismemberment insurance coverage.

Retirement and Pension Benefits. Our registered retirement savings plan, or RRSP Plan/Non-Registered Employee Savings Plan, provides Canadian resident employees, including certain of our named executive officers, with an opportunity to participate in a retirement savings plan. This plan is a Canadian retirement plan with features similar to a 401(k) plan or an individual retirement account administered in the United States. Our employees, including our named executive officers who are ~~Canadian citizens, are allowed to contribute their own funds, and we will, regardless of an employee's own contribution level, contribute 8% of an employee's base salary into the employee's RRSP Plan~~

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~~account~~Canadian citizens, are allowed to contribute their own funds, and we will, regardless of an employee's own contribution level, contribute 8% of an employee's base salary into the employee's RRSP Plan account, as well as make discretionary employer contributions on their behalf from time to time. Our named executive officers who are United States citizens are eligible to participate in a U.S. 401(k) plan, which allows each participant to contribute his own funds to his plan account, and the company provides up to a 5% match to the plan on his behalf. Further, in addition to this ~~contribution~~ matching contribution, the company also provides a 6% contribution regardless of any employee contribution.

Perquisites. We provide our named executive officers with certain perquisites that we believe are in line with industry standards, as well as with benefits and perquisites similar to those provided by members of the Peer Group within our geographic region, and which we believe are necessary to remain competitive with regard to overall executive compensation. During the ~~2015~~2016 fiscal year, certain of our named executive officers received additional payments to be applied to expenses for home computers, club memberships (including memberships to industry organizations) and other personal expenses, as well as a monthly automobile allowance and paid parking at our office facilities.

Employment Agreements and Severance and Change in Control Benefits

On May 7, 2014, our company entered into an employment agreement with each of Messrs. Shea, Casaday, Davis and Wallace. In addition, on June 5, 2015, our company entered into a similar employment agreement with Mr. Powers, our other U.S.-based executive officer. Each employment agreement has a three-year initial term and will automatically renew for successive one-year renewal terms unless either party provides written notice of non-renewal at least 30 days prior to the end of the initial term or any renewal term. Each employment agreement also sets forth the officer's annualized base salary and his eligibility for discretionary bonus compensation and equity awards and provides for certain separation payments and benefits in the event the officer's employment is terminated under certain specified circumstances. The employment agreements with Messrs. Shea, Casaday, Davis and Wallace are filed as exhibits to our Form 8-K filed with the SEC on May 13, 2014, and the employment agreement with Mr. Powers is filed as an exhibit to our Form 8-K filed with the SEC on June 5, 2015.

We did not have employment agreements with any of our other named executive officers during the ~~2015~~2016 fiscal year ~~(other than Mr~~. ~~Dupéré,~~ ~~whose employment agreement terminated in connection with his resignation on May 7, 2014).~~ However, the PUPP awards granted to each named executive officer during the 2015 fiscal year and prior fiscal years contain termination and change of control provisions. With respect to the outstanding PUPP awards, we have provided severance and change in control protections to serve as a retention tool. In connection with the Transaction, we have also entered into a retention plan that could impact the vesting and settlement provisions of the PUPP awards for certain Canadian-based named executive officers, described in greater detail below.

We believe that the post-termination payments in the employment agreements and the PUPP agreements, as applicable, allow our officers to focus their attention and energy on making the best objective business decisions that are in our interest, and in the interest of our unitholders, without allowing personal considerations to influence the decision-making process. Executive officers at other companies in our industry and the general market against which we compete for executive talent commonly have post-termination and/or change in control provisions, and we have consistently provided these benefits to our executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry. Please see "Executive Compensation—Potential Payments Upon Termination and Change in Control" for additional information.

In connection with his ~~resignation~~termination of employment on ~~May~~July 731, ~~2014~~2015, Mr. ~~Dupéré~~Davis entered into a Separation Agreement and General Release of Claims (the "Separation Agreement") with us, pursuant to which he received the same payments to which he would be entitled upon an involuntary termination of his employment without cause under his employment agreement ~~and under the PUPP~~, in exchange for a release of all claims against us and our affiliates. ~~Additional information regarding the Separation Agreement with~~ Mr. ~~Dupéré~~Davis is also ~~provided~~entered ~~below~~into ~~under~~an ~~"Executive Compensation—Potential~~Agreement ~~Payments~~Regarding ~~Upon~~Niska ~~Termination~~Gas ~~and Change in Control."~~

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Storage Partners LLC Phantom Unit Performance Plan Awards (the "PUPP Award Payment Agreement") that addresses the outstanding PUPP awards that Mr. Davis held at the time of his termination of employment. Additional information regarding the Separation Agreement and the PUPP Award Payment Agreement with Mr. Davis is also provided below under "Executive Compensation—Potential Payments Upon Termination and Change in Control."

Retention Plan

We adopted the Niska Gas Storage Partners LLC Transaction Incentive and Retention Bonus Plan (the "Retention Plan") on June 14, 2015 in connection with the signing of the Merger Agreement. The Retention Plan may impact outstanding PUPP awards granted to certain employees, including Canadian-based executive officers such as Mr. Staples. The named executive officers other than Mr. Staples were specifically excluded from participating in the Retention Plan.

The Retention Plan will provide each participant with the opportunity to receive two retention awards: a cash retention payment (described further below) and a PUPP award carryover amount. The PUPP award carryover amount is a cash award that will be based upon the number of time-based phantom units that a participant holds at the time of the closing of the Transaction. The number of PUPP awards held by Mr. Staples that may be impacted by the Retention Plan will be determined at the time of the closing of the Transaction. If a phantom unit held by a Retention Plan participant is subject to performance-based vesting criteria, the phantom unit will be forfeited without consideration at the closing of the Transaction. In other words, if a participant does not hold any time-based phantom units at the time that the Transaction closes, they will not receive a PUPP award carryover amount in the Retention Plan. However, if the participant holds a phantom unit that is subject to time-based vesting criteria at the time of the closing of the Transaction, the phantom unit will be forfeited at the closing, but the participant will receive a cash amount in the Retention Plan that will be equal to the number of time-based vesting phantom units the participant holds immediately prior to the closing of the Transaction, multiplied by the per unit cash value of the consideration that regular Unit holders will receive in connection with the closing of the Transaction ($4.225). The PUPP award carryover account, if any, will be governed by the terms of the Retention Plan rather than the PUPP or the LTIP, but it will be subject to the same terms and conditions as those imposed upon the outstanding time-based PUPP awards that were forfeited at the closing, including vesting and payment schedules.

For additional details regarding the potential payments that Mr. Staples may receive pursuant to the Retention Plan, please see the section below titled "Executive Compensation—Potential Payments Upon Termination and Change in Control."

Unit Ownership Requirements

During the 2015 fiscal year, the compensation committee approved unit ownership requirements for our executive officers. The purpose of these Executive Unit Ownership Guidelines ("Ownership Guidelines"), adopted effective May 7, 2014 ("Effective Date"), is to (i) require executive officers to own our Units and thereby (ii) further align the interests of our executive officers with those of our unitholders and (iii) further promote superior management and growth of our company's business.

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Guidelines"), adopted effective May 7, 2014 ("Effective Date"), is to (i) require executive officers to own our Units and thereby (ii) further align the interests of our executive officers with those of our unitholders and (iii) further promote superior management and growth of our company's business.

Ownership Guidelines

Under the Ownership Guidelines, each executive officer is required to own Units having a value equal to the dollar amount of the applicable multiple of such executive's base salary as set forth in the table below.

Executive Position		Multiple of Base Salary

Chief Executive Officer		Five times (5x)
Other Executive Officers		Three times (3x)

Compliance with the Ownership Guidelines ~~will~~was initially be determined based upon each executive officer's base salary in effect on the Effective Date and the closing price of the Units on on the New York Stock Exchange on March 31, 2015. Thereafter, a redetermination shall be made every year on March 31, based upon (i) the average of each executive officer's base salary for the determination period and (ii) the average of the high and low closing prices of the Units on the New York Stock Exchange on March 31 of the calendar year in which the redetermination is made.

Executive officers must satisfy the Ownership Guidelines no later than five years following (i) the Effective Date, for those executive officers employed as of the Effective Date; or (ii) for new executive officers, the officer's date of hire or date of promotion into an executive position. If an executive officer does not meet the Ownership Guidelines within the time period set forth above, the executive officer will be promptly notified and will have until the next redetermination period to meet the Ownership Guidelines. If at the time of redetermination the executive officer still does not meet the Ownership Guidelines, then the executive officer will be required to retain all Units owned by the executive officer, including all restricted or phantom units, until the Ownership Guidelines are met.

Credited Units

For purposes of determining compliance with the Ownership Guidelines, each of the following qualifies as ownership of Units:

•: Units owned (whether acquired in the open market, vested restricted units, issued in connection with vested phantom units, Units held in 401(k) accounts or otherwise);
•: unvested restricted units and unvested phantom units, in each case, subject to time-based vesting conditions; and
•: Units beneficially owned in a trust or by a spouse and/or minor children.

Unvested restricted units or unvested phantom units, in each case, subject to performance-based vesting conditions, are not considered Units for purposes of meeting the Ownership Guidelines.

Administration

The Ownership Guidelines are administered by the compensation committee. The compensation committee may, at any time, amend, modify or terminate the Ownership Guidelines in whole or in part, including, if the Ownership Guidelines would place a severe hardship on an executive officer, by developing alternative Unit ownership guidelines that reflects both the intention of the Ownership Guidelines and the personal circumstances of the executive officer.

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Tax and Securities Issues

We maintain an insider trading policy that is applicable to our directors and employees, including our named executive officers, which, among other things, prohibits such individuals from entering into short sales or from buying or selling puts, calls or other derivative securities in our Units. We also have generally designed our long term incentive program according to the tax effects that certain awards could have upon our employees. For Canadian citizens, grants of certain equity awards could create immediate adverse tax consequences, so we typically provide Canadian citizens with phantom units under the PUPP.

Report of the Compensation Committee

In light of the foregoing, as required by Item 407(e)(5) of Regulation S-K, our compensation committee has reviewed and discussed the Compensation Discussion and Analysis with our management and, based on such review and discussions, has recommended to the board of directors that the Compensation Discussion and Analysis be included in this annual report.

By the Compensation Committee:
Michael Hennigan, Chairman
Ralph Alexander
James G. Jackson
Stephen C. Muther
William H. Shea, Jr.

Executive Compensation

The following tables, footnotes and the above narratives provide information regarding the compensation, benefits and equity holdings of the named executive officers.

Summary Compensation for Years Ended March 31, ~~2015~~2016, ~~2014~~2015 and ~~2013~~2014

The year "~~2013~~2014" refers to the fiscal year beginning April 1, ~~2012~~2013 and ending March 31, ~~2013~~2014; the year "~~2014~~2015" refers to the fiscal year beginning April 1, ~~2013~~2014 and ending March 31, ~~2014~~2015; and the year "~~2015~~2016" refers to the fiscal year beginning April 1, ~~2014~~2015 and ending March 31, ~~2015~~2016. With respect to Canadian-based named executive officers, compensation was paid primarily in Canadian dollars but is reported in U.S. dollars in the tables and footnotes that follow. An exchange rate of (i) 0.~~9989~~9497 U.S. dollars for each Canadian dollar was used for ~~2013~~2014 amounts (the average exchange rate for the period as reported by the Bank of Canada), (ii) 0.~~9497~~8805 U.S. dollars for each Canadian dollar was used for ~~2014~~2015 amounts (the average exchange rate for the period as reported by the Bank of Canada), and (iii) 0.~~8805~~7638 U.S. dollars for each Canadian dollar was used for ~~2015~~2016 amounts (the average exchange rate for the period as reported by the Bank of Canada). Amounts reported as "Option Awards" in the tables and footnotes that follow relate to Class D Units in Niska Holdings that do not relate directly to

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our Units and for which our company is not responsible for making any payments, distributions or settlements.

Name and Principal Position
William H. Shea, Jr.	~~2015~~2016	~~360~~400,~~769~~000	0	~~1,901,854~~—	~~344,904~~—	4357,~~079~~153	2457,~~650,606~~153
Chairman, President and
Chairman, President and Chief	2015	360,769	0	1,901,854	344,904	43,079	2,650,606
Chief Executive Officer
Executive Officer
Simon Dupéré(5)(6)	2015	88,360	—	—	—	6,719,224	6,807,584
Vance E. Powers	2016	298,700	0	—	—	55,982	354,682
Former President and	2014	479,599	0	1,598,661	—	46,861	2,125,121
Chief Financial Officer	2015	298,700	0	624,003	—	100,698	1,023,401
Chief Executive Officer	2013	495,800	583,642	2,680,382	—	49,926	3,809,750
	2014	290,000	282,750	435,000	—	90,447	1,098,197
Vance E. Powers	2015	298,700	0	624,003	—	100,698	1,023,401
Mark D. Casaday	2016	320,000	0	—	—	43,194	363,194
Chief Financial Officer	2014	290,000	282,750	435,000	—	90,447	1,098,197
Chief Operating Officer	2015	288,615	0	755,385	344,904	25,290	1,414,194
	2013	287,436	201,318	635,000	—	79,093	1,202,847
Rick J. Staples(5)	2016	247,815	0	—	—	46,803	294,618
Mark D. Casaday	2015	288,615	0	755,385	344,904	25,290	1,414,194
Executive Vice President and	2015	285,678	0	665,265	—	53,685	1,004,628
Chief Operating Officer
Chief Commercial Officer	2014	299,156	364,596	747,889		57,117	1,468,758
Bruce D. Davis, Jr.	2015	232,407	0	665,260	98,544	21,690	1,017,901
Robert B. Wallace	2016	257,680	0	—	—	35,677	293,357
Vice President, Chief
Vice President, Finance and	2015	232,407	0	665,260	197,088	21,716	1,116,471
Corporate Development
Bruce D. Davis, Jr.(6)	2016	85,893	0	164,570	—	567,948	818,411
Former Vice President, Chief	2015	232,407	0	665,260	98,544	21,690	1,017,901
Administrative Officer
Rick J. Staples(5)	2015	285,678	0	665,265	—	53,685	1,004,628
Executive Vice President and	2014	299,156	364,596	747,889		57,117	1,468,758
Chief Commercial Officer	2013	312,412	273,040	1,086,304		60,091	1,731,847
Robert B. Wallace	2015	232,407	0	665,260	197,088	21,716	1,116,471
Vice President, Finance
and Corporate Development

(1)As described above under "Compensation Discussion and Analysis—Elements of Compensation—Discretionary Bonus Awards," we did not attain the Adjusted EBITDA Threshold for the ~~2015~~2016 fiscal year and the compensation committee, after considering the totality of the circumstances, determined not to make any payments to our named executive officers with respect to the discretionary annual cash bonus awards under the STIP for the ~~2015~~2016 fiscal year. (2)Amounts reported as "Unit Awards" for 2015 and ~~prior~~2014 ~~years~~ represent the grant date fair value of phantom unit awards under the PUPP determined in accordance with FASB ASC Topic 718, rather than the amounts that may actually be paid to each named executive officer upon vesting and settlement of an award. ~~For 2015, only time-based PUPP awards were granted to the named executive officers.~~ Pursuant to SEC rules, the amounts shown exclude the effect of estimated forfeitures and, with respect to the performance-based PUPP awards ~~granted in years prior to 2015~~, are based upon the probable outcome of the associated performance conditions at the grant date. Additional details regarding the calculation of the value reported for phantom unit awards under the PUPP are included in Note 1415 of the Notes to our Consolidated Financial Statements. Although PUPP awards are reported as "Unit Awards" above when granted, any PUPP awards granted prior to the 2015 fiscal year ~~that~~ are ~~still outstanding will be~~ settled, if at all, in cash payments rather than actual Units. The treatment of the phantom unit awards previously granted to Mr. Davis in fiscal 2015 (the full FASB ASC Topic 718 grant date fair value of which was reported in the "Unit Awards" column for 2015) in connection with his termination of employment on July 31, 2015 resulted in a modification charge with respect to those awards under FASB ASC Topic 718. As a result, in accordance with SEC rules, amounts reported in the "Unit Awards" column for Mr. Davis for 2016 reflect the associated incremental fair value of the awards, computed as of the modification date in accordance with FASB ASC Topic 718. This same amount is also discussed below under "Grants of Plan Based Awards" and the value realized with respect to the portion of such awards that was settled in connection with his termination of employment is reflected in the "Options Exercised and Units Vested" table. However, none of our named executive officers, including Mr. Davis, received a grant of any equity-based incentive awards during the 2016 fiscal year due to the restrictions set forth in the Merger Agreement. (3)In connection with their respective appointments to serve as executive officers of our company, Messrs. Shea, Casaday, Davis and Wallace each received an award of Class D Units in Niska Holdings on May 7, 2014. The Class D Units are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle the holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. The Class D Units vest over a five-year period, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. We believe that, despite the fact that the Class D Units do not require the payment of an exercise price, these awards are most similar economically to stock options and, as such, they are properly classified as "options" for purposes of the SEC's executive compensation disclosure rules under the definition provided in Item 402(a)(6)(i) of Regulation S-K since these awards have "option-like features." The amounts reflected in the "Option Awards" column report the value, determined as of the grant date under FASB ASC Topic 718, of the Class D Units, which for accounting purposes are treated as profits interest awards subject to a service condition, and do not reflect the amounts, if any, that may actually be distributed to holders of the Class D Units. Further information regarding the assumptions used in the valuation of these awards is included in Note 15 of the Notes to our Consolidated Financial Statements. However, as equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements to all holders relating to the Class D Units.

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~~stock options and, as such, they are properly classified as "options" for purposes of the SEC's executive compensation disclosure rules under the definition provided in Item 402~~(a)(6)(i) of Regulation S-K since these awards have "option-like features." The amounts reflected in the "Option Awards" column report the value, determined as of the grant date under FASB ASC Topic 718, of the Class D Units, which for accounting purposes are treated as profits interest awards subject to a service condition, and do not reflect the amounts, if any, that may actually be distributed to holders of the Class D Units. Further information regarding the assumptions used in the valuation of these awards is included in Note 14 of the Notes to our Consolidated Financial Statements. However, as equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements to all holders relating to the Class D Units. (4)Amounts disclosed in the "All Other Compensation" column for the ~~2015~~2016 fiscal year consist of the following items and amounts:

Executive Officer
William H. Shea, Jr.	2343,~~833~~999	—	—	—	137,~~462~~347	5,~~784~~807	—	—	4357,~~079~~153
Simon Dupéré	3,648	—	—	—	—		—	6,715,576	6,719,224
Vance E. Powers	31,612	—	12,000	—	6,780	5,590	—	—	55,982
Vance E. Powers	32,750	—	36,000	—	7,389	24,059	500	—	100,698
Mark D. Casaday	31,200	—	—	—	7,347	4,647	—	—	43,194
Mark D. Casaday	8,800	—	—	—	12,222	4,268	—	—	25,290
Rick Staples	19,825	14,588	9,324	2,832	—	—	234	—	46,803
Bruce D. Davis, Jr.	7,086	—	—	—	11,237	3,367	—	—	21,690
Robert B. Wallace	24,587	—	—	—	7,347	3,743	—	—	35,677
Rick Staples	22,854	16,818	10,566	3,187	—		260	—	53,685
Bruce D. Davis, Jr.	9,448	—	—	—	3,364	8,715	—	546,421	567,948
Robert B. Wallace	7,086	—	—	—	11,256	3,374	—	—	21,716

(a)~~The~~In ~~severance~~connection ~~payments~~with ~~made~~his totermination of employment on July 31, 2015, Mr. ~~Dupéré~~Davis inreceived ~~connection~~the ~~with~~payments to which he was entitled upon an involuntary termination without cause under his ~~resignation~~employment onagreement dated May 7, 2014. ~~consist~~These payments consisted of (i) a ~~lump~~severance ~~sum~~ payment in the aggregate amount of $~~961~~515,~~442 CDN ($846~~360,~~550~~ ~~U.S.),~~ less applicable taxes, withholdings and any other legal standard deductions, and (ii) a$31,061 ~~lump~~in ~~sum~~health ~~payment~~insurance ofpremium ~~$6,577,184~~costs ~~CDN~~for ~~($5,791,211~~COBRA ~~U.S.)~~continuation tocoverage during fiscal 2016 under our group ~~redeem~~health care plan for the period August 2015 through March 2016, which were paid by us on Mr. ~~Dupéré~~Davis's ~~vested~~behalf. In addition, 19,868 PUPP phantom ~~unit~~units ~~awards~~held ~~under~~by Mr. Davis became vested upon his termination of employment and were settled in the ~~PUPP~~form of common units. Mr. Davis' 28,478 ~~including~~remaining PUPP phantom units ~~that~~will ~~vested~~vest upon the closing of the Transaction. The treatment of these phantom unit awards in connection with ~~his~~Mr. Davis's ~~resignation,~~termination ~~and~~of ~~(iii)~~ employment resulted in a ~~lump~~modification ~~sum payment~~charge inwith ~~the~~respect ~~amount~~to ofthose ~~$88,376~~awards ~~CDN~~under ~~($77,815~~FASB UASC Topic 718.S. See note (2) to the "Summary Compensation Table" above for more information. All unvested Class D Units held by Mr. Davis were forfeited upon his ~~accrued,~~termination ~~unused~~of ~~vacation~~employment ~~time~~and his vested Class D Units were repurchased by Niska Holdings for $0.00.

(5)~~These~~Mr. Staples is one of our Canadian-based ~~named~~ executive officers. ~~were~~Canadian-based executives are paid primarily in Canadian dollars; ~~but~~however, ~~their~~ compensation is is reported in the Summary Compensation Table in U.S. dollars in accordance with the exchange rates described in the paragraph preceding the table. (6)Mr. ~~Dupéré~~Davis was ~~resigned~~terminated from his ~~employment~~position ~~with~~of usVice President and ~~from~~Chief ~~his~~Administrative ~~membership~~Officer on ~~our board on May~~July 731, ~~2014~~2015.

Grants of Plan-Based Awards

We ~~granted~~did ~~time~~not grant any plan-based awards, including any PUPP awards, toduring ~~each~~the 2016 fiscal year, and none of our named executive officers ~~during~~received ~~the~~any ~~2015~~grants ~~fiscal~~of ~~year.~~plan-based Inawards ~~addition,~~for inservices ~~connection~~provided ~~with their~~to ~~respective~~us ~~appointments~~during tothe ~~serve~~2016 asfiscal ~~executives~~year ~~officers~~from ofany ~~our~~other ~~company,~~entity. ~~Niska~~Please ~~Holdings~~see ~~issued~~"Compensation ~~Class D~~Discussion ~~Units~~and toAnalysis—Objectives of ~~Messrs. Shea,~~Our ~~Casaday,~~Executive ~~Davis~~Compensation Program and ~~Wallace~~Impact ~~during~~of the ~~2015~~Transaction" ~~fiscal~~for ~~year, which~~additional ~~Class D~~information ~~Units~~regarding ~~are~~our ~~classified~~compensation asprogram ~~"Option~~for ~~Awards" in~~ the ~~table~~2016 ~~below~~fiscal year.

95 The treatment of the phantom unit awards previously granted to Mr. Davis in fiscal 2015 (the full FASB ASC Topic 718 grant date fair value of which was reported in the "Unit Awards" column of the "Summary Compensation Table" for 2015) in connection with his termination of employment on July 31, 2015 resulted in a modification charge with respect to those awards under FASB ASC Topic 718. As a result, in accordance with SEC rules, amounts reported in the "Unit Awards" column of the "Summary Compensation Table" for Mr. Davis for 2016 reflect the associated incremental fair value of the awards, computed as of the modification date in accordance with FASB ASC Topic 718. The value realized with respect to the portion of such awards that was settled in connection with his termination of employment is reflected in the "Options Exercised and Units Vested" table.

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Class D Units in Niska Holdings do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements related to the Class D Units.

Name					Exercise or Base Price of Option Awards ($/Sh)(3)
William H. Shea, Jr.	5/7/2014	7/30/2014	124,630			1,901,854
	5/7/2014	—		280,000	n/a	344,904
Vance E. Powers	4/1/2014	7/30/2014	46,291			624,003
Mark D. Casaday	5/7/2014	7/30/2014	49,501			755,385
	5/7/2014	—		280,000	n/a	344,904
Bruce D. Davis, Jr.	5/7/2014	7/30/2014	43,595			665,260
	5/7/2014	—		80,000	n/a	98,544
Rick J. Staples	4/1/2014	7/30/2014	49,352			665,265
Robert B. Wallace	5/7/2014	7/30/2014	43,595			665,260
	5/7/2014	—		160,000	n/a	197,088

(1)The phantom units disclosed here are time-based PUPP awards and, upon vesting, such phantom units will be settled in Units. (2)The Class D Units disclosed here are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle the holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. The Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any holder relating to the Class D Units. (3)The Class D Units do not require the payment of an exercise price; however, we believe these awards are most similar economically to stock options and, as such, they are properly classified as "options" for purposes of the SEC's executive compensation disclosure rules under the definition provided in Item 402(a)(6)(i) of Regulation S-K since these awards have "option-like features." (4)The values reflected here show the grant date fair value of the time-based PUPP awards and the Class D Units reported in the table, in each case, determined in accordance with FASB ASC Topic 718, rather than the amounts, if any, that may actually be paid to each named executive officer with respect to the awards. Assumptions used to determine these amounts are disclosed in footnotes (2) and (3) to the Summary Compensation Table.

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Narrative Description to Summary Compensation Table and Grants of Plan-Based Awards

A discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table for the ~~PUPP~~2016 ~~Awards~~ fiscal year is provided above under "Compensation Discussion and Analysis."

~~The PUPP awards provided to each named executive officer may receive accelerated vesting or be forfeited upon the occurrence of certain~~ ~~events.~~ Outstanding ~~Specific~~Equity ~~details~~Awards ~~regarding~~as ~~the potential acceleration~~ of ~~vesting~~Fiscal orYear-End ~~the~~March 31, settlement of the phantom unit awards upon certain terminations of employment or a change in control are contained in the section entitled "Potential Payments Upon Termination or Change in Control" below. 2016

The ~~PUPP~~ ~~awards~~table ~~granted~~below inreflects the ~~2015~~outstanding ~~fiscal~~phantom ~~year~~unit ~~settle~~awards inunder ~~Units;~~the ~~however,~~ PUPP ~~awards~~that ~~granted~~each inof ~~prior~~our ~~fiscal~~named ~~years~~executive ~~pay~~officers ~~out~~held inas ~~cash and have special settlement features. The value~~ of ~~the~~ ~~settlement~~March 31, of2016. ~~these~~In ~~phantom~~addition, ~~awards~~it ~~will~~reflects ~~depend upon~~ the ~~average~~number ~~closing price~~ of ~~our~~outstanding ~~Units during the 30~~Class ~~day~~D ~~period~~Units ~~prior~~in toNiska ~~the~~Holdings ~~settlement~~held ~~date. The settlement date for the awards will occur on a date following the applicable vesting date that is chosen~~ by ~~the~~certain ~~compensation~~named ~~committee~~executive inofficer ~~its~~as ~~discretion in accordance with the terms~~ of ~~the~~March 31, ~~PUPP~~2016. Class D

~~Class D Unit Awards~~ 94

Class D Units were issued by Niska Holdings to Messrs. Shea, Casaday, Davis and Wallace in connection with their respective appointments to serve as executive officers of our company. Class D Units are profits interests and represent actual (non-voting) equity interests in Niska Holdings that have no value for tax purposes on the date of grant but entitle holders to share in distributions by Niska Holdings once a specified rate of return has been received by Class A holders of Niska Holdings. As equity interests in Niska Holdings, the Class D Units do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements related to the Class D Units.

The Class D Units vest over a five-year period, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. Specific details regarding the treatment of Class D Units upon certain terminations of employment are contained in the section entitled "Potential Payments Upon Termination or Change in Control" below.

Outstanding Equity Awards as of Fiscal Year-End March 31, 2015

The table below reflects the outstanding phantom unit awards under the PUPP that each of our named executive officers held as of March 31, 2015. In addition, it reflects the number of outstanding, unvested Class D Units in Niska Holdings held by certain named executive officer as of March 31,

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~~2015. Class D~~ Units in Niska Holdings do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements related to the Class D Units.

	Option Awards(1)						~~Unit Awards~~
Name	Number of Securities Underlying Unexercised Options, Unexercisable (#)		Number of Securities Underlying Unexercised Options, Exercisable (#)		Option Exercise Price ($)	Option Expiration Date	Number of Time-based Units That Have Not Vested (#)(2)		Market Value of Units That Have Not Vested ($)(3)		Equity Incentive Plan Awards: Number of Unearned Performance- based Units That Have Not Vested (#)(4)		Equity Incentive Plan Awards: Market Value of Unearned Units That Have Not Vested ($)(5)
	Number of Securities Underlying Unexercised Options, Exercisable (#)		Number of Securities Underlying Unexercised Options, Unexercisable (#)
William H. Shea, Jr.		280,000		0	n/a	n/a		138,210		247,396
							Unit Awards
Vance E. Powers								87,162		156,020		6,521		11,673
					Option Exercise Price ($)
Mark D. Casaday		280,000		0	n/a	n/a		54,896		98,264
Name						Option Expiration Date	Number of Time-based Units That Have Not Vested (#)(2)		Market Value of Units That Have Not Vested ($)(3)
Bruce D. Davis, Jr.		80,000		0	n/a	n/a		48,346		86,539
William H. Shea, Jr.		112,000		168,000	n/a	n/a		138,210	$	496,174
Rick J. Staples								112,518		201,407		11,806		21,133
Vance E. Powers		—		—				51,335	$	184,293
Robert B. Wallace		160,000		0	n/a	n/a		48,346		86,539
Mark D. Casaday		112,000		168,000	n/a	n/a		54,896	$	197,077
Rick J. Staples		—		—				54,730	$	196,481
Robert B. Wallace		64,000		96,000	n/a	n/a		48,346	$	173,662
Bruce D. Davis, Jr.		—		—				28,478	$	102,236

(1)Reflects Class D Units in Niska Holdings, which ~~vest~~became ~~over~~vested aas ~~five-year~~to 20% of the total award on May 6, 2015 and vests as to 5% of the total award on the last day of each June, September, December and March during the period commencing on June 30, 2015 and ending on March 31, 2019, generally subject to the holder's continued employment with the company, Niska Holdings or one of their respective subsidiaries. Awards reflected as "Unexercisable" are Class D Units that have not yet vested. All unvested Class D ~~(2)The outstanding~~Units ~~time-based~~previously ~~PUPP~~held ~~awards~~by ~~will~~Mr. Davis bewere ~~settled,~~forfeited ifupon athis ~~all,~~termination ~~(i) in~~of ~~Units~~employment on July 31, if2015 ~~granted~~and ~~during~~his ~~the~~vested ~~2015~~Class D ~~fiscal~~Units ~~year~~were orrepurchased by Niska Holdings for $0.00. (ii2) ~~in cash~~All ~~payments~~outstanding time-based PUPP awards will be settled, if ~~granted~~at all, in ~~prior fiscal years~~Units. Assuming that all time-based vesting conditions are met for the awards, ~~each of~~ the ~~outstanding~~ time-based PUPP awards ~~reported~~granted into ~~this~~the ~~column~~named ~~will~~executive ~~vest~~officers ~~in accordance~~during ~~with~~ the ~~following~~2015 ~~schedules: (a)The time-based~~fiscal ~~PUPP~~year ~~awards granted to Messrs. Powers and Staples on April 24, 2012~~ cliff vest on ~~April~~March 2431, ~~2015~~2017. As of March 31, ~~2015~~ 2016, ~~Messrs. Powers~~the ~~and~~named ~~Staples~~executive officers held ~~22,785~~the following ~~and~~numbers ~~34,177~~ of these units,: (a)Mr. Shea held ~~respectively~~138,210 ~~which include 6~~units,~~215~~ ~~and~~including 913,~~322~~580 additional phantom units, ~~respectively,~~ credited following the date of grant pursuant to DERs.; (b)~~The remaining time-based PUPP awards granted to Messrs~~Mr. Powers ~~and Staples on April 1, 2013 will vest on March 31, 2016. As of~~ ~~March 31, 2015, Messrs. Powers and Staples~~ held 1351,~~042~~335 ~~and 23,611 of these~~ units, ~~respectively,~~including ~~which include 2~~5,~~380~~044 ~~and 4,310~~ additional phantom units, ~~respectively,~~ credited following the date of grant pursuant to DERs.; (c)~~The~~Mr. Casady ~~time-based~~held ~~PUPP~~54,896 ~~awards~~units, ~~granted~~including to5,395 ~~the~~additional ~~named~~phantom ~~executive~~units ~~officers~~credited ~~during~~following the ~~2015~~date ~~fiscal~~of ~~year~~grant ~~cliff~~pursuant ~~vest~~to ~~on March 31, 2017. As of March 31,~~DERs; ~~2015, Messrs~~(d)Mr. ~~Powers and~~ Staples held ~~51,335 and~~ 54,730 ~~of these~~ units, ~~respectively,~~including ~~which include~~ 5,~~044 and 5,~~378 additional phantom units, ~~respectively,~~ credited ~~pursuant~~following ~~to DERs. In addition,~~ the ~~number~~date of ~~outstanding~~grant ~~time-based~~pursuant ~~PUPP~~to ~~awards~~DERs; ~~reported above for Messrs~~and (e)Mr. ~~Shea, Casaday, Davis and~~ Wallace held ~~include 13~~48,~~580,~~346 5units,~~395,~~ ~~4,751~~including ~~and~~ 4,751 additional phantom units~~, respectively,~~ credited following the date of grant pursuant to DERs. As of March 31, 2016, Mr. Davis held 28,478 remaining units that will vest upon the closing of the Transaction. (3)In accordance with SEC rules, the values reported in this column are calculated by multiplying the closing price of our Units on March 31, ~~2015~~2016 ($13.7959), by the number of outstanding time-based PUPP awards reported in the table above. ~~However, the award agreements for PUPP awards granted in fiscal years prior to 2015 require that we settle the~~ ~~awards~~ in cash using the 30 day average closing price of our Units, and the amount actually realized by a named executive officer with respect to outstanding PUPP awards may be greater or less than the values reported above depending upon the value of our Units during the 30-day period preceding the applicable settlement date and the settlement requirements set forth in the award agreements. (4)The outstanding performance-based PUPP awards reported in this column will be settled, if at all, in cash payments rather than actual Units. Assuming that all time-based and performance-based vesting conditions are met for the awards, each of the outstanding performance-based PUPP awards reported in

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this column (which includes 1,190 and 2,155 additional phantom units, respectively, credited following the date of grant pursuant to DERs) will vest on March 31, 2016. In accordance with SEC rules, the number of performance-based PUPP awards reflected in this column represents the threshold number of phantom units that could become vested. (5)In accordance with SEC rules, the values reported in this column are calculated by multiplying the closing price of our Units on March 31, 2015 ($1.79), by the threshold number of outstanding performance-based PUPP awards reported in the preceding column. However, the award agreements require that we settle the awards in cash using the 30 day average closing price of our Units, and the amount actually realized by a named executive officer with respect to these awards may be greater or less than the values reported above depending upon the value of our Units during the 30-day period preceding the applicable settlement date, our TUR performance at the end of the applicable annual performance period and the settlement requirements set forth in the award agreements.

Option Exercises and Units Vested

The table below reflects the number of time-based PUPP awards that vested during the ~~2015~~2016 fiscal year. The named executive officers did not hold any options to purchase our Units during the ~~2015~~2016 fiscal year, and no performance-based PUPP awards became vested during the ~~2015~~2016 fiscal year. ~~While~~because ~~certain~~we ~~named~~did ~~executive~~not ~~officers~~achieve ~~were awarded Class D Units, which are profits interests in Niska Holdings, during~~ the ~~2015~~threshold performance ~~fiscal~~level. ~~year~~Therefore, noall ~~Class D~~remaining ~~Units~~outstanding ~~vested~~portions ~~and~~of nopreviously ~~payments~~awarded orperformance-based ~~distributions~~PUPP ~~were made with respect to those~~ awards ~~during~~have ~~the~~been ~~2015 fiscal year~~forfeited.

Name	Number of Units Acquired on Vesting (#)(1)	Value Realized on Vesting ($)(2)
William H. Shea, Jr.
Vance E. Powers	16,887	30,228
Mark D. Casaday
Bruce D. Davis, Jr.
Rick J. Staples	30,571	54,722
Robert B. Wallace

Table ~~(1)The phantom units awarded under the PUPP that vested during the 2015 fiscal year (including 4,213 and 7,627 additional phantom units, respectively, credited following the date~~ of grant pursuant to DERs) were settled in cash payments rather than actual Units. While the awards reported in this column vested in the 2015 fiscal year, settlement of the awards occurred at a later date. (2)In accordance with SEC rules, the amounts reported in the "Value Realized on Vesting" column above were calculated using the closing price of our Units on March 31, 2015 ($1.79), which was the date of vesting. However, the award agreements require that we settle the awards in cash using the average closing price of our Units during the 30-day period preceding the applicable settlement date, which would have been $1.91 as of the March 31, 2015 settlement date. Based on the value of $1.91 per unit, Messrs. Powers and Staples received $32,354 and $58,391, respectively. Contents

While certain named executive officers hold Class D Units, which are profits interests in Niska Holdings, a portion of which vested during the 2016 fiscal year, no payments or distributions were made with respect to any Class D Units during the 2016 fiscal year.

Name		Value Realized on Vesting ($)(2)

William H. Shea, Jr.	—		—
Vance E. Powers	35,827	$	93,758
Mark D. Casaday	—		—
Rick J. Staples	57,788	$	155,168
Robert B. Wallace	—		—
Bruce D. Davis, Jr.	19,868	$	66,756

(1): The phantom units held by Mr. Powers and Mr. Staples that vested during the 2016 fiscal year (including 8,595 and 13,632 additional phantom units, respectively, credited following the date of grant pursuant to DERs) were settled in cash payments rather than actual Units. The 19,868 phantom units held by Mr. Davis that became vested upon his termination of employment were settled in the form of Units.
(2): In accordance with SEC rules, the amounts reported in the "Value Realized on Vesting" column above were calculated using the closing price of our Units on the applicable vesting date, which was (a) April 24, 2015 ($2.06), with respect to 22,785 phantom units held by Mr. Powers and 34,177 phantom units held by Mr. Staples; (b) March 31, 2016 ($3.59), with respect to 13,042 phantom units held by Mr. Powers and 23,611 phantom units held by Mr. Staples; and (c) July 31, 2015 ($3.36), with respect to the phantom units held by Mr. Davis. However, the award agreements require that we settle the awards held by Mr. Powers and Mr. Staples in cash using the average closing price of our Units during the 30-day period preceding the applicable settlement date. As result, Messrs. Powers and Staples actually received $89,170 and $147,923, respectively, with respect to the phantom units reported in this table.

Pension Benefits

We do not maintain or sponsor a defined benefit pension plan for our named executive officers.

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Nonqualified Deferred Compensation

We do not maintain or sponsor a nonqualified deferred compensation plan for our named executive officers.

Potential Payments Upon Termination or Change in Control

PUPP. The phantom units that we granted to each of our named executive officers under the PUPP during 2015 and prior fiscal years contain certain termination and change in control benefits. The PUPP participants must generally be providing services to us or one of our affiliates on an applicable vesting date in order for their award to vest, but in the event of a PUPP participant's death, "disability," "retirement," or termination of employment without "cause" (each quoted term as defined below), an unvested phantom unit ~~(whether time- or performance-based)~~ will vest on a pro rata basis by taking into account the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award. With respect to the pro-rata vesting of performance-based phantom units, a "target" level of performance (i.e., 100% payout) will be applied to the number of performance-based awards that vest on a pro-rata basis.

If we incur a "change in control" and the participant also is terminated by us (or the successor entity) other than for cause or the participant resigns as a result of a "constructive dismissal" (each quoted term as defined below), then all unvested phantom units will vest, with any performance-based vesting provisions being accelerated at the "target" performance level. 96

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Under the PUPP, the following terms have the meanings set forth below:

•: A "disability" is defined as a participant's inability, due to illness, disease, affliction, mental or physical disability or a similar cause, to perform his or her duties for any consecutive 12 month period or for any 18 month period, or a court's declaration of the participant's incompetence.
•: A "retirement" is defined as a normal or early retirement pursuant to any applicable retirement plan maintained by us at the time of the retirement.
•: "cause" is defined as any act or omission that would entitle us to terminate a participant's employment without notice or compensation under the common law for just cause, including without limitation, any improper conduct by the participant that is materially detrimental to us or the willful failure of the participant to properly carry out his or her duties on our behalf or to act in accordance with our reasonable direction.
•: A "change in control" generally will be deemed to have occurred upon (i) the acquisition by any person or group, other than us or one of our affiliates, of ownership of fifty percent (50%) or more of the outstanding shares of Niska Gas Storage Management LLC (a Delaware limited liability company and our "manager"); or (ii) a sale or other disposition of all of substantially all of our assets (or those of our affiliates) to any person other than one of our affiliates. However, the following transactions will not be deemed to result in our change in control: (a) acquisitions by investors in the manager for financing purposes; (b) an underwriter temporarily holding equity interests pursuant to a public offering of those interests; (c) any transfer of assets to an entity that is controlled by us; or (d) an acquisition by any employee benefit plan maintained by us, the manager or an affiliate of either us or the manager.
•: A "constructive dismissal" for a Canadian citizen shall be defined pursuant to the common law, which includes a material change to the executive's title, responsibilities, reporting relationship or compensation, where the termination must occur within the 45 day period following the event that gave rise to the constructive dismissal. A "constructive dismissal" for a U.S. citizen will generally be defined as our material change to the participant's title, responsibilities, reporting relationship or compensation that we do not remedy within a 30 day period of being put on notice of the condition, and where the executive then terminates within a 30 day period following the end of our cure period.

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~~notice~~ Other than with respect to Mr. Davis (whose employment actually terminated during the 2016 fiscal year and whose actual related payments are discussed below under "—Termination Benefits to Mr. Davis"), the table below shows the estimated value of the ~~condition,~~acceleration ~~and~~of ~~where~~the phantom units that each officer would have received upon certain terminations of employment. For purposes of the ~~executive~~table ~~then~~below ~~terminates~~we ~~within~~have aassumed 30that the termination of employment occurred on March ~~day~~31, ~~period~~2016 ~~following~~and our common units were valued at $3.59 (the closing ~~end~~price of ~~our~~a ~~cure~~common ~~period~~unit on March 31, 2016). The actual amount that any named executive officer will receive with respect to his phantom units, however, can only be determined upon an actual termination of employment.

As described above under "Compensation Discussion and Analysis—Employment Agreements and Severance and Change in Control Benefits," Mr. Dupéré's employment with us ended on May 7, 2014 upon his resignation. Pursuant to the Separation Agreement we entered into with Mr. Dupéré (the "Separation Agreement"), Mr. Dupéré received the same payments that he otherwise would have been entitled to under his Executive Employment Agreement dated April 24, 2012 upon an involuntary termination of employment without cause (see "Potential Payments Upon Termination or Change in Control—Mr. Dupéré Separation Agreement" below for more information) and the PUPP. Accordingly, Mr. Dupéré vested as to a number of phantom units on a pro rata basis after taking into account the number of days of actual service provided to us or one of our affiliates through Mr. Dupéré's resignation versus the number of days in the entire vesting period for the award, with a target level of performance applied for performance-based phantom units. Under the Separation Agreement, vested phantom units held by Mr. Dupéré (including phantom units that vested in connection with his resignation) were redeemed for cash in accordance with the terms of the PUPP.

Name	Termination of Employment Due to Death, Disability, Retirement, or our Termination of the Executive without Cause ($)(1)		Termination of Employment without Cause, or due to a Constructive Dismissal, in Connection with a Change in Control ($)(2)

William H. Shea, Jr.	$	235,217	$	496,174
Vance E. Powers	$	87,366	$	184,293
Mark D. Casaday	$	93,426	$	197,077
Rick J. Staples	$	93,143	$	196,481
Robert B. Wallace	$	82,279	$	173,662

~~Other~~ ~~than~~ ~~with~~ (1)The amounts ~~respect~~reflected toin ~~Mr. Dupéré,~~this ~~the~~column ~~table~~were ~~below~~calculated ~~shows~~as ~~the~~a ~~estimated~~pro-rata ~~value~~portion of the ~~acceleration~~number of ~~the~~units ~~phantom~~subject ~~units~~to ~~that~~the ~~each~~outstanding ~~officer~~time-based ~~would~~PUPP awards ~~have~~calculated ~~received~~based upon ~~certain~~the ~~terminations~~number of ~~employment.~~days ~~For purposes~~ of ~~the~~actual ~~table~~service ~~below~~provided weto ~~have~~us ~~assumed~~or ~~that~~one ~~the termination~~ of ~~employment occurred on March 31, 2015 and~~ our ~~common~~affiliates ~~units~~versus ~~were valued at $1.79 (~~the ~~closing~~number ~~price~~ of adays ~~common~~in ~~unit~~the onentire ~~March 31,~~vesting ~~2015).~~period ~~The~~for ~~actual~~the ~~amount~~award ~~that~~(such ~~any~~pro-rata ~~named~~portion ~~executive~~of ~~officer~~the number ~~will~~of ~~receive~~units ~~with~~equal ~~respect~~ to: ~~his~~for ~~phantom units~~Mr. Shea, ~~however~~65,520; ~~can~~for ~~only~~Mr. Powers, ~~be determined~~24,336; ~~upon~~for anMr. Casaday, ~~actual~~26,024; ~~termination~~for ~~of employment~~Mr. Staples, ~~With~~25,945; ~~respect~~and tofor Mr. ~~Dupéré~~Wallace, ~~the~~22,919), ~~amount~~multiplied ~~shown below discloses the amount actually received~~ by Mr$3. ~~Dupéré~~59. (2)The amounts reflected in ~~connection~~this ~~with~~column ~~the~~were ~~redemption~~calculated ofas ~~his~~the ~~phantom~~number ~~units~~of ~~that~~time-based ~~occurred~~PUPP inawards ~~connection~~reported ~~with~~for ~~his~~each ~~resignation~~named onexecutive ~~May 7,~~officer ~~2014. These cash payments to Mr. Dupéré are also included~~ above in the "~~All~~Outstanding ~~Other~~Equity ~~Compensation"~~Awards ~~column~~as of ~~the~~Fiscal ~~Summary~~Year-End ~~Compensation~~March 31, ~~Table~~2016" ~~for~~multiplied ~~2015~~by $3.59.

Name
William H. Shea, Jr	76,625	247,396
Simon Dupéré	5,791,211	—
Vance E. Powers (3)	131,792	209,593
Mark D. Casaday	30,435	98,264
Bruce D. Davis, Jr	26,803	86,539
Rick J. Staples (3)	203,476	298,393
Robert B. Wallace	26,803	86,539

Employment Agreements. On May 7, 2014, we entered into employment agreements with each of Messrs. Shea, Casaday, Davis and Wallace (the "Employment Agreements"). In addition, we entered into a similar Employment Agreement with Mr. Powers on June 5, 2015. Each Employment Agreement contains certain provisions regarding potential severance benefits. The Employment Agreements do not contain provisions regarding change in control benefits. We do not currently maintain any employment or similar agreements with any other named executive officers.

(1)Other than with respect to Mr. Dupéré, the amounts reflected in this column were calculated by using the results of the following items: (a) a pro-rata portion of the number of shares subject to each grant of time-based PUPP awards calculated based upon the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award (such pro-rata portion of the number of shares equal to: for Mr. Shea, 42,807; Mr. Powers, 48,045; Mr. Casaday, 17,003; Mr. Davis, 14,974; Mr. Staples, 67,362; and Mr. Wallace, 14,974), multiplied by $1.79; and (b) a pro-rata portion of the target number of outstanding performance-based PUPP awards, calculated based upon the number of days of actual service provided to us or one of our affiliates versus the number of days in the entire vesting period for the award (such pro-rata portion of the number of shares equal to: for Mr. Powers, 25,582

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and for Mr. Staples, 46,312), multiplied by $1.79. With respect to Mr. Dupéré, the amount reflected in this column is equal to the amount received by Mr. Dupéré in connection with the redemption of the vested phantom units held by Mr. Dupéré pursuant to the Separation Agreement. (2)The amounts reflected in this column were calculated by using the results of the following two items: (a) the number of time-based PUPP awards reported for each named executive officer above in the "Outstanding Equity Awards as of Fiscal Year-End March 31, 2015" multiplied by $1.79; and (b) the target number of performance-based PUPP awards as of March 31, 2015 multiplied by $1.79. (3)For Messrs. Powers and Staples, the values included in the table above (a) reflect the target number of certain portions of performance-based PUPP awards granted in the 2013 and 2014 fiscal years that were actually forfeited at the end of the 2015 fiscal year because the threshold performance level was not attained, and (b) do not reflect the portion of certain time-based PUPP awards granted in the 2013 and 2014 fiscal years that actually vested on March 31, 2015, which are reported in the "Options Exercised and Units Vested" table.

Employment Agreements. On May 7, 2014, we entered into employment agreements with each of Messrs. Shea, Casaday, Davis and Wallace (the "Employment Agreements"). In addition, although not in effect at the end of our last completed fiscal year, we entered into a similar Employment Agreement with Mr. Powers on June 5, 2015. Each Employment Agreement contains certain provisions regarding potential severance benefits. The Employment Agreements do not contain provisions regarding change in control benefits. We do not currently maintain any employment or similar agreements with any other named executive officers.

Upon a termination of employment by us without "cause" or by a named executive officer for "good reason," the Employment Agreements provide that the named executive officer shall generally be eligible to receive (i) 24 months of the then-current base salary for such named executive officer, less any statutory withholding, payable over a 24-month period and (ii) up to 18 months of reimbursement, on a monthly basis, of the monthly premium costs paid by the named executive officer for continuation coverage under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended ("COBRA"), provided that such reimbursement shall terminate at the time the named executive officer becomes eligible to be covered under a group health plan sponsored by another employer. In the event of a named executive officer's termination of employment for any other reason, the Employment Agreements provide that the named executive officer shall receive no further payments or benefits other than any accrued obligations.

Under the Employment Agreements, the following terms have the meanings set forth below:

•: "cause" is generally defined as the named executive officer's (i) material breach of the Employment Agreement; (ii) material breach of any other written agreement with us or an

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affiliate or certain of our policies or codes of conduct; (iii) commission of gross negligence, willful misconduct or breach of fiduciary duty; (iv) commission of fraud, theft or embezzlement; (v) conviction of, or plea of nolo contendere, to any felony or state law equivalent or any crime involving moral turpitude; or (vi) failure or refusal to perform obligations reasonably and lawfully assigned by the board.

•: "disability" is generally defined as a physical or mental infirmity that qualifies as a long-term disability under our then-applicable long-term disability insurance policy or, if no such policy is then in effect, the inability to perform the essential functions of the named executive officer's position due to an illness or physical or mental impairment or other incapacity that continues in excess of 120 days, whether or not consecutive.
•: "good reason" generally means any of the following without the named executive officer's consent: (i) a material diminution in the named executive officer's base salary (which shall be deemed to have occurred upon a reduction by 10% or more); (ii) a material diminution in the named executive officer's authority, duties, title or responsibilities; (iii) a material breach by us of any obligations under the Employment Agreement; (iv) a requirement to report to anyone other than the Chief Executive Officer or, in the case of Mr. Shea, the board; or (v) the relocation of the named executive officer's principal place of employment by more than 50 miles.

The Employment Agreements contain standard restrictive covenants. The confidentiality restriction under the Employment Agreements is perpetual. The non-competition and non-solicitation restrictions under the Employment Agreements apply during the employment period and cover the six month period following termination of employment.

In addition to the amounts noted above with respect to the phantom unit awards, if Messrs. Shea, Powers, Casaday, ~~Davis~~or ~~and~~ Wallace terminated employment for good reason or were terminated by us without cause on March 31, ~~2015~~2016, the amounts shown in the table below are the estimated payments that would become due to each of Messrs. Shea, Powers, Casaday, ~~Davis~~ and Wallace. The table below does not include payments or benefits that Messrs. Shea, Powers, Casaday, ~~Davis~~ and Wallace would be entitled to receive regardless of the reason for the termination, ~~including~~ including but not limited to: (i) accrued but unpaid base salary, (ii) accrued, but unused, vacation, (iii) accrued benefits under plans, programs and award agreements or (iv) any unreimbursed eligible expenses. Because Mr. Davis actually terminated employment during the 2016 fiscal year, the actual payments related to his termination are discussed below under "—Termination Benefits to Mr. Davis."


Mr. Shea	800,000	5860,~~936~~827	~~858~~860,~~936~~827
Mr. Casaday	640,000	60,692	700,692
Mr. Powers	597,400	55,798	653,198
Mr. Davis	515,360	68,505	583,865
Mr. Casaday	640,000	66,797	706,797
Mr. Wallace	515,360	43,~~010~~698	519,~~370~~058

(1): The amounts shown in this column assume that COBRA reimbursement will be provided for the maximum period of time (i.e., 18 months).

~~In the~~Class D ~~event~~Units Mrin Niska Holdings. The Class ~~Powers~~D isUnits ~~terminated~~that ~~from~~were issued to Messrs. Shea, Casaday, and Wallace by Niska Holdings contain certain termination provisions but do not contain any provisions directly related to a change in control of our company. If the employment of one of the Class D Unit recipients is terminated by us without "cause" or(including non-renewal of such recipient's employment agreement), by ~~Mr. Powers~~the recipient for "good reason" onor due to death or ~~after~~"disability" ~~June 5~~(each quoted term as defined above under "Potential Payments Upon Termination or Change in Control—Employment Agreements"), ~~2015~~then (i) the recipient shall forfeit, ~~effective~~without ~~date~~consideration, ofall ~~his~~Class D ~~Employment~~Units that ~~Agreement,~~have henot ~~would~~yet ~~also~~vested beas ~~entitled~~of tothe ~~severance~~date ~~payments~~of termination and ~~benefits~~(ii) for ~~under~~a ~~his~~period ~~Employment~~of ~~Agreement~~180 days asfollowing ~~described~~termination, ~~above.~~Niska

Class D Units in Niska Holdings. The Class D Units that were issued to Messrs. Shea, Casaday, Davis and Wallace by Niska Holdings contain certain termination provisions but do not contain any provisions directly related to a change in control of our company. If the employment of one of the Class D Unit recipients is terminated by us without "cause" (including non-renewal of such recipient's employment agreement), by the recipient for "good reason" or due to death or "disability" (each quoted term as defined above under "Potential Payments Upon Termination or Change in Control—Employment Agreements"), then (i) the recipient shall forfeit, without consideration, all Class D Units that have not yet vested as of the date of termination and (ii) for a period of 180 days following termination, Niska Holdings shall have the right (but not the obligation) to repurchase any or all of the vested Class D Units held by such recipient on the date of such termination at fair market value. As of March 31, 2015, none of the Class D Units held by Messrs. Shea, Casaday, Davis and Wallace had vested. Thus, assuming a termination of employment on March 31, 2015 for any reason, Messrs. Shea, Casaday, Davis and Wallace would forfeit all Class D Units. As described above, the Class D Units are equity interests in Niska Holdings, do not relate directly to our Units and our company is not responsible for making any payments, distributions or settlements to any recipient relating to the Class D Units. Niska Holdings is solely responsible for making all payments, distributions and settlements, if any, to all recipients relating to the Class D Units. 99

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~~Mr. Dupéré's~~Holdings shall ~~Separation~~have ~~Agreement. In~~the ~~connection~~right ~~with~~(but ~~his~~not ~~resignation~~the onobligation) ~~May 7,~~to ~~2014,~~repurchase ~~pursuant~~any toor all of the ~~Separation~~ ~~Agreement,~~vested ~~Mr.~~Class ~~Dupéré~~D ~~received~~Units ~~the~~held ~~same~~by ~~payments~~such ~~that~~recipient heon ~~otherwise~~the ~~would~~date ~~have~~of ~~been~~such ~~entitled~~termination toat ~~under~~fair ~~his~~market ~~employment~~value. ~~agreement~~As ~~upon~~of March 31, an2016, ~~involuntary termination~~40% of ~~employment~~the ~~without~~Class D ~~cause~~Units ~~and~~held ~~the~~by ~~PUPP~~Messrs. Shea, ~~(see~~Casaday, ~~"Potential~~and ~~Payments~~Wallace ~~Upon~~had ~~Termination~~vested. orThus, ~~Change~~assuming ina ~~Control—PUPP"~~termination ~~above~~of ~~for~~employment ~~more~~on ~~information). Specifically~~March 31, in2016 ~~accordance~~for ~~with~~one of the ~~Separation~~foregoing ~~Agreement~~reasons, MrMessrs. ~~Dupéré~~Shea, ~~received~~Casaday, aand ~~lump~~Wallace ~~sum~~would ~~cash~~forfeit ~~severance~~60% ~~payment~~ of ~~$846,550,~~their ~~which~~Class D isUnits ~~equal~~and Niska Holdings would have the right to ~~two~~repurchase ~~times~~the ~~his~~remaining ~~then-current~~40% ~~annual~~of ~~base~~the Class D ~~salary~~Units that each officer retained at fair market value, ~~less statutory~~which ~~withholding~~we ~~obligations~~estimate would be $0.00 ~~These~~as ~~cash~~of ~~payments~~March 31, ~~are~~2016. ~~also~~All ~~included~~unvested ~~above~~Class D inUnits ~~the~~held ~~"All~~by ~~Other~~Mr. Davis ~~Compensation"~~were forfeited ~~column~~upon his termination of ~~the~~employment ~~Summary~~on ~~Compensation~~July 31, ~~Table~~2015, and his vested Class D Units were repurchased by Niska Holdings for ~~2015~~$0.00.

~~Mr. Dupéré's~~As ~~employment~~described ~~agreement contained standard restrictive covenants~~above, ~~which were reaffirmed under~~ the ~~Separation Agreement. Mr.~~Class ~~Dupéré's~~D ~~non-competition~~Units ~~restrictions~~are ~~extend~~equity ~~for~~interests ain ~~twelve~~Niska ~~month~~Holdings, ~~period~~do ~~following~~not ~~Mr. Dupéré's~~relate ~~termination~~directly ofto ~~employment, and~~our ~~his~~Units ~~non-solicitation~~and ~~restrictions~~our ~~cover~~company ais ~~six~~not ~~month~~responsible ~~period~~for ~~following~~making ~~his~~any ~~termination~~payments, distributions ofor ~~employment.~~settlements Into ~~the~~any ~~event~~recipient ~~that~~relating ~~any~~to ~~law,~~the ~~government~~Class D ~~regulation~~Units. orNiska ~~stock~~Holdings ~~exchange~~is ~~listing~~solely ~~requires~~responsible usfor ~~to recover~~making ~~any~~all ~~necessary~~payments, ~~portion~~distributions ofand ~~incentive-based~~settlements, ~~compensation~~if ~~paid~~any, to ~~Mr. Dupéré,~~all recipients werelating ~~are entitled~~ to ~~recover~~ the ~~grant~~Class D ~~or payment~~Units.

Termination Benefits to Mr. Davis. In connection with his termination of employment on July 31, 2015, Mr. Davis entered into a Separation Agreement and General Release of Claims (the "Separation Agreement") with us, pursuant to which he received the same payments to which he would be entitled upon an involuntary termination of his employment without cause under his employment agreement, in exchange for a release of all claims against us and our affiliates. These payments consisted of (i) a severance payment in the aggregate amount of $515,360, less applicable taxes, withholdings and any other legal standard deductions, and (ii) $31,061 in health insurance premium costs for COBRA continuation coverage during fiscal 2016 under our group health care plan for the period August 2015 through March 2016, which were paid by us on Mr. Davis's behalf. These cash payments are also included above in the "All Other Compensation" column of the Summary Compensation Table for 2016.

Mr. Davis also entered into an Agreement Regarding Niska Gas Storage Partners LLC Phantom Unit Performance Plan Awards (the "PUPP Award Payment Agreement") that addresses the outstanding PUPP awards that Mr. Davis held at the time of his termination of employment. As described in the PUPP Award Payment Agreement, 19,868 PUPP phantom units held by Mr. Davis became vested upon his termination of employment and were settled in the form of common units. Mr. Davis' 28,478 remaining PUPP phantom units will vest upon the closing of the Transaction.

Retention Plan. We adopted the Niska Gas Storage Partners LLC Transaction Incentive and Retention Bonus Plan (the "Retention Plan") on June 14, 2015 in connection with the signing of the Merger Agreement. The Retention Plan may impact outstanding PUPP awards granted to certain employees, including Canadian-based executive officers such as Mr. Staples. The named executive officers other than Mr. Staples were specifically excluded from participating in the Retention Plan.

The Retention Plan will provide each participant with the opportunity to receive two retention awards: a cash retention payment (described further below) and a PUPP award carryover amount. The PUPP award carryover amount is a cash award that will be based upon the number of time-based phantom units that a participant holds at the time of the closing of the Transaction. The number of PUPP awards held by Mr. Staples that may be impacted by the Retention Plan will be determined at the time of the closing of the Transaction. If a participant holds a phantom unit that is subject to time-based vesting criteria at the time of the closing of the Transaction, the phantom unit will be forfeited at the closing, but the participant will receive a cash account in the Retention Plan that will be equal to the number of time-based vesting phantom units the participant holds immediately prior to the closing of the Transaction, multiplied by the per unit cash value of the consideration that regular Unit holders will receive in connection with the closing of the Transaction ($4.225). The PUPP award carryover account, if any, will be governed by the terms of the Retention Plan rather than the PUPP or the LTIP, but it will be subject to the same terms and conditions as those imposed upon the

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outstanding time-based PUPP awards that were forfeited at the closing, including vesting and payment schedules. If the closing of the Transaction had occurred on March 31, 2016, Mr. Staples would have received a $231,234 cash payment in exchange for the 54,730 time-based phantom units held by him.

The Retention Plan will also provide participants with an opportunity to receive a separate cash-based retention award that is not tied to the PUPP awards. This cash retention amount will vest on the first to occur of the closing of the Transaction or the termination date of the Merger Agreement, subject to the participant remaining continuously employed until the applicable vesting date. However, the cash retention amount would also become vested in the event that the employee is terminated without cause at any time between the date that is sixty days prior to the date of the closing of the Transaction and the actual closing date. The Retention Plan generally defines "cause" to mean (i) the occurrence of any act or omission by the participant that would qualify as an event of "cause" within the meaning of the definition of "cause" contained in any existing or future written employment agreement between the applicable participant and us, any of our subsidiaries, or their successors and assigns, (ii) the willful or negligent failure by the participant to substantially perform the participant's duties (other than any such failure resulting from a disability), (iii) the participant commits, or is convicted of or pleads no contest to, a felony or crime involving moral turpitude, (iv) the participant willfully engages in gross misconduct, (v) the participant violates our code of ethics conduct policy (or that of an affiliate), or (vi) the participant commits one or more significant acts of dishonesty as regards us or any affiliate. The cash retention amount that Mr. Staples will be eligible to earn under the Retention Plan is $195,886.69. All cash payments (including cash payments related to the conversion of PUPP awards) will be converted to Canadian currency for any Canadian residents at the time of payment based on the average exchange rate between the U.S. and Canada for the thirty day period immediately prior to the date of the applicable conversion.

Risk Assessment

Our compensation committee has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that they do encourage is not reasonably likely to have a material adverse effect on us.

Our compensation philosophy and culture support the use of base salary and certain ~~performance-based~~ compensation awards that are generally uniform in design and in operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered, and are substantially identical between our business divisions. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:

•: Our overall compensation levels are competitive with the market.
•: Our compensation mix is balanced among (i) fixed components like salary and benefits, and (ii) incentives that reward our overall financial performance and operational measures.
•: The compensation committee has discretion to reduce performance-based awards when it determines that such adjustments would be appropriate based on our interests and the interests of our unitholders.
•: Executive officers are subject to certain blackout periods, our insider trading policy and our Unit Ownership Guidelines.

Director Compensation

Officers, employees or paid consultants and advisors of our manager or its affiliates who also serve as our directors do not receive additional compensation for their service as our directors. Directors who are not officers, employees or paid consultants and advisors of our manager or its affiliates ("Eligible Directors") receive an annual cash retainer of $50,000 and receive an annual award of Units with a market value equal to $50,000, each subject to proration for partial years. In addition, Eligible Directors receive $1,500 for each board and committee meeting that they attend, other than with respect to conflicts committee meeting fees, which for 2015 were $2,500 per meeting. The chairperson of the audit committee receives an additional annual fee of $15,000. Directors serving as the chairperson of our other committees receive an additional annual fee of $10,000. Directors also receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or

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Directors") receive an annual cash retainer of $50,000 and receive an annual award of Units with a market value equal to $50,000, each subject to proration for partial years. In addition, Eligible Directors receive $1,500 for each board and committee meeting that they attend, other than with respect to conflicts committee meeting fees, which for 2016 were $2,500 per meeting. The chairpersons of our audit and compensation committees receive an additional annual fee of $15,000. Directors also receive reimbursement for out-of-pocket expenses associated with attending meetings of the board or committees and director and officer liability insurance coverage. Each director is fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law. The elements and amounts of director compensation will remain the same for the 2017 fiscal year.

~~Mr. Dupéré~~As ~~joined~~ our ~~board in connection with his appointment as our~~ Chief Executive Officer, ~~and resigned from our board on May 7, 2014, in connection with the resignation of his employment.~~ Mr. ~~Dupéré~~Shea did not receive any compensation for his service on our board during the ~~2015~~2016 fiscal year. ~~Prior to his appointment as our Chief Executive Officer, Mr. Shea served,~~ and ~~he continues to serve, on our board. Mr. Shea did not receive any compensation for his service on our board during the 2015 fiscal year and~~ all compensation provided to Mr. Shea in connection with services he performs for us in any capacity is included in the Summary Compensation Table above. Other board members that served on our board during the ~~2015~~2016 fiscal year (i.e., Ralph Alexander ~~(who was appointed to the board on December 31~~, ~~2014),~~ E. Bartow Jones, ~~George A. O'Brien (who resigned from the board on December 31, 2014),~~ Andrew W. Ward, and Olivia C. Wassenaar ~~(who was appointed to the board on July 30, 2014~~)) were not paid any compensation by us for their services as board members, as they are appointed and compensated by Riverstone, an affiliate of our manager. The compensation received by the Eligible Directors for their board service during the ~~2015~~ 2016 fiscal year, in U.S. dollars, is set forth below:

~~DIRECTOR COMPENSATION TABLE~~ 102

Name
Michael J. Hennigan(4)	36,853	28,063	0	64,916
James G. Jackson	109,500	50,096	2,528	162,124
Stephen C. Muther	124,500	50,096	626	175,222

(1)The Eligible Directors had the option of participating in the Deferred Plan (described below) for the 2015 fiscal year, thus certain cash fees reported within this column were not actually received by the Eligible Directors due to the deferral of those amounts into the Deferred Plan. Cash payments actually paid to the Eligible Directors during the 2015 fiscal year were as follows: Mr. Hennigan, $17,000; and Mr. Muther, $20,750. Mr. Jackson did not defer any cash fees to the Deferred Plan for the 2015 fiscal year. (2)Represents the aggregate grant date fair value of the fully vested Units granted to the Eligible Directors during the 2015 fiscal year, determined in accordance with FASB ASC Topic 718. On May 22, 2014, Mr. Jackson and Mr. Muther each received 1,739 common units. On November 20, 2014, Mr. Hennigan received 4,490 common units and Mr. Jackson and Mr. Muther each received 4,031 common units. As of March 31, 2015, none of the directors held any outstanding options or any outstanding, unvested equity awards. (3)Represents the above market earnings that Mr. Hennigan, Mr. Jackson, and Mr. Muther received with respect to their respective accounts within the Deferred Plan. For these purposes, earnings are considered above market if they exceed 120% of the applicable federal long-term rate, with compounding, at the time the earnings rate under the plan is set (4.54%). (4)Mr. Hennigan was appointed to the board on September 10, 2014. As a result, Mr. Hennigan received a prorated annual cash retainer and prorated award of Units for the 2015 fiscal year.

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DIRECTOR COMPENSATION TABLE

Name

Michael J. Hennigan	127,589	50,861	178,450
James G. Jackson	123,500	50,861	174,361
Stephen C. Muther	126,500	50,861	177,361

(1): The Eligible Directors had the option of participating in the Deferred Plan (described below) for the 2016 fiscal year, thus certain cash fees reported within this column were not actually received by the Eligible Directors due to the deferral of those amounts into the Deferred Plan. None of the Eligible Directors deferred any cash fees to the Deferred Plan for the 2015 calendar year. Messrs. Hennigan and Jackson also did not elect to defer any cash fees to the Deferred Plan for the 2016 calendar year; however, Mr. Muther deferred all cash fees for the 2016 calendar year. All Eligible Directors maintained an accumulated balance in the Deferred Plan as of the end of the 2016 fiscal year, but none of the Eligible Directors received above market earnings with respect to their respective accounts within the Deferred Plan for fiscal 2016. For these purposes, earnings are considered above market if they exceed 120% of the applicable federal long term rate, with compounding at the time the earnings rate under the plan is set.
(2): Represents the aggregate grant date fair value of the fully vested Units granted to the Eligible Directors during the 2016 fiscal year, determined in accordance with FASB ASC Topic 718. On May 20, 2015, Messrs. Hennigan, Jackson and Muther each received 12,462 common units. On November 19, 2015, Messrs. Hennigan, Jackson and Muther each received 7,884 common units. As of March 31, 2016, none of the directors held any outstanding options or any outstanding, unvested equity awards.

On August 10, 2011, we adopted the Niska Gas Storage Partners LLC Director Deferred Compensation Plan (the "Deferred Plan"). The purpose of the Deferred Plan is to allow us to attract and retain Eligible Directors to serve as our directors. The Deferred Plan is an unfunded arrangement intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of the Employee Retirement Income Security Act of 1974, as amended, and to comply with Section 409A of the Internal Revenue Code of 1986, as amended ("Section 409A"). Our obligations under the Deferred Plan are general unsecured obligations to pay deferred compensation in the future to Eligible Director participants in accordance with the terms of the Deferred Plan.

Participation, Deferrals and Contributions. The Deferred Plan is based on a calendar year plan year. Eligible Directors may participate in the Deferred Plan, provided that they are not residents of Canada for purposes of the Income Tax Act (Canada) and not otherwise subject to Canadian taxation under the Income Tax Act (Canada). Any such Eligible Director may become a participant (a "Participant") in the Deferred Plan for an applicable plan year by electing during the open enrollment period to defer a portion of his or her compensation on an election form. A Participant may defer a stated dollar amount, or a designated whole number percentage, up to a maximum percentage of 100% of the Participant's compensation for the applicable plan year. At the time of election, the Participant can choose to defer the compensation until either (i) termination of the Participant's board service or (ii) a future year in which the Participant is still providing services to us and that is at least two calendar years after the year in which the deferred compensation would otherwise have been paid (a "Scheduled In-Service Withdrawal"). We may also elect to make a discretionary contribution to a ~~Participant's account, which may be subject to a vesting schedule, in an amount and at such time as determined by our board.~~

Investment Options. At the time of making his or her deferral election, a Participant will also select the investment option with which the Participant would like for us to credit the Participant for basic deferrals. The Participant may select between two cash investment crediting rate options: (i) an annual rate of interest equal to one percent (1%) below the prime rate of interest as quoted by Bloomberg, compounded daily, or (ii) one or more benchmark mutual funds chosen by the plan administrator as an investment option for the Deferred Plan. Notwithstanding the preceding sentence, under the Deferred Plan, we have the discretion to choose an investment crediting rate for a Participant other than the investment crediting rate requested by the Participant; provided that such investment crediting rate cannot be less than (i) in the preceding sentence. 103

Distributions. A Participant may elect to receive a distribution of his Deferred Plan account upon a termination of service at any of the following times: (i) as soon as practicable following the termination of board service, (ii) in the first January following the termination of service, or (iii) in the second January following the termination of service. All account distributions are made in lump sum cash payments. If a Participant fails to elect the time at which his account balance will be paid out, it will be paid as soon as practicable following the termination of service. If a Participant elected to receive a Scheduled In-Service Withdrawal, the Participant may subsequently elect to delay such distribution for a minimum period of five calendar years; provided that such election is made at least 12 months prior to the date that such distribution would otherwise be made. If a Participant elected to receive a Scheduled In-Service Withdrawal and the Participant's board service is otherwise terminated prior to such distribution, the Scheduled In-Service Withdrawal will be cancelled and the entire account balance of the Participant will be paid according to the Participant's termination distribution election. In the event of an unforeseeable emergency, a Participant may apply to the plan administrator, who has sole and absolute discretion to approve such application, to request that all or a portion of the Participant's account balance be distributed prior to termination or a Scheduled In-Service Withdrawal. In the event a Participant dies while providing services to us, the Participant's account balance will be paid to the Participant's beneficiary in the manner previously elected by the Participant. The Deferred

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~~Plan~~Participant's ~~has~~account, ~~provisions~~which ~~that~~may ~~provide~~be ~~for~~subject ~~special~~to ~~distribution~~a ~~rights~~vesting ~~with~~schedule, ~~respect~~in toan ~~any~~amount ~~spousal~~and ~~claims~~at ~~made~~such ~~pursuant~~time toas adetermined ~~domestic~~by ~~relations~~our ~~order~~board.

Investment Options. At the time of making his or her deferral election, a Participant will also select the investment option with which the Participant would like for us to credit the Participant for basic deferrals. The Participant may select between two cash investment crediting rate options: (i) an annual rate of interest equal to one percent (1%) below the prime rate of interest as quoted by Bloomberg, compounded daily, or (ii) one or more benchmark mutual funds chosen by the plan administrator as an investment option for the Deferred Plan. Notwithstanding the preceding sentence, under the Deferred Plan, we have the discretion to choose an investment crediting rate for a Participant other than the investment crediting rate requested by the Participant; provided that such investment crediting rate cannot be less than (i) in the preceding sentence.

Distributions. A Participant may elect to receive a distribution of his Deferred Plan account upon a termination of service at any of the following times: (i) as soon as practicable following the termination of board service, (ii) in the first January following the termination of service, or (iii) in the second January following the termination of service. All account distributions are made in lump sum cash payments. If a Participant fails to elect the time at which his account balance will be paid out, it will be paid as soon as practicable following the termination of service. If a Participant elected to receive a Scheduled In-Service Withdrawal, the Participant may subsequently elect to delay such distribution for a minimum period of five calendar years; provided that such election is made at least 12 months prior to the date that such distribution would otherwise be made. If a Participant elected to receive a Scheduled In-Service Withdrawal and the Participant's board service is otherwise terminated prior to such distribution, the Scheduled In-Service Withdrawal will be cancelled and the entire account balance of the Participant will be paid according to the Participant's termination distribution election. In the event of an unforeseeable emergency, a Participant may apply to the plan administrator, who has sole and absolute discretion to approve such application, to request that all or a portion of the Participant's account balance be distributed prior to termination or a Scheduled In-Service Withdrawal. In the event a Participant dies while providing services to us, the Participant's account balance will be paid to the Participant's beneficiary in the manner previously elected by the Participant. The Deferred Plan has provisions that provide for special distribution rights with respect to any spousal claims made pursuant to a domestic relations order.

Administration. The Deferred Plan is administered by our board of directors, or a plan administrator that our board may appoint, which we refer to as the plan administrator. The plan administrator directly administers the Deferred Plan and has the right to adopt rules of procedure and regulations necessary for administration of the Deferred Plan and will review and render decisions respecting claims for benefits under the Deferred Plan, among other powers and duties. The Deferred Plan may be amended, suspended, or terminated at any time by our board; provided that, no such amendment, suspension or termination may adversely impact the amount of benefits a participant has accrued under the Deferred Plan or deprive a participant of such benefits except to the extent required by applicable law. The Deferred Plan also provides for claims for benefits procedures and a review process in the event of a dispute by a Participant under the Deferred Plan.

Item 12. Security Ownership of Certain Beneficial Owners and Management.

The following table sets forth the beneficial ownership of our Units by:

•: each person known by us to be a beneficial owner of more than 5% of our outstanding Units;
•: each of our directors;
•: each of our named executive officers; and

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power 104

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•: all of our directors and executive officers as a group.

~~with~~ The ~~respect~~amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a "beneficial owner" of a security if that person has or shares "voting power," which includes the power to vote or to direct the voting of such security, or "investment power," which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them as of ~~March~~May 3124, ~~2015~~2016, subject to community property laws where applicable.

Name of Beneficial Owner
Niska Sponsor Holdings Cooperatief U.A.(1)	20,488,525	53.93	%	—	—	—
William H. Shea, Jr.	—	—
Simon Dupéré(2)	—	—		—	—	—
Vance E. Powers	2,000	*		—	—	—
Mark D. Casaday	—	—
Bruce D. Davis, Jr	—	—
Bruce D. Davis, Jr(2)	—	—
Rick J. Staples	—	—		—	—	—
Robert B. Wallace	—	—		—	—	—
Ralph Alexander(3)	—	—
Ralph Alexander	—	—
Michael J. Hennigan(4)	16,952	*
Michael J. Hennigan	30,918	*
James G. Jackson	2943,~~207~~173	*		—	—	—
E. Bartow Jones	—	—		—	—	—
Stephen C. Muther	3549,~~292~~258	*		—	—	—
Andrew W. Ward	—	—		—	—	—
Olivia Wassenaar(5)	—	—
Olivia Wassenaar	—	—
All directors and executive officers as a group (14 persons)	83,451	*		—	—	—
All directors and executive officers as a group (13 persons)	125,349	*		—	—	—

*Less than 1% (1)The equity interests in Holdco are indirectly owned by our executive officers, certain of our employees and investment limited partnerships affiliated with the Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Carlyle/Riverstone Global Energy and Power Fund III, L.P. C/R Energy GP III, LLC exercises investment discretion and control over the units held by Holdco through Carlyle/Riverstone Energy Partners III, L.P., of which C/R Energy GP III, LLC is the sole general partner. C/R Energy GP III, LLC is managed by an eight person management committee. The address of Holdco and C/R Energy GP III, LLC is 712 Fifth Avenue, 51st Floor, New York, NY 10019. (2)~~Simon Dupéré, former President, Chief Executive Officer and member of the board of directors, resigned on May 7, 2014. (3)~~Mr. ~~Alexander~~Davis was ~~appointed~~terminated tofrom ~~our~~his ~~board~~position onof ~~December 31,~~Vice ~~2014. (4)Mr. Hennigan was~~President ~~appointed~~and toChief ~~our~~Administrative ~~board~~Officer on ~~September 10, 2014. (5)Ms. Wassenaar was appointed to our board on~~ July 3031, ~~2014~~2015.

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Equity Compensation Plan Information

The following table sets forth certain information with respect to our equity compensation plans as of March 31, ~~2015~~2016.

Plan Category
Equity compensation plans approved by unitholders:
2010 Long-Term Incentive Plan	0	(1)	N/A	32,~~303~~716,~~473~~153
Equity compensation plans not approved by unitholders:
N/A	—		—	—

(1): We have not granted any options, warrants or rights pursuant to the 2010 Long-Term Incentive Plan.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Party Transactions

Holdco owns 20,488,525 common units, representing approximately 53.93% of our units and the all the incentive distribution rights. In addition, our manager owns a 1.80% managing member interest in us.

Agreements with Affiliates

Effective May 12, 2006, our subsidiary, AECO Partnership, entered into a services agreement with certain affiliates of Holdco pursuant to which it would provide employees to manage certain development projects for Holdco or its affiliates in return for a service fee that is to be agreed upon between the parties from time to time. AECO Partnership subsequently assigned its rights and obligations under the services agreement to Niska Partners Management ULC in an Amended and Restated Services Agreement.

Effective July 1, 2015, a management services agreement was established between Mainline Energy Partners, LLC ("Mainline"), REP Management Company VI, LLC, a Riverstone-related entity, and the Company, in which three US executives of Niska Partners will provide services to Mainline. Mainline will reimburse the Company for all reasonable direct and indirect costs and expenses incurred by the Company, including a portion of salaries and benefits, overhead costs and direct out-of-pocket expenses incurred by Niska Partners related to Mainline.

Policies Relating to Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our manager and its affiliates (including Holdco), on the one hand, and us and our unaffiliated members, on the other hand. Our directors and officers have fiduciary duties to manage our manager in a manner beneficial to its owners. At the same time, our manager has a fiduciary duty to manage us in a manner beneficial to our unitholders. Our Operating Agreement contains provisions that specifically define our manager's fiduciary duties to the unitholders. Our Operating Agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Limited Liability Company Act, which we refer to as the Delaware Act, provides that Delaware limited liability companies may, in their Operating Agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a manager to members and us.

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~~the~~Limited ~~power~~Liability toCompany ~~conduct our business~~Act, towhich ~~our~~we ~~board.~~refer ~~Our~~to ~~board~~as ~~may,~~the ~~but~~Delaware ~~is not required to~~Act, ~~seek~~provides ~~the~~that ~~approval~~Delaware oflimited ~~such~~liability ~~resolution~~companies ~~from~~may, ~~the~~in ~~conflicts~~their ~~committee~~Operating ofAgreements, ~~our~~expand, ~~board.~~restrict Anor ~~independent~~eliminate ~~third~~the ~~party is~~fiduciary ~~not~~duties ~~required~~otherwise toowed ~~evaluate~~by ~~the~~a ~~fairness~~manager ofto ~~the~~members ~~resolution~~and us.

Under our Operating Agreement, whenever a conflict arises between our manager or its affiliates, on the one hand, and us or any unaffiliated member or our board as our manager's delegate, on the other, our manager will resolve that conflict. Our manager has delegated this responsibility, along with the power to conduct our business, to our board. Our board may, but is not required to, seek the approval of such resolution from the conflicts committee of our board. An independent third party is not required to evaluate the fairness of the resolution.

Whenever a potential conflict of interest exists or arises between the manager or any of its affiliates, on the one hand, and us or any of our members, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our members, and shall not constitute a breach of our Operating Agreement, of any agreement contemplated, or of any duty if the resolution or course of action in respect of such conflict of interest is:

•: approved by the conflicts committee of our board, although our board is not obligated to seek such approval;
•: approved by the vote of a majority of the outstanding common units, excluding any common units owned by our manager or any of its affiliates;
•: on terms no less favorable to us than those generally being provided to or available from unaffiliated third parties; or
•: fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our board does not seek approval from the conflicts committee and determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, our board acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our Operating Agreement, our board or the conflicts committee of our board may consider any factors it determines in good faith to consider when resolving a conflict. When our Operating Agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of us, unless the context otherwise requires. See "Management" for information about the conflicts committee of our board.

The transactions described above under "—Agreements With Affiliates" were described in our registration statement relating to our IPO and deemed approved by all our members under the terms of our Operating Agreement.

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Item 14. Principal Accounting Fees and Services.

The following table presents fees for professional services rendered by KPMG LLP for ~~2015~~2016 and ~~2014~~2015:

	Year Ended March 31,
	2015		2014
	2016		2015
Audit Fees	$	1,~~322~~554,000	$	1,~~367~~322,000
Audit—Related fees		~~150,000~~—		—150,000

Total	$	1,~~472~~554,000	$	1,~~367~~472,000

Our audit committee has adopted an audit committee charter, which is available on our website at www.niskapartners.com, which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a): (1) Financial Statements

(a)(1) Financial Statements

See "Index to the Consolidated Financial Statements" set forth on Page F-1.

(2) Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3) Exhibits

EXHIBIT LIST

			Description
2.1		—	Agreement and Plan of Merger and Membership Interest Transfer Agreement, dated as of June 14, 2015, by and among Niska Gas Storage Partners LLC, Niska Gas Storage Management LLC, Niska Sponsor Holdings Coöperatief U.A., Swan Holdings LP and Swan Merger Sub LLC (incorporated by reference to Exhibit 2.1 of the Company's current report on Form 8-K filed on June 18, 2015)
3.1		—	Certificate of Formation of Niska Gas Storage Partners LLC dated January 26, 2010 (incorporated by reference to exhibit 3.1 to Amendment No. 2 to the Company's Registration Statement on Form S-1 (Registration No. 333-165007), filed on April 15, 2010)
3.2		—	Second Amended and Restated Operating Agreement of Niska Gas Storage Partners LLC, dated as of April 2, 2013 (incorporated by reference to exhibit 3.2 to the Company's Current Report on Form 8-K, filed on April 3, 2013)
4.1		—	Registration Rights Agreement between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. dated May 17, 2010 (incorporated by reference to exhibit 10.2 of the Company's Current Report on Form 8-K, filed on May 19, 2010)
4.2		—	Amendment No. 1 to Registration Rights Agreement made as of August 24, 2011, by and between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. (incorporated by reference to exhibit 4.1 of the Company's Quarterly Report on Form 10-Q, filed on November 7, 2011)
4.3		—	Indenture dated as of March 17, 2014 among Niska Gas Storage Canada ULC and Niska Gas Storage Canada Finance Corp., as issuers, each of the Guarantors party thereto, and The Bank of New York Mellon, as Trustee (incorporated by reference to exhibit 4.1 to the Company's Current Report on Form 8-K, filed on March 18, 2014)
10.1	†	—	Niska Gas Storage Partners LLC 2010 Long-Term Incentive Plan effective as of May 16, 2010 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 19, 2010)
10.2		—	Services Agreement dated March 5, 2010 among AECO Gas Storage Partnership, Niska GS Holdings US, L.P. and Niska GS Holdings Canada L.P. (incorporated by reference to exhibit 10.3 to Amendment No. 1 to the Company's Registration Statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
10.3		—	Amended and Restated Credit Agreement dated June 29, 2012, among Niska Gas Storage US LLC, AECO Gas Storage Partnership, Niska Gas Storage Partners LLC and Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the other Lenders and joint book managers party thereto (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on July 5, 2012)

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			Description
4.2		—	Amendment No. 1 to Registration Rights Agreement made as of August 24, 2011, by and between Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöperatief U.A. (incorporated by reference to exhibit 4.1 of the Company's Quarterly Report on Form 10-Q, filed on November 7, 2011)
4.3		—	Indenture dated as of March 17, 2014 among Niska Gas Storage Canada ULC and Niska Gas Storage Canada Finance Corp., as issuers, each of the Guarantors party thereto, and The Bank of New York Mellon, as Trustee (incorporated by reference to exhibit 4.1 to the Company's Current Report on Form 8-K, filed on March 18, 2014)
10.1†		—	Niska Gas Storage Partners LLC 2010 Long-Term Incentive Plan effective as of May 16, 2010 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 19, 2010)
10.2		—	Services Agreement dated March 5, 2010 among AECO Gas Storage Partnership, Niska GS Holdings US, L.P. and Niska GS Holdings Canada L.P. (incorporated by reference to exhibit 10.3 to Amendment No. 1 to the Company's Registration Statement on Form S-1 (Registration No. 333-165007), filed on March 29, 2010)
10.3		—	Amended and Restated Credit Agreement dated June 29, 2012, among Niska Gas Storage US LLC, AECO Gas Storage Partnership, Niska Gas Storage Partners LLC and Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the other Lenders and joint book managers party thereto (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on July 5, 2012)
10.4		—	Sponsor Equity Restructuring Agreement by and among Niska Gas Storage Partners LLC and Niska Sponsor Holdings Coöpertief U.A., dated as of April 2, 2013 (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on April 3, 2013)
10.5	†	—	Employment Agreement, dated May 7, 2014, between the Company and William H. Shea, Jr. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.6	†	—	Employment Agreement, dated May 7, 2014, between the Company and Mark D. Casaday (incorporated by reference to exhibit 10.2 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.7	†	—	Employment Agreement, dated May 7, 2014, between the Company and Robert B. Wallace (incorporated by reference to exhibit 10.3 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.8	†	—	Employment Agreement, dated May 7, 2014, between the Company and Bruce D. Davis, Jr. (incorporated by reference to exhibit 10.4 of the Company's Current Report on Form 8-K, filed on May 13, 2014)
10.9	†	—	Separation Agreement and General Release of Claims, executed on June 18, 2014, between Niska Partners Management ULC and Simon Dupéré, Niska Gas Storage Partners LLC and Niska Holdings L.P. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 20, 2014)
10.10	†	—	Release and Confidentiality Agreement, dated as of June 25, 2014, by and between Niska Gas Storage Partners LLC and Jason Kulsky (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 30, 2014)
10.11	†		Employment Agreement, dated June 5, 2015, between the Company and Vance E. Powers. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 5, 2015)
12.1	*	—	Statement regarding computation of ratios of earnings to fixed charges
21.1	*	—	List of Subsidiaries of Niska Gas Storage Partners LLC
23.1	*	—	Consent of KPMG LLP
31.1	*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2	*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1	**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	*	—	XBRL Instance Document.
101.SCH	*	—	XBRL Taxonomy Extension Schema Document.
101.CAL	*	—	XBRL Taxonomy Extension Calculation Linkbase Document.

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			Description
10.11	†	—	Employment Agreement, dated June 5, 2015, between the Company and Vance E. Powers. (incorporated by reference to exhibit 10.1 of the Company's Current Report on Form 8-K, filed on June 5, 2015)
10.12		—	Commitment Letter, dated June 14, 2015, by and between BIF II Swan Finance Co. (Delaware) LLC and Niska Gas Storage Partners LLC (incorporated by reference to exhibit 10.1 of the Company's current report on Form 8-K filed on June 18, 2015)
10.13		—	Credit Agreement, dated as of July 28, 2015, by and between Niska Gas Storage Partners LLC, as the borrower, Swan Finance LP, as Administrative Agent and Collateral Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on July 31, 2015)
10.14		—	Separation Agreement and General Release of Claims, executed on July 31, 2015, between Bruce D. Davis, Jr., Niska Gas Storage Partners LLC, Niska Gas Transport Inc. and Niska Holdings L.P. (incorporated by reference to Exhibit 10.1 of the Company's current report on Form 8-K filed on August 4, 2015)
10.15		—	Agreement Regarding Niska Gas Storage Partners LLC Phantom Unit Performance Plan Awards, executed on July 31, 2015, between Bruce D. Davis, Jr. and Niska Gas Storage Partners LLC (incorporated by reference to Exhibit 10.2 of the Company's current report on Form 8-K filed on August 4, 2015)
10.16		—	Amendment No. 1 to Amended & Restated Credit Agreement, dated as of February 29, 2016, by and among Niska Gas Storage US, LLC and AECO Gas Storage Partnership, as borrowers, the other loan parties party thereto, Royal Bank of Canada, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company's current report on Form 8-K filed on March 1, 2016)
12.1	*	—	Statement regarding computation of ratios of earnings to fixed charges
21.1	*	—	List of Subsidiaries of Niska Gas Storage Partners LLC
23.1	*	—	Consent of KPMG LLP
31.1	*	—	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2	*	—	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1	**	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	**	—	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	*	—	XBRL Instance Document.
101.SCH	*	—	XBRL Taxonomy Extension Schema Document.
101.CAL	*	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.PRE	*	—	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF	*	—	XBRL Taxonomy Extension Definition Linkbase Document.

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Exhibit Number					Description

	101.DEF	*	—		XBRL Taxonomy Extension Definition Linkbase Document.

*: Filed herewith.
**: Furnished herewith.
†: Management contract or compensatory plan or arrangement required to be filed as an exhibit to this 10-K pursuant to Item 15(b).

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NISKA GAS STORAGE PARTNERS LLC By: /s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. Chairman, President and Chief Executive Officer and Director


	NISKA GAS STORAGE PARTNERS LLC
	By:	/s/ WILLIAM H. SHEA, JR. William H. Shea, Jr. Chairman, President and Chief Executive Officer and Director
Date: June 10, 2016

Date: June 12, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature		Title		Date
/s/ WILLIAM H. SHEA, JR. William H. Shea, Jr.		Chairman, President and Chief Executive Officer and Director (Principal Executive Officer)		June 1210,

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