UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009
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: 000-51120

Hiland Partners, LP

(Exact name of Registrant as specified in its charter)


DELAWARE (State or other jurisdiction of incorporation or organization)		71-0972724 (I.R.S. Employer Identification No.)

205 West Maple, Suite 1100 Enid, Oklahoma (Address of principal executive offices)		73701 (Zip Code)

(580) 242-6040

(Registrant’s telephone number, including area code)

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. þ Yes o No

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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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. (Check one):


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

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

The number of the registrant’s outstanding equity units as of November 5, 2009 was 6,300,624 common units, 3,060,000 subordinated units and a 2% general partnership interest.

HILAND PARTNERS, LP

INDEX


PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets	3
	Consolidated Statements of Operations	4
	Consolidated Statements of Cash Flows	5
	Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income (Loss)	6
	Condensed Notes to Consolidated Financial Statements (Unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risks	51
Item 4.	Controls and Procedures	52

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Submission of Matters to a Vote of Security Holders	56
Item 5.	Other Information	56
Item 6.	Exhibits	56
SIGNATURES		58
Certification of CEO under Section 302
Certification of CFO under Section 302
Certification of CEO under Section 906
Certification of CFO under Section 906
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

HILAND PARTNERS, LP

Consolidated Balance Sheets


	September 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands, except unit amounts)

ASSETS
Current assets:
Cash and cash equivalents	$	3,557		$	1,173
Accounts receivable:
Trade — net of allowance for doubtful accounts of $304		17,872			23,863
Affiliates		1,262			2,346

		19,134			26,209
Fair value of derivative assets		3,860			6,851
Other current assets		816			1,584

Total current assets		27,367			35,817
Property and equipment, net		322,681			345,855
Intangibles, net		29,902			35,642
Fair value of derivative assets		608			7,141
Other assets, net		1,303			1,684

Total assets	$	381,861		$	426,139


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable	$	11,221		$	22,470
Accounts payable — affiliates		4,298			7,662
Fair value of derivative liabilities		835			1,439
Accrued liabilities and other		5,466			2,463

Total current liabilities		21,820			34,034
Commitments and contingencies (Note 9)
Long-term debt		256,934			256,466
Fair value of derivative liabilities		267			—
Asset retirement obligation		2,593			2,483
Partners’ equity
Limited partners’ interest:
Common unitholders (6,300,624 and 6,286,755 units issued and
outstanding at September 30, 2009 and December 31, 2008, respectively)		105,226			122,666
Subordinated unitholders (3,060,000 units issued and outstanding)		(5,816	)		3,055
General partner interest		1,645			2,202
Accumulated other comprehensive income (loss)		(808	)		5,233

Total partners’ equity		100,247			133,156

Total liabilities and partners’ equity	$	381,861		$	426,139

The accompanying notes are an integral part of these consolidated financial statements.

HILAND PARTNERS, LP

Consolidated Statements of Operations

For the Three and Nine Months Ended


	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues:
Midstream operations
Third parties	$	53,015		$	107,158		$	151,133		$	308,625
Affiliates		626			7,390			2,525			10,433
Compression services, affiliate		1,205			1,205			3,615			3,615

Total revenues		54,846			115,753			157,273			322,673

Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		18,526			45,616			52,943			139,258
Midstream purchases — affiliate (exclusive of items shown separately below)		11,740			36,279			35,538			99,328
Operations and maintenance		7,736			7,881			23,216			22,201
Depreciation, amortization and accretion		10,472			9,554			30,981			27,652
Property impairments		20,500			—			21,450			—
Bad debt		—			(7,799	)		—			304
General and administrative		2,579			2,259			8,458			6,423

Total operating costs and expenses		71,553			93,790			172,586			295,166

Operating (loss) income		(16,707	)		21,963			(15,313	)		27,507

Other income (expense):
Interest and other income		10			96			91			267
Amortization of deferred loan costs		(149	)		(147	)		(448	)		(426	)
Interest expense		(2,702	)		(3,271	)		(7,739	)		(9,888	)

Other income (expense), net		(2,841	)		(3,322	)		(8,096	)		(10,047	)

Net (loss) income		(19,548	)		18,641			(23,409	)		17,460
Less general partner’s interest in net (loss) income		(391	)		2,641			(468	)		6,513

Limited partners’ interest in net (loss) income	$	(19,157	)	$	16,000		$	(22,941	)	$	10,947

Net (loss) income per limited partners’ unit — basic	$	(2.05	)	$	1.71		$	(2.45	)	$	1.17

Net (loss) income per limited partners’ unit — diluted	$	(2.05	)	$	1.71		$	(2.45	)	$	1.17

Weighted average limited partners’ units outstanding — basic		9,356			9,339			9,352			9,323

Weighted average limited partners’ units outstanding — diluted		9,356			9,365			9,352			9,364

The accompanying notes are an integral part of these consolidated financial statements.

HILAND PARTNERS, LP

Consolidated Statements of Cash Flows

For the Nine Months Ended


	September 30,			September 30,
	2009			2008
	(Unaudited, in thousands)

Cash flows from operating activities:
Net (loss) income	$	(23,409	)	$	17,460
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		30,864			27,550
Accretion of asset retirement obligation		117			102
Property impairments		21,450			—
Amortization of deferred loan cost		448			426
Gain on derivative transactions		(9	)		(3,685	)
Net proceeds from settlement of derivative contracts		3,155			—
Unit based compensation		837			1,159
Bad debt		—			304
Gain on sale of assets		(3	)		(12	)
Increase in other assets		(57	)		(72	)
(Increase) decrease in current assets:
Accounts receivable — trade		5,991			(10,036	)
Accounts receivable — affiliates		1,084			(3,846	)
Other current assets		768			(1,459	)
Increase (decrease) in current liabilities:
Accounts payable		(2,366	)		(2,856	)
Accounts payable — affiliates		(3,364	)		435
Accrued liabilities and other		3,031			1,241

Net cash provided by operating activities		38,537			26,711

Cash flows from investing activities:
Purchases of property and equipment		(32,299	)		(37,164	)
Proceeds from disposals of property and equipment		12			18

Net cash used in investing activities		(32,287	)		(37,146	)

Cash flows from financing activities:
Proceeds from long-term borrowings		12,000			41,000
Payments on long-term borrowings		(11,000	)		—
Increase in deferred offering cost		—			(7	)
Debt issuance costs		(10	)		(355	)
Proceeds from unit options exercise		—			1,052
General partner contribution for issuance of restricted common units and from conversion of vested phantom units		(2	)		7
Redemption of vested phantom units		—			(35	)
Forfeiture of unvested restricted common units		18			—
Payments on capital lease obligations		(560	)		(369	)
Cash distributions to unitholders		(4,312	)		(29,208	)

Net cash (used in) provided by financing activities		(3,866	)		12,085

Increase for the period		2,384			1,650
Beginning of period		1,173			10,497

End of period	$	3,557		$	12,147

Supplementary information
Cash paid for interest, net of amounts capitalized	$	7,923		$	9,707

The accompanying notes are an integral part of these consolidated financial statements.

HILAND PARTNERS, LP

Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income (Loss)

For the Nine Months Ended September 30, 2009


	Common			Subordinated						Accumulated
	Limited			Limited			General			Other						Total
	Partner			Partner			Partner			Comprehensive						Comprehensive
	Interest			Interest			Interest			Income (Loss)			Total			Income (Loss)
	(Unaudited)
	(In thousands, except unit amounts)

Balance, January 1, 2009	$	122,666		$	3,055		$	2,202		$	5,233		$	133,156
Issuance of 7,869 common units
from 8,250 vested phantom units		(3	)		—			1			—			(2	)
Forfeiture of 4,250 unvested		22			—			(4	)		—			18
restricted common units
Periodic cash distributions		(2,849	)		(1,377	)		(86	)		—			(4,312	)
Unit based compensation		837			—			—			—			837
Other comprehensive income
reclassified to income on
closed derivative transactions		—			—			—			(5,848	)		(5,848	)	$	(5,848	)
Change in fair value of derivatives		—			—			—			(193	)		(193	)		(193	)
Net loss		(15,447	)		(7,494	)		(468	)		—			(23,409	)		(23,409	)

Comprehensive loss																$	(29,450	)

Balance, September 30, 2009	$	105,226		$	(5,816	)	$	1,645		$	(808	)	$	100,247

The accompanying notes are an integral part of this consolidated financial statement.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2009 and 2008

(in thousands, except unit information or unless otherwise noted)


Note 1:	Organization, Basis of Presentation and Principles of Consolidation

Hiland Partners, LP, a Delaware limited partnership (“we,” “us,” “our” or the “Partnership”), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc. (“CGI”) and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, CGI contributed a substantial portion of its net assets to us. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and was recorded at historical cost. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CLR”).

CGI operated in one segment, midstream, which involved the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating and marketing of natural gas liquids, or NGLs. CGI historically owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland, Bakken, Kinta Area, Woodford Shale and North Dakota Bakken gathering systems. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, consisting of certain southeastern Montana gathering assets, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general partner equivalent units, both at $45.03 per unit. We began construction of the Woodford Shale gathering system in the first quarter of 2007 and commenced initial start-up of its operations in April 2007. Construction on the North Dakota Bakken gathering system and processing plant began in October 2008 and became fully operational in May 2009. As of September 30, 2009, we have invested approximately $24.0 million in the North Dakota Bakken gathering system.

The unaudited financial statements for the three and nine months ended September 30, 2009 and 2008 included herein have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (the “SEC”). The interim financial statements reflect all adjustments, which in the opinion of our management, are necessary for a fair presentation of our results for the interim periods. Such adjustments are considered to be of a normal recurring nature. Subsequent events have been evaluated through November 8, 2009. Results of operations for the three and nine months ended September 30, 2009 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2009. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Concentration and Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and receivables. We place our cash and cash equivalents with high-quality institutions and in money market funds. We derive our revenue from customers primarily in the oil and gas and utility industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities. The counterparties to our commodity based derivative instruments as of September 30, 2009 are BP Energy Company and Bank of Oklahoma, N.A. Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

Fair Value of Financial Instruments

Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and long-term debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value. Fair value of our derivative instruments is determined based on management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward New York Mercantile Exchange (“NYMEX”) natural gas and light crude prices and forecasted forward interest rates as a function of forward London Interbank Offered Rate (“LIBOR”) interest rates. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

Interest Rate Risk Management

We are exposed to interest rate risk on our variable rate bank credit facility. We manage a portion of our interest rate exposure by utilizing an interest rate swap to convert a portion of variable rate debt into fixed rate debt. The swap fixes the one month LIBOR rate at the indicated rates for a specified amount of related debt outstanding over the term of the swap agreement. We have elected to designate the interest rate swap as a cash flow hedge for accounting treatment. Accordingly, unrealized gains and losses relating to the interest rate swap are recorded in accumulated other comprehensive income until the related interest rate expense is recognized in earnings. Any ineffective portion of the gain or loss is recognized in earnings immediately.

Commodity Risk Management

We engage in price risk management activities in order to minimize the risk from market fluctuation in the prices of natural gas and NGLs. To qualify as an accounting hedge, the price movements in the commodity derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives that qualify as accounting hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statement of operations as revenues from midstream operations. Gains and losses related to commodity derivatives that are not designated as accounting hedges or do not qualify as accounting hedges are recognized in income immediately and are included in revenues from midstream operations in the consolidated statement of operations.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

US GAAP requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in accumulated other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented and reassessed periodically. Certain normal purchases and normal sales contracts are not subject to fair value measurement. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or a derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

Our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in partners’ equity and reclassified into earnings in the same period in which the hedged transaction closes. The assets or liabilities related to the derivative instruments are recorded on the balance sheet as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.

Long Lived Assets

We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

When determining whether impairment of one or more of our long-lived assets has occurred, we estimate the undiscounted future cash flows attributable to the asset or asset group. Estimates of cash flows are based on assumptions regarding the volume of reserves providing asset cash flow, future natural gas and NGL product prices, estimated future operating and maintenance capital expenditures. The amount of reserves and drilling activities are dependent in part on natural gas and crude oil prices. Projections of reserves, future commodity prices and operating and maintenance capital expenditures are inherently subjective and contingent upon a number of variable factors, including, but not limited to:


	•	changes in general economic conditions in regions in which the assets are located;

	•	the availability and prices of NGLs and NGL products and competing commodities;

	•	the availability and prices of raw natural gas supply;

	•	our ability to negotiate favorable marketing agreements;

	•	the risks that third party oil and gas exploration and production activities will not occur or be successful;

	•	our dependence on certain significant customers and producers of natural gas; and

	•	competition from other midstream service providers and processors, including major energy companies.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges of $20,500 in September 2009. Additionally, as a result of volume declines at our natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $950 in March 2009. No impairment charges were recognized during the three and nine months ended September 30, 2008.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial instruments. For derivatives qualifying as accounting hedges, the effective portion of changes in fair value is recognized in partners’ equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. Our comprehensive income (loss) for the three and nine months ended September 30, 2009 and 2008 is presented in the table below:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008

Net (loss) income	$	(19,548	)	$	18,641	$	(23,409	)	$	17,460
Closed derivative transactions reclassified to income		(1,969	)		1,395		(5,848	)		6,478
Change in fair value of derivatives		(1,143	)		13,219		(193	)		2,965

Comprehensive (loss) income	$	(22,660	)	$	33,255	$	(29,450	)	$	26,903

Net Income (Loss) per Limited Partners’ Unit

Net income (loss) per limited partners’ unit is computed based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per limited partners’ unit is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by both the basic and diluted weighted-average number of limited partnership units outstanding.

Recent Accounting Pronouncements

In September 2009, the FASB issued new authoritative accounting guidance, effective for financial statements issued for interim and annual periods ending after September 15, 2009, which identifies the FASB Accounting Standards Codification (“Codification”) as the authoritative source of GAAP in the United States. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. Codification is not intended to change GAAP. The adoption of this new accounting guidance had no impact on our financial statements and disclosures therein.

In May 2009, the FASB issued new authoritative accounting guidance on subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new accounting guidance is effective for interim or annual periods ending after June 15, 2009. The adoption of this new guidance was effective June 30, 2009 and did not have a material impact on our financial statements and disclosures therein.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

In April 2009, the FASB issued new authoritative accounting guidance on interim disclosures about fair value of financial instruments which expands the fair value disclosures required for all financial instruments to interim periods. This new guidance also requires entities to disclose in interim periods the methods and significant assumptions used to estimate the fair value of financial instruments. This new accounting guidance is effective for interim reporting periods ending after June 15, 2009. The adoption of this new guidance was effective June 30, 2009 and did not have a material impact on our financial statements and disclosures therein.

In April 2009, the FASB revised the authoritative guidance related to the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. Generally, assets acquired and liabilities assumed in a business combination that arise from contingencies must be recognized at fair value at the acquisition date. This guidance was adopted January 1, 2009. As this guidance is applied prospectively to business combinations with an acquisition date on or after the date the guidance became effective, the impact cannot be determined until the transactions occur. No such transactions have occurred during 2009.

In April 2008, the FASB issued amended guidance on the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets, including goodwill. In determining the useful life of an acquired intangible asset, this guidance removes the requirement for an entity to consider whether renewal of the intangible asset requires significant costs or material modifications to the related arrangement and replaces the previous useful life assessment criteria with a requirement that an entity considers its own experience or market participant assumptions in renewing similar arrangements. This guidance was adopted effective January 1, 2009, and will apply to future intangible assets acquired. We don’t believe the adoption will have a material impact on our financial position, results of operations or cash flows.

In March 2008, the FASB amended and expanded the disclosure requirements related to derivative instruments and hedging activities to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. The revised guidance requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. This guidance was adopted effective January 1, 2009 and did not have a material impact on our financial statements and disclosures therein.

In March 2008, the FASB issued authoritative accounting guidance which requires the calculation of a Master Limited Partnership’s (“MLPs”) net earnings per limited partner unit for each period presented according to distributions declared and participation rights in undistributed earnings as if all of the earnings for that period had been distributed. In periods with undistributed earnings above specified levels, the calculation per the two-class method results in an increased allocation of such undistributed earnings to the general partner and a dilution of earnings to the limited partners. This guidance was adopted effective January 1, 2009 and did not have a significant impact on our financial statements and disclosures therein.

In December 2007, the FASB revised the authoritative guidance for business combinations which provides guidance for how the acquirer recognizes and measures goodwill acquired in the business combination or a gain from a bargain purchase, the identifiable assets acquired, liabilities assumed and any noncontrolling interest in the acquiree. This guidance also determines what information to disclose to enable users to be able to evaluate the nature and financial effects of the business combination. This guidance was adopted effective January 1, 2009 and will apply to future business combinations.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income are now determined without deducting minority interest; however, earnings-per-share information continues to be calculated on the basis of the net income attributable to the parent’s shareholders. Additionally, this guidance establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. This guidance is effective for fiscal years beginning on or after December 15, 2008, was adopted effective January 1, 2009 and did not have a material impact on our financial position, results of operations or cash flows.

In February 2007, the FASB expanded guidance on fair value measurements which expands opportunities to use fair value measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. This guidance was adopted effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at fair value by other authoritative literature, were designated to be recorded at fair value. The adoption of this guidance did not have any impact on our financial position, results of operations or cash flows.

In September 2006, the FASB issued new authoritative accounting guidance for fair value measurements, which defines fair value as 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, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. This guidance establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value and defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value. This guidance was adopted effective January 1, 2009 and did not have a material impact on our financial statements or disclosures therein.


Note 2:	Merger Agreements

On November 3, 2009, the Partnership amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of the Partnership (other than certain restricted common units owned by officers and employees) not owned by Hiland Holdings (the “Hiland Partners Merger”). The amendment increased the consideration payable to common unitholders of the Partnership from $7.75 to $10.00 per common unit and extended the end date under the merger agreement to December 11, 2009. On the same day, Hiland Holdings amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of Hiland Holdings (other than certain restricted common units owned by officers and employees) not owned by Mr. Hamm, his affiliates and the Hamm family trusts (the “Hiland Holdings Merger”). The amendment increased the consideration payable to common unitholders of Hiland Holdings from $2.40 to $3.20 per common unit and extended the end date under the merger agreement to December 11, 2009.

Upon consummation of the mergers, the common units of the Hiland companies will no longer be publicly owned or publicly traded. Conflicts committees comprised entirely of independent members of the boards of directors of the general partners of the Partnership and Hiland Holdings separately determined that

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

the merger agreements, as amended, and the mergers are advisable, fair to and in the best interests of the applicable Hiland company and its public unitholders. In determining to make their recommendations to the boards of directors, each conflicts committee considered, among other things, the opinion received from its respective financial advisor related to the fairness of the increased merger consideration. Based on the recommendation of its conflicts committee, the board of directors of the general partner of each of the Partnership and Hiland Holdings has approved the applicable merger agreement and has recommended, along with its respective conflicts committee, that the public unitholders of the Partnership and Hiland Holdings, respectively, approve the applicable merger. Consummation of the Hiland Partners Merger is subject to certain conditions, including the approval of holders of a majority of our outstanding common units not owned by the general partner of the Partnership and its affiliates, including Hiland Holdings, the absence of any restraining order or injunction, and other customary closing conditions. Additionally, the obligation of Mr. Hamm and his affiliates to complete the Hiland Partners Merger is contingent upon the concurrent completion of the Hiland Holdings Merger, and the Hiland Holdings Merger is subject to closing conditions similar to those described above. There can be no assurance that the Hiland Partners Merger or any other transaction will be approved or consummated.

In connection with amending the merger agreements, each Hiland company has adjourned its special meeting of unitholders until December 4, 2009, to allow the unitholders of each Hiland company additional time to consider the proposals to approve the applicable merger agreement and merger. The Partnership and Hiland Holdings intend to file with the SEC a supplement to the definitive joint proxy statement on Schedule 14A, which, upon clearance by the SEC, the Hiland companies intend to mail to all holders of record of the Hiland companies as of September 9, 2009, the record date for the special meetings. The definitive joint proxy statement on Schedule 14A was filed with the SEC on September 11, 2009 and first mailed to unitholders on or around September 16, 2009.

Each of the Hiland companies had previously amended the respective merger agreement between that Hiland company and affiliates of Harold Hamm on October 26, 2009 to extend the end date under the merger agreement from November 1 to November 6. Those amendments were to provide the boards of directors and conflicts committees of each of the Hiland companies additional time to consider the proposals made by Harold Hamm in letters delivered to the conflicts committees on October 26, 2009, to increase the consideration payable to common unitholders of the Partnership and Hiland Holdings under the respective merger agreements.

On July 10, 2009, the United States Federal Trade Commission granted early termination of the waiting period under the Hart-Scott-Rodino Act with respect to the Hiland Partners Merger.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)


Note 3:	Property and Equipment and Asset Retirement Obligations

Property and equipment consisted of the following for the periods indicated:


	As of		As of
	September 30,		December 31,
	2009		2008

Land	$	295	$	295
Construction in progress		2,558		15,583
Midstream pipeline, plants and compressors		441,853		405,842
Compression and water injection equipment		19,421		19,391
Other		4,987		4,621

		469,114		445,732
Less: accumulated depreciation and amortization		146,433		99,877

	$	322,681	$	345,855

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges consisting of right-of-ways, pipelines, compressors and related equipment of $18,854 in September 2009. Additionally, as a result of volume declines at our natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $950 in March 2009. No impairment charges were recognized during the three and nine months ended September 30, 2008. During the three and nine months ended September 30, 2009, we capitalized interest of $2 and $106, respectively. We capitalized interest of $5 and $160 during the three and nine months ended September 30, 2008, respectively.

We recorded the fair value of liabilities for asset retirement obligations in the periods in which they are incurred with corresponding increases in the carrying amounts of the related long-lived assets. The asset retirement costs are subsequently allocated to expense using a systematic and rational method and the liabilities are accreted to measure the change in liability due to the passage of time. Our asset retirement obligations primarily relate to dismantlement and site restoration of certain of our plants, pipelines and compressor stations. We have evaluated our asset retirement obligations as of September 30, 2009 and have determined that revisions in the carrying values are not necessary at this time.

The following table summarizes our activity related to asset retirement obligations for the indicated period:


Asset retirement obligation, January 1, 2009	$	2,483
Less: obligation extinguished		(17	)
Add: additions on leased locations		10
Add: accretion expense		117

Asset retirement obligation, September 30, 2009	$	2,593


Note 4:	Intangible Assets

Intangible assets consist of the acquired value of customer relationships and existing contracts to purchase, gather and sell natural gas and other NGLs and compression contracts, which do not have significant residual value. The customer relationships and the contracts are being amortized over their estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value based on the

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

discounted probable cash flows of the intangible assets. As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges related to customer relationships of $1,646 in September 2009. No impairments of intangible assets were recorded during the three and nine months ended September 30, 2008.

Intangible assets consisted of the following for the periods indicated:


	As of		As of
	September 30,		December 31,
	2009		2008

Gas sales contracts	$	25,585	$	25,585
Compression contracts		18,515		18,515
Customer relationships		10,492		10,492

		54,592		54,592
Less accumulated amortization		24,690		18,950

Intangible assets, net	$	29,902	$	35,642

During each of the three months ended September 30, 2009 and 2008, we recorded $1,365 of amortization expense. During each of the nine months ended September 30, 2009 and 2008, we recorded $4,094 of amortization expense. Estimated aggregate amortization expense for the remainder of 2009 is $1,303 and $5,209 for each of the four succeeding fiscal years from 2010 through 2013 and a total of $7,763 for all years thereafter.


Note 5:	Derivatives

Interest Rate Swap

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. We entered into a one year interest rate swap agreement with our counterparty on October 7, 2008 for the period from January 2009 through December 2009 at a rate of 2.245% on a notional amount of $100.0 million. The swap fixes the one month LIBOR rate at 2.245% for the notional amount of debt outstanding over the term of the swap agreement. During the three and nine months ended September 30, 2009, one month LIBOR interest rates were lower than the contracted fixed interest rate of 2.245%. Consequently, for the three and nine months ended September 30, 2009, we incurred additional interest expense of $501 and $1,406, respectively, upon monthly settlements of the interest rate swap agreement.

The following table provides information about our interest rate swap at September 30, 2009 for the periods indicated:


	Notional		Interest			Fair Value
Description and Period	Amount		Rate			(Liability)

Interest Rate Swap
October 2009 — December 2009	$	100,000		2.245	%	$	(512	)

Commodity Swaps

We have entered into certain derivative contracts that are classified as cash flow hedges which relate to forecasted natural gas sales in 2009 and 2010. We entered into these financial swap instruments to hedge forecasted natural gas sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures, the “sold fixed for floating price” or “buy fixed for floating price” contracts, to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80% to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in natural gas reference prices under a hedging instrument and actual natural gas prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. We assess effectiveness using regression analysis and measure ineffectiveness using the dollar offset method.

Derivatives are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in partners’ equity as accumulated other comprehensive income (loss) and reclassified to earnings when the underlying hedged transaction closes. The ineffective portions of qualifying derivatives are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of future changes in prices. Hedge ineffectiveness is recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized cash gains and losses on closed/settled instruments and hedge ineffectiveness are reflected in the contract month being hedged as an adjustment to our midstream revenue.

On June 26, 2009, we unwound (cash settled) a 2010 coupled qualified hedge for a discounted net amount of $3,155 and entered into a new cash flow swap agreement for the same underlying forecasted natural gas sales which settle in the same monthly periods in 2010. The coupled qualified hedge we cash settled on June 26, 2009 consisted of a receipt of $4,499 from one counterparty offset by a payment of $1,344 to another counterparty. Of the $4,499 cash received, $3,571 had previously been recognized as midstream revenues in 2008 as the hedge, at that time, did not qualify for hedge accounting. The net unrecognized loss of $416 has been recorded to accumulated other comprehensive income and will be recorded as reductions in midstream revenues as the hedged transactions settle in 2010. Under the terms of the new derivative contract, we receive a fixed price of $5.08 and pay a floating CIG index price for the same relevant volumes and contract period as the underlying natural gas is sold.

On October 1, 2009, we entered into a financial swap agreement related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This swap agreement with BP Energy Company replaces a previous swap agreement we entered into with Bank of Oklahoma, N.A. on May 27, 2008. The terms of the new swap agreement are identical to the May 27, 2008 swap agreement. The new swap agreement is coupled with a derivative contract entered into on January 13, 2009 whereby we receive a floating NYMEX Henry Hub index price less a differential of $2.13 and pay a CIG index price for the same relevant volumes and contract period as the underlying natural gas related to the October 1, 2009 derivative contract is sold, qualifying the coupled agreements for hedge accounting.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Presented in the table below is information related to our derivatives for the indicated periods:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Net gains (losses) on closed/settled transactions
reclassified from (to) accumulated other
comprehensive income	$	1,969		$	(1,395	)	$	5,848		$	(6,478	)
Increases (decreases) in fair values of open
derivatives recorded to (from) accumulated
other comprehensive income	$	(1,143	)	$	13,219		$	(193	)	$	2,965
Unrealized non-cash gains (losses) on ineffective
portions of qualifying derivative transactions	$	(238	)	$	133		$	9		$	128
Unrealized non-cash gains on
non-qualifying derivatives	$	—		$	5,487		$	—		$	3,557

At September 30, 2009, our accumulated other comprehensive income (loss) was $(808). Of this amount, we anticipate $1,786 will be reclassified to earnings during the next twelve months and $(2,594) will be reclassified to earnings in subsequent periods.

The fair value of derivative assets and liabilities are as follows for the indicated periods:


	As of			As of
	September 30,			December 31,
	2009			2008

Fair value of derivative assets — current	$	3,860		$	6,851
Fair value of derivative assets — long term		608			7,141
Fair value of derivative liabilities — current		(835	)		(1,439	)
Fair value of derivative liabilities — long term		(267	)		—

Net fair value of derivatives	$	3,366		$	12,553

The terms of our derivative contracts currently extend as far as December 2010. At September 30, 2009, the counterparties to our commodity-based derivative contracts were BP Energy Company and Bank of Oklahoma, N.A. Effective October 1, 2009, the counterparty to our commodity-based derivative contracts is BP Energy Company. Our counterparty to our interest rate swap is Wells Fargo Bank, N.A.

The following table provides information about our commodity derivative instruments at September 30, 2009 for the periods indicated:


		Average	Fair
		Fixed	Value
Description and Production Period	Volume	Price	Asset
	(MMBtu)	(Per MMBtu)

Natural Gas — Sold Fixed for Floating Price Swaps
October 2009 — September 2010	2,136,000	$6.87	$	3,537
October 2010 — December 2010	534,000	$6.73		341

			$	3,878

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)


Note 6:	Fair Value Measurements

We adopted FASB authoritative accounting guidance on fair value measurement beginning in the first quarter of 2008. We adopted amended guidance for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually) effective January 1, 2009, which applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. The adopted fair value guidance defines fair value as 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 and establishes a framework for measuring fair value in GAAP such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair value measurements based on their level in the hierarchy. The adopted fair value guidance further establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The fair value hierarchy defines three levels of inputs that may be used to measure fair value. Level 1 refers to assets that have observable market prices, level 2 assets do not have an “observable price” but do have inputs that are based on such prices in which components have observable data points and level 3 refers to assets in which one or more of the inputs do not have observable prices and calibrated model parameters, valuation techniques or management’s assumptions are used to derive the fair value.

US GAAP requires derivatives and other financial instruments be measured at fair value at initial recognition and for all subsequent periods. We use the fair value methodology to value assets and liabilities for our outstanding fixed price cash flow swap derivative contracts. Valuations of our natural gas derivative contracts are based on published forward price curves for natural gas and, as such, are defined as Level 2 fair value hierarchy assets and liabilities. We valued our interest rate-based derivative on a comparative mark-to-market value received from our counterparty and, as such, is defined as Level 3. The following table represents the fair value hierarchy for our assets and liabilities measured at fair value on a recurring basis at September 30, 2009:


	Level 1	Level 2			Level 3			Total

Commodity — based derivative assets	$ —	$	4,468		$	—		$	4,468
Commodity — based derivative liabilities	—		(590	)		—			(590	)
Interest — based derivative liabilities	—		—			(512	)		(512	)

Total	$ —	$	3,878		$	(512	)	$	3,366

The following table provides a summary of changes in the fair value of our Level 3 interest rate-based derivative for the nine months ended September 30, 2009:


Balance, January 1, 2009	$	(1,439	)
Cash settlements from other comprehensive income		1,406
Change in fair value of derivative		(479	)

Balance, September 30, 2009	$	(512	)

We review properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We compare each property’s estimated expected future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

future cash flows are based on management’s expectations for the future and include estimates of future oil and gas reserves, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we determined that tangible and intangible carrying amounts totaling approximately $20,500 were not recoverable from future cash flows and, therefore, were impaired at September 30, 2009. We reduced the carrying amounts of these nonrecurring level 3 hierarchy assets to their estimated fair values of approximately $72,600 by using a combination of estimated future cash flows and comparable market data. Additionally, as a result of volumes declines combined with significantly reduced natural gas prices, we determined that carrying amounts totaling approximately $950 related to natural gas gathering systems located in Texas and Mississippi were not recoverable from future cash flows and, therefore, were impaired at March 31, 2009. We reduced the carrying amounts of these nonrecurring level 3 hierarchy assets to their estimated fair values of approximately $249 by using the discounted cash flow method described above, as comparable market data was not available.


Note 7:	Long-Term Debt

Long-term debt consisted of the following for the indicated periods:


	As of		As of
	September 30,		December 31,
	2009		2008

Credit facility	$	253,064	$	252,064
Capital lease obligations		4,492		5,051

		257,556		257,115
Less: current portion of capital lease obligations		622		649

Long-term debt	$	256,934	$	256,466

Credit Facility. Our borrowing capacity under our senior secured revolving credit facility, as amended, is $300.0 million, consisting of a $291.0 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “Working Capital Facility”).

In addition, the senior secured revolving credit facility provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to $50.0 million and allows for the issuance of letters of credit of up to $15.0 million in the aggregate. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

above the current forward prices and expected inlet natural gas volumes for the fourth quarter of 2009, the Partnership could be in violation of the maximum consolidated funded debt to EBITDA covenant ratio as early as December 31, 2009, unless this ratio is amended, the Partnership receives an infusion of equity capital, the Partnership’s debt is restructured or the Partnership is able to monetize “in-the-money” hedge positions. Management is continuing discussions with certain lenders under the credit facility as to ways to address a potential covenant violation. While no potential solution has been agreed to, the Partnership expects that any solution will require the assessment of fees and increased rates, the infusion of additional equity capital or the incurrence of subordinated indebtedness by the Partnership and the suspension of distributions for a certain period of time. There can be no assurance that any such agreement will be reached with the lenders, that any required equity or debt financing will be available to the Partnership, or that the Partnership will have sufficient “in-the-money” hedges to monetize to address the maximum consolidated funded debt to EBITDA covenant ratio.

Upon the occurrence of an event of default as defined in the credit facility, the lenders may, among other things, be able to accelerate the maturity of the credit facility and exercise other rights and remedies as set forth in the credit facility.

Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us, and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility.

Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus ¹/2 of 1%. We have elected for the indebtedness to bear interest at LIBOR plus the applicable margin. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During the step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum. At September 30, 2009, the interest rate on outstanding borrowings from our credit facility was 2.87%.

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. See Note 5 “Derivatives” for a discussion of our interest rate swap.

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from such distributions. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement, which contains non-compete and indemnity provisions, or enter into a merger, consolidation or sale of assets.

The credit facility defines EBITDA as our consolidated net income (loss), plus income tax expense, interest expense, depreciation, amortization and accretion expense, amortization of intangibles and organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary or non-recurring items.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

revolving working capital facility is subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.

As of September 30, 2009, we had $253.1 million outstanding under the credit facility and were in compliance with its financial covenants. Our EBITDA to interest expense ratio was 4.93 to 1.0 and our consolidated funded debt to EBITDA ratio was 4.50 to 1.0.

Capital Lease Obligations. We are obligated under two separate capital lease agreements entered into with respect to our Bakken and Badlands gathering systems in the third quarter of 2007. Under the terms of a capital lease agreement for a rail loading facility and an associated products pipeline at our Bakken gathering system, we are repaying a counterparty a predetermined amount over a period of eight years. Once fully paid, title to the leased assets will transfer to us no later than the end of the eight-year period commencing from the inception date of the lease. We also incurred a capital lease obligation to a counterparty for the aid to construct several electric substations at our Badlands gathering system which, by agreement, is being repaid in equal monthly installments over a period of five years.

During the three and nine months ended September 30, 2009, we made principal payments of $210 and $560, respectively, on the above described capital lease obligations. The current portion of the capital lease obligations presented in the table above is included in accrued liabilities and other in the balance sheet.


Note 8:	Share-Based Compensation

Our general partner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and directors of our general partner and employees of its affiliates. The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units and phantom units granted under the plan. No more than 225,000 of the 680,000 common units may be issued with respect to vested restricted or phantom units. The plan is administered by the compensation committee of our general partner’s board of directors. The plan will continue in effect until the earliest of (i) a date determined by the board of directors of our general partner; (ii) the date common units are no longer available for payment of awards under the plan; or (iii) the tenth anniversary of the plan.

Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant. Under the unit option grant agreement, granted options of common units vest and become exercisable in one-third increments on the anniversary of the grant date over three years. Vested options are exercisable within the option’s contractual life of ten years after the grant date. Restricted common units granted vest and become exercisable in one-fourth increments on the anniversary of the grant date over four years. A restricted unit is a common unit that is subject to forfeiture, and upon vesting, the grantee receives a common unit that is not subject to forfeiture. Distributions on unvested restricted common units are held in trust by our general partner until the units vest, at which time the distributions are distributed to the grantee. Granted phantom common units are generally more flexible than restricted units and vesting periods and distribution rights may vary with each grant. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, holders of phantom units will receive (i) a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a combination thereof, at the discretion of our general partner’s board of directors and (ii) the distributions held in trust, if applicable, related to the vested units.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Phantom Units. On August 8, 2009, 1,875 phantom units awarded to our Chief Operations Officer in August 2008 vested, of which 1,494 were converted to common units and 381 were redeemed.

The following table summarizes information about our phantom units for the nine months ended September 30, 2009:


				Weighted		Weighted
				Average		Average
				Fair Value		Fair Value at
				at Grant		Redemption
Phantom Units	Units			Date ($)		Date ($)

Unvested at January 1, 2009		50,794		$	47.74
Granted		—
Vested and converted or redeemed		(8,250	)	$	49.34	$	7.40
Forfeited		(5,050	)	$	45.11

Unvested at September 30, 2009		37,494		$	47.75

During the three and nine months ended September 30, 2009, we incurred non-cash unit based compensation expense of $189 and $652, respectively, related to phantom units. During the three and nine months ended September 30, 2008, we incurred non-cash unit based compensation expense of $297 and $877, respectively, related to phantom units. We will recognize additional expense of $803 over the next four years, and the additional expense is to be recognized over a weighted average period of 2.2 years.

Restricted Units. Each non-employee board member of Hiland Partners GP, LLC received an additional 1,000 restricted common units on each anniversary date of the initial reward with the exception of the anniversary date on August 10, 2009. We issued no restricted units during the three and nine months ended September 30, 2009. During the three months ended September 30, 2009, a total of 6,000 restricted common units issued to non-employee board members of our general partner in 2005, 2006, 2007 and 2008 vested and were converted into common units. Non-cash unit based compensation expense related to restricted units issued is to be recognized over their respective four-year vesting period on the graded vesting attribution method.

The following table summarizes information about our restricted units for the nine months ended September 30, 2009.


				Weighted
				Average
				Fair Value
				per Unit
				at Grant
Restricted Units	Units			Date ($)

Unvested at January 1, 2009		18,500		$	48.73
Granted		—
Vested		(6,000	)	$	44.29
Forfeited		(4,250	)	$	47.56

Unvested at September 30, 2009		8,250		$	52.56

Non-cash unit based compensation expense related to the restricted units was $46 and $183 for the three and nine months ended September 30, 2009, respectively, and was $91 and $258 for the three and nine months ended September 30, 2008, respectively. As of September 30, 2009, there was $166 of total unrecognized cost related to the unvested restricted units. This cost is to be recognized over a weighted average period of 2.1 years.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

Unit Options. At September 30, 2009, all common unit options awarded have vested. The weighted average exercise price of 33,336 outstanding exercisable common unit options at September 30, 2009 is $37.79 per unit, and such common unit options have a weighted average remaining contractual term of 6.2 years. Non-cash unit based compensation expense related to the unit options was insignificant for the three and nine months ended September 30, 2009 and 2008, respectively.


Note 9:	Commitments and Contingencies

We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees’ compensation. Contributions to the plan are 5.0% of eligible employees’ compensation and resulted in expense for the three months ended September 30, 2009 and 2008 of $100 and $83, respectively, and for the nine months ended September 30, 2009 and 2008 was $290 and $238, respectively.

We maintain our health and workers’ compensation insurance through third-party providers. Property and general liability insurance is also maintained through third-party providers with a $100 deductible on each policy.

The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.

Although there are no significant regulatory proceedings in which we are currently involved, periodically we may be a party to regulatory proceedings. The results of regulatory proceedings cannot be predicted with certainty; however, our management believes that we presently do not have material potential liability in connection with regulatory proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows.

We lease certain equipment, vehicles and facilities under operating leases, most of which contain annual renewal options. We also lease office space from a related entity. See Note 11 “Related Party Transactions.” Under these lease agreements, rent expense was $437 and $731, respectively, for the three months ended September 30, 2009 and 2008 and $2,031 and $1,983 for the nine months ended September 30, 2009 and 2008, respectively.

Three putative unitholder class action lawsuits have been filed relating to the Hiland Partners Merger and the Hiland Holdings Merger. These lawsuits are as follows: (i) Robert Pasternack v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4397-VCS; (ii) Andrew Jones v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4558-VCS; and (iii) Arthur G. Rosenberg v. Hiland Partners, LP et al., In the District Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02. The lawsuits name as defendants the Partnership, Hiland Holdings, the general partner of each of the Partnership and Hiland Holdings, and the members of the board of directors of each of the Partnership and Hiland Holdings. The lawsuits challenge both the Hiland Partners Merger and the Hiland Holdings Merger. The lawsuits allege claims of breach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) a purported class of common unitholders of the Partnership and (ii) a purported class of our common unitholders of Hiland Holdings.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

committees of the general partner of each of the Partnership and Hiland Holdings that were charged with reviewing the proposals and making a recommendation to each committee’s respective board of directors lacked any meaningful independence, (iii) the defendants acted in bad faith in recommending and approving the Hiland Partners Merger or the Hiland Holdings Merger, and (iv) the disclosures in the Preliminary Proxy Statement filed by the Partnership and Hiland Holdings are materially misleading. The Pasternack plaintiff seeks to preliminarily enjoin the defendants from proceeding with or consummating the mergers and seeks an order requiring defendants to supplement the Preliminary Proxy Statement with certain information. On August 13, 2009, the Partnership, Hiland Holdings and certain individual defendants moved to dismiss the claims added in the July 31, 2009 Amended Class Action Complaint. The plaintiffs moved to expedite proceedings on September 4, 2009. On September 4, 2009, the plaintiffs filed a motion to expedite the proceedings. On September 9, 2009, the Delaware Chancery Court requested that the defendants file a response to plaintiffs’ motion that same day and set a hearing on plaintiffs’ motion for September 11, 2009. Defendants responded to plaintiffs’ motion as ordered by the Court, and, following the hearing on September 11, 2009, plaintiffs’ motion to expedite the proceedings was denied.

We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits.


Note 10:	Significant Customers and Suppliers

All of our revenues are domestic revenues. The following table presents our top midstream customers as a percent of total revenue for the periods indicated:


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008

Customer 1		24	%		5	%		21	%		15	%
Customer 2		18	%		7	%		12	%		12	%
Customer 3		12	%		10	%		14	%		9	%
Customer 4		7	%		18	%		9	%		13	%
Customer 5		2	%		14	%		2	%		10	%

Customer 1 above is SemStream, L.P., a subsidiary of SemGroup, L.P., who filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008. In March 2009, we received a good faith deposit from SemStream, L.P. for $3,000 in lieu of renewing a letter of credit to our benefit. The $3,000 deposit received is included in accrued liabilities and other in the balance sheet.

All of our purchases are from domestic sources. The following table presents our top midstream suppliers as a percent of total midstream purchases for the periods indicated:


	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008

Supplier 1 (affiliated company)		39	%		45	%		41	%		42	%
Supplier 2		20	%		14	%		19	%		15	%
Supplier 3		16	%		17	%		16	%		18	%


Note 11:	Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $11,740 and $36,279 for the three months ended September 30, 2009 and 2008, respectively and totaled $35,538 and $99,328 for the nine months ended September 30, 2009 and 2008, respectively. We also sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled $626 and $7,390 for the

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

three months ended September 30, 2009 and 2008, respectively and totaled $2,525 and $10,433 for the nine months ended September 30, 2009 and 2008, respectively. Compression revenues from affiliates were $1,205 and $3,615 for each of the three and nine months ended September 30, 2009 and 2008, respectively.

Accounts receivable — affiliates of $1,262 at September 30, 2009 include $823 from one affiliate for midstream sales. Accounts receivable — affiliates of $2,346 at December 31, 2008 include $2,083 from one affiliate for midstream sales.

Accounts payable — affiliates of $4,298 at September 30, 2009 include $3,365 due to one affiliate for midstream purchases. Accounts payable — affiliates of $7,662 at December 31, 2008 include $6,682 payable to the same affiliate for midstream purchases.

We utilize affiliated companies to provide services to our plants and pipelines and certain administrative services. The total expenditures to these companies were $94 and $157 during the three months ended September 30, 2009 and 2008, respectively and were $350 and $420 during the nine months ended September 30, 2009 and 2008, respectively.

We lease office space under operating leases directly or indirectly from an affiliate. Rent expense associated with these leases totaled $41 and $42 for the three months ended September 30, 2009 and 2008, respectively and totaled $121 and $117 for the nine months ended September 30, 2009 and 2008, respectively.


Note 12:	Reportable Segments

We have distinct operating segments for which additional financial information must be reported. Our operations are classified into two reportable segments:

(1) Midstream, which is the purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and the fractionating and marketing of NGLs.

(2) Compression, which is providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota.

These business segments reflect the way we manage our operations. Our operations are conducted in the United States. General and administrative costs, which consist of executive management, accounting and finance, operations and engineering, marketing and business development, are allocated to the individual segments based on revenues.

Midstream assets totaled $360,590 at September 30, 2009. Assets attributable to compression operations totaled $21,271. All but $30 of the total capital expenditures of $23,413 for the nine months ended September 30, 2009 was attributable to midstream operations. All but $63 of the total capital expenditures of $38,043 for the nine months ended September 30, 2008 was attributable to midstream operations.

The tables below present information for the reportable segments for the three and nine months ended September 30, 2009 and 2008.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)


	For the Three Months Ended September 30,
	2009								2008
	Midstream			Compression					Midstream			Compression
	Segment			Segment		Total			Segment			Segment		Total

Revenues	$	53,641		$	1,205	$	54,846		$	114,548		$	1,205	$	115,753
Operating costs and expenses:
Midstream purchases (exclusive of
items shown separately below)		30,266			—		30,266			81,895			—		81,895
Operations and maintenance		7,559			177		7,736			7,617			264		7,881
Depreciation and amortization		9,575			897		10,472			8,658			896		9,554
Property impairments		20,500			—		20,500			—			—		—
Bad debt		—			—		—			(7,799	)		—		(7,799	)
General and administrative		2,522			57		2,579			2,235			24		2,259

Total operating costs and expenses		70,422			1,131		71,553			92,606			1,184		93,790

Operating (loss) income	$	(16,781	)	$	74		(16,707	)	$	21,942		$	21		21,963

Other income (expense):
Interest and other income							10								96
Amortization of deferred loan costs							(149	)							(147	)
Interest expense							(2,702	)							(3,271	)

Total other income (expense)							(2,841	)							(3,322	)

Net (loss) income						$	(19,548	)						$	18,641


	For the Nine Months Ended September 30,
	2009								2008
	Midstream			Compression					Midstream		Compression
	Segment			Segment		Total			Segment		Segment		Total

Revenues	$	153,658		$	3,615	$	157,273		$	319,058	$	3,615	$	322,673
Operating costs and expenses:
Midstream purchases (exclusive of
items shown separately below)		88,481			—		88,481			238,586		—		238,586
Operations and maintenance		22,612			604		23,216			21,428		773		22,201
Depreciation and amortization		28,289			2,692		30,981			24,966		2,686		27,652
Property impairments		21,450			—		21,450			—		—		—
Bad debt		—			—		—			304		—		304
General and administrative		8,262			196		8,458			6,350		73		6,423

Total operating costs and expenses		169,094			3,492		172,586			291,634		3,532		295,166

Operating (loss) income	$	(15,436	)	$	123		(15,313	)	$	27,424	$	83		27,507

Other income (expense):
Interest and other income							91							267
Amortization of deferred loan costs							(448	)						(426	)
Interest expense							(7,739	)						(9,888	)

Total other income (expense)							(8,096	)						(10,047	)

Net (loss) income						$	(23,409	)					$	17,460

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)


Note 13:	Net Income (Loss) per Limited Partners’ Unit

The computation of net income (loss) per limited partners’ unit is based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income (loss) per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income (loss) per unit applicable to limited partners is computed by dividing net income (loss) applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. The following is a reconciliation of the limited partner units used in the calculations of (loss) per limited partner unit — basic and (loss) per limited partner unit — diluted assuming dilution for the three and nine months ended September 30, 2009 and 2008:


	For the Three Months Ended September 30,
	2009								2008
	(Loss)								Income
	Attributable								Attributable
	to Limited			Limited					to Limited		Limited
	Partners			Partner Units		Per Unit			Partners		Partner Units		Per Unit
	(Numerator)			(Denominator)		Amount			(Numerator)		(Denominator)		Amount

(Loss) income per limited partner unit — basic and diluted:
(Loss) income attributable to limited partners	$	(19,157	)			$	(2.05	)	$	16,000			$	1.71
Weighted average limited partner units outstanding					9,356,000							9,339,000
Income per limited partner unit — diluted: Unit Options, restricted and phantom units					—							26,000

(Loss) income attributable to limited
partners plus assumed conversions	$	(19,157	)		9,356,000	$	(2.05	)	$	16,000		9,365,000	$	1.71


	For the Nine Months Ended September 30,
	2009								2008
	(Loss)								Income
	Attributable								Attributable
	to Limited			Limited					to Limited		Limited
	Partners			Partner Units		Per Unit			Partners		Partner Units		Per Unit
	(Numerator)			(Denominator)		Amount			(Numerator)		(Denominator)		Amount

(Loss) income per limited partner unit — basic and diluted:
(Loss) income attributable to limited partners	$	(22,941	)			$	(2.45	)	$	10,947			$	1.17
Weighted average limited partner units outstanding					9,352,000							9,323,000
Income per limited partner unit — diluted: Unit Options, restricted and phantom units					—							41,000

(Loss) income attributable to limited partners plus assumed conversions	$	(22,941	)		9,352,000	$	(2.45	)	$	10,947		9,364,000	$	1.17

For the three and nine months ended September 30, 2009, approximately 79,000 unit options and restricted and phantom units, respectively, were excluded from the computation of diluted earnings attributable to limited partner units because the inclusion of such units would have been anti-dilutive.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)


Note 14:	Partners’ Capital and Cash Distributions

Our unitholders (limited partners) have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence our management’s decisions regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our general partner or elect its board of directors in the future. Unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our 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 our management.

Our partnership agreement requires that we distribute all of our cash on hand at the end of each quarter, less reserves established at our general partner’s discretion. We refer to this as “available cash.” The amount of available cash may be greater than or less than the minimum quarterly distributions. In general, we will pay any cash distribution made each quarter in the following manner:


	•	first, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.45 plus any arrearages from prior quarters;

	•	second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.45; and

	•	third, 98% to all units pro rata, and 2% to our general partner, until each unit has received a distribution of $0.495.

If cash distributions per unit exceed $0.495 in any quarter, our general partner will receive increasing percentages, up to a maximum of 50% of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”

The distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units do not accrue arrearages. The subordination period will extend until the first day of any quarter beginning after March 31, 2010 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in the partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. In addition, if the tests for ending the subordination period are satisfied for any three consecutive four quarter periods ending on or after March 31, 2008, 25% of the subordinated units will convert into an equal number of common units. On May 14, 2008 these tests were met and accordingly, 1,020,000, or 25%, of the subordinated units converted into an equal number of common units.

We have suspended quarterly cash distributions on common and subordinated units beginning with the first quarter distribution of 2009 due to the impact of lower commodity prices and reduced drilling activity on our current and projected throughput volumes, midstream segment margins and cash flows combined with future required levels of capital expenditures and the outstanding indebtedness under our senior secured revolving credit facility. Under the terms of the partnership agreement, the common units carry an arrearage of

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

$1.35 per unit, representing the minimum quarterly distribution to common units for the first three quarters of 2009 that must be paid before the Partnership can make distributions to the subordinated units. Presented below are cash distributions to common and subordinated unitholders, including amounts to affiliate owners and regular and incentive distributions to our general partner paid by us from January 1, 2008 forward (in thousands, except per unit amounts):


Distribution	Date Cash		Per Unit Cash
for Quarter	Distribution		Distribution		Common		Subordinated		General Partner				Total Cash
Ending	Paid		Amount		Units		Units		Regular		Incentive		Distribution

12/31/07		02/14/08		0.7950	$	4,169	$	3,243	$	182	$	1,492	$	9,086
03/31/08		05/14/08		0.8275		4,364		3,376		194		1,789		9,723
06/30/08		08/14/08		0.8625		5,446		2,639		208		2,107		10,400
09/30/08		11/14/08		0.8800		5,574		2,694		214		2,268		10,750
12/31/08		02/13/09		0.4500		2,849		1,377		86		—		4,312
03/31/09				—		—		—		—		—		—
06/30/09				—		—		—		—		—		—
09/30/09				—		—		—		—		—		—

			$	3.8150	$	22,402	$	13,329	$	884	$	7,656	$	44,271


Note 15:	Subsequent Events

On November 3, 2009, the Partnership amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of the Partnership (other than certain restricted common units owned by officers and employees) not owned by Hiland Holdings. The amendment increased the consideration payable to common unitholders of the Partnership from $7.75 to $10.00 per common unit and extended the end date under the merger agreement to December 11, 2009. On the same day, Hiland Holdings amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of Hiland Holdings (other than certain restricted common units owned by officers and employees) not owned by Mr. Hamm, his affiliates or the Hamm family trusts. The amendment increased the consideration payable to common unitholders of Hiland Holdings from $2.40 to $3.20 per common unit and extended the end date under the merger agreement to December 11, 2009.

On November 3, 2009, in connection with amending the merger agreements, each Hiland company has adjourned its special meeting of unitholders until December 4, 2009, to allow the unitholders of each Hiland company additional time to consider the proposals to approve the applicable merger agreement and merger. The Partnership and Hiland Holdings intend to file with the SEC a supplement to the definitive joint proxy statement on Schedule 14A, which, upon clearance by the SEC, the Hiland companies intend to mail to all holders of record of the Hiland companies as of September 9, 2009, the record date for the special meetings.

Concurrently with the filing of the supplement to the joint proxy statement, (i) the Partnership, our general partner, Hiland Holdings and its general partner, HH GP Holding, LLC, an affiliate of Harold Hamm, HLND MergerCo, LLC, a wholly-owned subsidiary of HH GP Holding, LLC, Harold Hamm, Chairman of the Hiland Companies, Joseph L. Griffin, Chief Executive Officer and President of the Hiland Companies, and Matthew S. Harrison, Chief Financial Officer, Vice President — Finance and Secretary of the Hiland Companies will file Amendment No. 7 to their Transaction Statement on Schedule 13E-3 with the SEC and (ii) Hiland Holdings, its general partner, HH GP Holding, LLC, HPGP MergerCo, LLC, Continental Gas Holdings, Inc. (an affiliate of Mr. Hamm) and Messrs. Hamm, Griffin and Harrison will file Amendment No. 7 to their Transaction Statement on Schedule 13E-3 with the SEC.

HILAND PARTNERS, LP

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

The definitive joint proxy statement on Schedule 14A was filed with the SEC on September 11, 2009 and first mailed to unitholders on or around September 16, 2009.

On October 1, 2009, the Partnership entered into a financial swap agreement related to forecasted natural gas sales in 2010 whereby the Partnership receives a fixed price and pays a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This swap agreement with BP Energy Company replaces a previous swap agreement the Partnership entered into with Bank of Oklahoma, N.A. on May 27, 2008. The terms of the new swap agreement are identical to the May 27, 2008 swap agreement.

Cautionary Statement About Forward-Looking Statements

This report on Form 10-Q includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements include statements regarding our plans, goals, beliefs or current expectations. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Our actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. Such factors include:


	•	with respect to the mergers: (1) the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreements or the failure of required conditions to close the mergers; (2) the outcome of any legal proceedings that have been or may be instituted against the Partnership and/or Hiland Holdings and others; (3) the inability to obtain unitholder approval or the failure to satisfy other conditions to completion of the mergers, including the receipt of certain regulatory approvals; (4) risks that the proposed transaction disrupts current plans and operations and the potential difficulties in employee retention as a result of the mergers; (5) the performance of Harold Hamm, his affiliates and the Hamm family trusts , (6) the amount of the costs, fees, expenses and related charges and (7) the ability of the Hiland companies to receive clearance of the supplement to the definitive joint proxy statement a sufficient amount of time prior to the reconvened special meeting date to permit distribution of the supplement;

	•	the ability to comply with certain covenants in our credit facility and the ability to reach agreement with our lenders in the event of a breach of such covenants;

	•	the ability to pay distributions to our unitholders;

	•	our cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders.

	•	the continued ability to find and contract for new sources of natural gas supply;

	•	the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;

	•	the amount of natural gas gathered on our gathering systems and the associated level of throughput in our natural gas processing and treating facilities given the recent reduction in drilling activity in our areas of operations;

	•	the fees we charge and the margins realized for our services;

	•	the prices and market demand for, and the relationship between, natural gas and NGLs;

	•	energy prices generally;

	•	the level of domestic crude oil and natural gas production;

	•	the availability of imported crude oil and natural gas;

	•	actions taken by foreign crude oil and natural gas producing nations;

	•	the political and economic stability of petroleum producing nations;

	•	the weather in our operating areas;

	•	the extent of governmental regulation and taxation;


	•	hazards or operating risks incidental to the gathering, treating and processing of natural gas and NGLs that may not be fully covered by insurance;

	•	competition from other midstream companies;

	•	loss of key personnel;

	•	the availability and cost of capital and our ability to access certain capital sources;

	•	margin call risk with counterparties on our derivative instruments;

	•	changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;

	•	the costs and effects of legal and administrative proceedings;

	•	the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results;

	•	risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities;

	•	the completion of significant, unbudgeted expansion projects may require debt and/or equity financing which may not be available to us on acceptable terms, or at all; and;

	•	increases in interest rates could increase our borrowing costs, adversely impact our unit price and our ability to issue additional equity, which could have an adverse effect on our cash flows and our ability to fund our growth.

These factors are not necessarily all of the important factors that could cause our actual results to differ materially from those expressed in any of our forward-looking statements. Our future results will depend upon various other risks and uncertainties, including, but not limited to those described above. Other unknown or unpredictable factors also could have material adverse effects on our future results. You should not place undue reliance on any forward-looking statements.

All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no duty to update our forward-looking statements to reflect the impact of events or circumstances after the date of the forward-looking statements.


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

General Trends and Outlook

We expect our business to continue to be affected by the key trends described below. Our expectations are based on assumptions made by us, and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our expectations may vary materially from actual results. Please see “Forward Looking Statements.”

U.S. Natural Gas Supply and Outlook. Natural gas prices have declined significantly since the peak New York Mercantile Exchange (“NYMEX”) Henry Hub last day settle price of $13.11/MMBtu in July 2008 to the NYMEX Henry Hub last day settle price of $3.73 in October 2009, a 72% decline. NYMEX Henry Hub last day settle prices averaged $3.92 for the first ten months of 2009 compared to an average of $9.51 for the same periods in 2008, a decrease of $5.59, or 59%. According to data published by Baker Hughes Incorporated (“Baker Hughes”), U.S. natural gas drilling rig counts have declined by approximately 53% to 728 as of October 30, 2009, compared to 1,552 natural gas drilling rigs as of October 31, 2008, and have declined approximately 55% compared to the peak natural gas drilling rig count of 1,606 in September 2008. Natural gas storage levels have recently approached 3.7 Tcf (“trillion cubic feet”), which surpassed the November 2007 record working gas storage of 3.5 Tcf. We believe that current natural gas prices will continue to result in reduced natural gas-related drilling in our service territories until the economic environment in the United States improves and increases the demand for natural gas.

U.S. Crude Oil Supply and Outlook. A weaker economic environment and the resulting drop in demand for crude oil products in 2009 compared to 2008 continues to impact the price for crude oil. West Texas Intermediate (WTI) crude oil pricing has declined from a peak of $134.62/bbl in July 2008 to a low of $33.87/Bbl in January 2009, a 75% decline, increasing to $71.55/Bbl in October 2009, a 47% decline from July 2008. West Texas Intermediate (WTI) crude oil prices averaged $54.52 for the first ten months of 2009 compared to an average of $113.25 for the same periods in 2008, a decrease of $58.73, or 52%. According to data published by Baker Hughes, U.S. crude oil drilling rig counts have declined by approximately 19% to 330 as of October 30, 2009, compared to 408 crude oil drilling rigs as of October 24, 2008, and have declined approximately 25% compared to the peak crude oil drilling rig count of 442 in November 2008. Baker Hughes also published that U.S. crude oil drilling rig counts have steadily increased from a low of 179 as of June 5, 2009 to 330 as of October 30, 2009, an increase of 84% from June 5, 2009. Crude oil prices have steadily increased from $33.87/Bbl in January 2009 to $71.55/Bbl in October 2009. In addition, the forward curve for WTI crude oil pricing has recently improved.

U.S. NGL Supply and Outlook. A weaker economic environment and the resulting drop in demand for NGL products in 2009 compared to 2008 has impacted the price for NGLs. Conway NGL prices have dropped dramatically since the peak Conway NGL basket pricing of $1.97/gallon in June 2008 to a low of $0.61/gallon in December 2008, a 69% decline, increasing to $1.12/gallon in October 2009, a 43% decline from June 2008. Conway NGL basket pricing has historically correlated to WTI crude oil pricing. In addition, the forward curve for Conway NGL basket pricing and WTI crude oil pricing has recently improved.

A number of the areas in which we operate have experienced a significant decline in drilling activity as a result of this years decline in natural gas and crude oil prices as compared to last year. Excluding our North Dakota Bakken gathering system, which commenced operations in April 2009, we connected 26 wells during the first nine months of 2009 as compared to 83 wells connected during the same period in 2008, a 69% decrease. At our North Dakota Bakken gathering system, we connected 41 wells during the nine months ended September 30, 2009. Currently, there are two rigs drilling along our dedicated acreage company wide, both of which are located at our North Dakota Bakken gathering system. We anticipate that the dedicated rig count will increase during the remainder of 2009 and into 2010. While we anticipate continued exploration and production activities in the areas in which we operate, albeit at depressed levels, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of natural gas and crude oil reserves. Drilling activity generally decreases as natural gas and crude oil prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Disruption to functioning of capital markets

Overview

We are engaged in purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas, fractionating and marketing of NGLs, and providing air compression and water injection services for oil and gas secondary recovery operations. Our operations are primarily located in the Mid-Continent and Rocky Mountain regions of the United States.

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into two business segments:


	•	Midstream Segment, which is engaged in purchasing, gathering, compressing, dehydrating, treating, processing and marketing of natural gas and the fractionating and marketing of NGLs. The midstream segment generated 95.1% and 96.4% of total segment margin for the three months ended September 30, 2009 and 2008, respectively and 94.7% and 95.7% of total segment margin for the nine months ended September 30, 2009 and 2008, respectively.

	•	Compression Segment, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota. The compression segment generated 4.9% and 3.6% of total segment margin for the three months ended September 30, 2009 and 2008, respectively and 5.3% and 4.3% of total segment margin for the nine months ended September 30, 2009 and 2008, respectively.

Our midstream assets currently consist of 15 natural gas gathering systems with approximately 2,160 miles of gas gathering pipelines, six natural gas processing plants, seven natural gas treating facilities and three NGL fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.

Our results of operations are determined primarily by five interrelated variables: (1) the volume of natural gas gathered through our pipelines; (2) the volume of natural gas processed; (3) the volume of NGLs fractionated; (4) the level and relationship of natural gas and NGL prices; and (5) our current contract portfolio. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio, the pricing environment for natural gas and NGLs and the price of NGLs relative to natural gas prices will dictate increases or decreases in our profitability. Our profitability is also dependent upon prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Recent Events

Merger Agreements. On November 3, 2009, the Partnership amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all of the outstanding common units of the Partnership (other than certain restricted common units owned by officers and employees) not owned by Hiland Holdings. The amendment increased the consideration payable to common unitholders of the Partnership from $7.75 to $10.00 per common unit and extended the end date under the merger agreement to December 11, 2009. On the same day, Hiland Holdings amended its merger agreement with affiliates of Harold Hamm, pursuant to which Mr. Hamm’s affiliates had agreed to acquire all

of the outstanding common units of Hiland Holdings (other than certain restricted common units owned by officers and employees) not owned by Mr. Hamm, his affiliates or the Hamm family trusts. The amendment increased the consideration payable to common unitholders of Hiland Holdings from $2.40 to $3.20 per common unit and extended the end date under the merger agreement to December 11, 2009.

Hedging Transactions. On October 1, 2009, we entered into a financial swap agreement related to forecasted natural gas sales in 2010 whereby we receive a fixed price and pay a floating price based on NYMEX Henry Hub pricing for the relevant contract period as the underlying natural gas is sold. This swap agreement with BP Energy Company replaces a previous swap agreement we entered into with Bank of Oklahoma, N.A. on May 27, 2008. The terms of the new swap agreement are identical to the May 27, 2008 swap agreement.

SEC Filings. The Partnership and Hiland Holdings intend to file with the SEC a supplement to the definitive joint proxy statement on Schedule 14A, which, upon clearance by the SEC, the Hiland companies intend to mail to all holders of record of the Hiland companies as of September 9, 2009, the record date for the special meetings.

The definitive joint proxy statement on Schedule 14A was filed with the SEC on September 11, 2009 and first mailed to unitholders on or around September 16, 2009.

Distributions. We have suspended quarterly cash distributions on common and subordinated units beginning with the first quarter distribution of 2009 due to the impact of lower commodity prices and reduced drilling activity on our current and projected throughput volumes, midstream segment margins and cash flows combined with future required levels of capital expenditures and the outstanding indebtedness under our senior secured revolving credit facility. Under the terms of the partnership agreement, the common units will carry an arrearage of $1.35 per unit, representing the minimum quarterly distribution to common units for the first three quarters of 2009 that must be paid before the Partnership can make distributions to the subordinated units.

Historical Results of Operations

Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward primarily due to significantly decreased natural gas and NGL sales prices, volumes at our North Dakota Bakken gathering system, which commenced operations in April 2009, and increased volumes and operating expenses at our Woodford Shale and Badlands gathering systems.

Our Results of Operations

The following table presents a reconciliation of the non-GAAP financial measure of total segment margin (which consists of the sum of midstream segment margin and compression segment margin) to operating income on a historical basis for each of the periods indicated. We view total segment margin, a non-GAAP financial measure, as an important performance measure of the core profitability of our operations because it is directly related to our volumes and commodity price changes. We review total segment margin monthly for consistency and trend analysis. We define midstream segment margin as midstream revenue less midstream purchases. Midstream revenue includes revenue from the sale of natural gas, NGLs and NGL products resulting from our gathering, treating, processing and fractionation activities and fixed fees associated with the gathering of natural gas and the transportation and disposal of saltwater. Midstream purchases include the cost of natural gas, condensate and NGLs purchased by us from third parties, the cost of natural gas, condensate and NGLs purchased by us from affiliates, and the cost of crude oil purchased by us from third parties. We define compression segment margin as the revenue derived from our compression segment. Our total segment margin may not be comparable to similarly titled measures of other companies as other companies may not calculate total segment margin in the same manner.

Set forth in the tables below are certain financial and operating data for the periods indicated.


	Three Months Ended September 30,
	2009			2008
	(In thousands)

Total Segment Margin Data:
Midstream revenues	$	53,641		$	114,548
Midstream purchases		30,266			81,895

Midstream segment margin		23,375			32,653
Compression revenues(1)		1,205			1,205

Total segment margin(2)	$	24,580		$	33,858

Summary of Operations Data:
Midstream revenues	$	53,641		$	114,548
Compression revenues		1,205			1,205

Total revenues		54,846			115,753
Midstream purchases (exclusive of items shown separately below)		30,266			81,895
Operations and maintenance		7,736			7,881
Depreciation, amortization and accretion		10,472			9,554
Property impairments		20,500			—
Bad debt		—			(7,799	)
General and administrative		2,579			2,259

Total operating costs and expenses		71,553			93,790

Operating (loss) income		(16,707	)		21,963
Other income (expense)		(2,841	)		(3,322	)

Net (loss) income		(19,548	)		18,641
Add:
Depreciation, amortization and accretion		10,472			9,554
Property impairments		20,500			—
Amortization of deferred loan costs		149			147
Interest expense		2,702			3,271

EBITDA(3)	$	14,275		$	31,613

Operating Data:
Inlet natural gas (Mcf/d)		257,950			261,345
Natural gas sales (MMBtu/d)		86,979			95,889
NGL sales (Bbls/d)		7,115			6,036


	Nine Months Ended September 30,
	2009			2008
	(In thousands)

Total Segment Margin Data:
Midstream revenues	$	153,658		$	319,058
Midstream purchases		88,481			238,586

Midstream segment margin		65,177			80,472
Compression revenues(1)		3,615			3,615

Total segment margin(2)	$	68,792		$	84,087

Summary of Operations Data:
Midstream revenues	$	153,658		$	319,058
Compression revenues		3,615			3,615

Total revenues		157,273			322,673
Midstream purchases (exclusive of items shown separately below)		88,481			238,586
Operations and maintenance		23,216			22,201
Depreciation, amortization and accretion		30,981			27,652
Property impairments		21,450			—
Bad debt		—			304
General and administrative		8,458			6,423

Total operating costs and expenses		172,586			295,166

Operating (loss) income		(15,313	)		27,507
Other income (expense)		(8,096	)		(10,047	)

Net (loss) income		(23,409	)		17,460
Add:
Depreciation, amortization and accretion		30,981			27,652
Property impairments		21,450			—
Amortization of deferred loan costs		448			426
Interest expense		7,739			9,888

EBITDA(3)	$	37,209		$	55,426

Operating Data:
Inlet natural gas (Mcf/d)		268,937			245,098
Natural gas sales (MMBtu/d)		88,703			89,615
NGL sales (Bbls/d)		7,141			5,763


(1)		Compression revenues and compression segment margin are the same. There are no compression purchases associated with the compression segment.


(2)		Reconciliation of total segment margin to operating income:


	Three Months Ended September 30,
	2009			2008
	(In thousands)

Reconciliation of Total Segment Margin to Operating Income
Operating (loss) income	$	(16,707	)	$	21,963
Add:
Operations and maintenance expenses		7,736			7,881
Depreciation, amortization and accretion		10,472			9,554
Property impairments		20,500			—
Bad debt		—			(7,799	)
General and administrative		2,579			2,259

Total segment margin	$	24,580		$	33,858


	Nine Months Ended September 30,
	2009			2008
	(In thousands)

Reconciliation of Total Segment Margin to Operating Income
Operating (loss) income	$	(15,313	)	$	27,507
Add:
Operations and maintenance expenses		23,216			22,201
Depreciation, amortization and accretion		30,981			27,652
Property impairments		21,450			—
Bad debt		—			304
General and administrative expenses		8,458			6,423

Total segment margin	$	68,792		$	84,087


(3)		We define EBITDA, a non-GAAP financial measure, as net income (loss) plus interest expense, provisions for income taxes and depreciation, amortization and accretion expense. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others to assess: (1) the financial performance of our assets without regard to financial methods, capital structure or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or structure; and (4) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders and is used as a gauge for compliance with our financial covenants under our credit facility. EBITDA should not be considered an alternative to net income (loss), operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Our EBITDA may not be comparable to EBITDA of similarly titled measures of other entities, as other entities may not calculate EBITDA in the same manner as we do.

Three Months Ended September 30, 2009 Compared with Three Months Ended September 30, 2008

Revenues. Total revenues (midstream and compression) were $54.8 million for the three months ended September 30, 2009 compared to $115.8 million for the three months ended September 30, 2008, a decrease of $60.9 million, or (52.6%). This $60.9 million decrease was primarily due to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems combined with decreased natural

gas and NGL sales volumes in all but three of our gathering systems. As a result of significant reduced drilling activity in 2009 at our mid-continent areas of operations, natural gas sales volumes decreased by 3,906 MMBtu/d (MMBtu per day), or (17.4%) at the Eagle Chief gathering system, 4,654 MMBtu/d, or (29.3%) at the Matli gathering system and 5,113 MMBtu/d, or (23.1%) at the Woodford Shale gathering systems for the three months ended September 30, 2009 compared to the same period in 2008. Additionally, NGL sales volumes decreased by 72 Bbls/d (Bbls per day), or (7.2%) at the Eagle Chief gathering system and 136 Bbls/d, or (39.4%) at the Matli gathering system for the three months ended September 30, 2009 compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed natural gas sales volumes of 4,005 MMBtu/d and NGL sales volumes of 370 Bbls/d during the three months ended September 30, 2009. Natural gas sales volumes increased by 429 MMBtu/d, or 4.2% at the Montana Bakken gathering system and NGL sales volumes increased by 277 Bbls/d, or 25.8% at the Badlands gathering systems for the three months ended September 30, 2009 compared to the same period in 2008. Revenues from compression assets were the same for both periods.

Midstream revenues were $53.6 million for the three months ended September 30, 2009 compared to $114.5 million for the three months ended September 30, 2008, a decrease of $60.9 million, or (53.2%). Of this $60.9 million decrease in midstream revenues, approximately $61.2 million was attributable to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems, approximately $6.7 million was attributable to revenues from overall decreases in natural gas sales volumes, offset by approximately $7.0 million attributable to revenues from increased NGL sales volumes for the three months ended September 30, 2009 as compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed $2.2 million in midstream revenues for the three months ended September 30, 2009.

Inlet natural gas was 257,950 Mcf/d (Mcf per day) for the three months ended September 30, 2009 compared to 261,345 Mcf/d for the three months ended September 30, 2008, a decrease of 3,395 Mcf/d, or (1.3%). This decrease is primarily attributable to mid-continent volume declines totaling 13,378 Mcf/d, or (17.9%) at the Eagle Chief, Matli and Woodford Shale gathering systems offset by volumes of 4,194 Mcf/d at the North Dakota Bakken gathering system, which commenced operations in April 2009, and volume increases totaling 5,930 Mcf/d, or 3.7% at the Badlands and Kinta Area gathering systems.

Natural gas sales volumes were 86,979 MMBtu/d for the three months ended September 30, 2009 compared to 95,889 MMBtu/d for the three months ended September 30, 2008, a decrease of 8,910 MMBtu/d, or (9.3%). This 8,910 MMBtu/d decrease in natural gas sales volumes was attributable to decreased mid-continent natural gas sales volumes of 13,673 MMBtu/d, or (22.6%) at the Eagle Chief, Matli and Woodford Shale gathering systems, offset by natural gas sales volumes of 4,005 MMBtu/d at the North Dakota Bakken gathering system, which commenced operations in April 2009, and increased natural gas sales volumes totaling 1,108 MMBtu/d, or 3.7% at our Bakken and Kinta Area gathering systems.

NGL sales volumes were 7,115 Bbls/d for the three months ended September 30, 2009 compared to 6,036 Bbls/d for the three months ended September 30, 2008, an increase of 1,079 Bbls/d, or 17.9%. This 1,079 Bbls/d increase in NGL sales volumes is primarily attributable to increased NGL sales volumes totaling 984 Bbls/d, or 43.6% at the Woodford Shale and Badlands gathering systems and NGL sales volumes of 370 Bbls/d at the North Dakota Bakken gathering system, which commenced operations in April 2009, offset by reduced NGL sales volumes totaling 266 Bbls/d, or (7.4%) at our Bakken, Eagle Chief and Matli gathering systems.

Average realized natural gas sales prices were $3.25 per MMBtu for the three months ended September 30, 2009 compared to $7.57 per MMBtu for the three months ended September 30, 2008, a decrease of $4.32 per MMBtu, or (57.1%). Average realized NGL sales prices were $0.76 per gallon for the three months ended September 30, 2009 compared to $1.55 per gallon for the three months ended September 30, 2008, a decrease of $0.79 per gallon or (51.0%). The decrease in our average realized natural gas and NGL sales prices was primarily a result of significantly lower index prices for natural gas and posted prices for NGLs during the three months ended September 30, 2009 compared to the three months ended September 30, 2008.

Net cash received from our counterparty on cash flow swap contracts for natural gas sales and natural gas purchase derivative transactions that closed during the three months ended September 30, 2009 totaled $2.5 million compared to $1.1 million for the three months ended September 30, 2008. The $2.5 million gain for the three months ended September 30, 2009 increased averaged realized natural gas prices to $3.25 per MMBtu from $2.94 per MMBtu, an increase of $0.31 per MMBtu, or 10.5%. The $1.1 million net gain for the three months ended September 30, 2008 increased averaged realized natural gas prices to $7.57 per MMBtu from $7.44 per MMBtu, an increase of $0.13 per MMBtu, or 1.7%. We had no cash flow swap contracts for NGLs during the three months ended September 30, 2009. Cash paid to our counterparty on cash flow swap contracts for NGL derivative transactions that closed during the three months ended September 30, 2008 totaled $2.5 million. The $2.5 million loss for the three months ended September 30, 2008 reduced averaged realized NGL prices to $1.55 per gallon from $1.65 per gallon, a decrease of $0.10 per gallon, or (6.1%).

Compression revenues were $1.2 million for the each of the three months ended September 30, 2009 and 2008.

Midstream Purchases. Midstream purchases were $30.3 million for the three months ended September 30, 2009 compared to $81.9 million for the three months ended September 30, 2008, a decrease of $51.6 million, or (63.0%). This $51.6 million decrease is primarily due to significantly reduced natural gas and NGL purchase prices, resulting in decreased midstream purchases for all of our gathering systems compared to the same period in 2008, offset by $1.2 million of midstream purchases at the North Dakota Bakken gathering system, which commenced operations in April 2009.

Midstream Segment Margin. Midstream segment margin was $23.4 million for the three months ended September 30, 2009 compared to $32.7 million for the three months ended September 30, 2008, a decrease of $9.3 million, or (28.4%). The decrease is primarily due to unfavorable gross processing spreads, significantly lower average realized natural gas and NGL prices, an overall decrease in natural gas sales volumes, offset by an overall increase in NGL sales volumes. As a percent of midstream revenues, midstream segment margin was 43.6% for the three months ended September 30, 2009 compared to 28.5% for the three months ended September 30, 2008, an increase of 15.1%. This increase is attributable to (i) the positive impact of fixed fee arrangement contracts which are not affected by realized natural gas and NGL selling prices, (ii) improvements in third party processing arrangements at the Woodford Shale gathering system, (iii) increased volumes under favorable percentage-of-proceeds contracts at the North Dakota Bakken and Badlands gathering systems and (iv) gains on closed/settled derivative transactions and unrealized non-cash gains on open derivative transactions for the three months ended September 30, 2009 totaling $2.2 million compared to net losses of $1.4 million on closed/settled derivative transactions and unrealized non-cash losses on open derivative transactions for the three months ended September 30, 2008, offset by an unrealized non-cash gain of $5.6 million related to a non-qualifying mark-to-market cash flow hedge for forecasted sales in 2010.

Operations and Maintenance. Operations and maintenance expense totaled $7.7 million for the three months ended September 30, 2009 compared with $7.9 million for the three months ended September 30, 2008, a net decrease of $0.1 million, or (1.8%). The net decrease in operations and maintenance of $0.2 million compared to the same period in 2008 includes decreases totaling $0.8 million attributable to all gathering systems with the exception of insignificant increases in the Montana Bakken and Badlands gathering systems and a decrease of $0.1 million related to compression operations, offset by $0.5 million attributable to the North Dakota Bakken gathering system, which commenced operations in April 2009.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense totaled $10.5 million for the three months ended September 30, 2009 compared with $9.6 million for the three months ended September 30, 2008, an increase of $0.9 million, or 9.6%. This $0.9 million increase was primarily attributable to depreciation of $0.3 million on the North Dakota Bakken gathering system, which commenced operations in April 2009, increased depreciation of $0.3 million on the Kinta Area gathering system and increases of $0.1 million each on the Badlands and Woodford Shale and gathering systems.

Bad Debt. We had no bad debt expense for the three months ended September 30, 2009. For the three months ended September 30, 2008, we had recorded a reversal of an uncollectible trade accounts receivable of $7.8 million related to a receivable from a significant customer in which we had previously reserved an allowance for uncollectible accounts of $8.1 million during the second quarter of 2008. Accordingly, we decreased our reserve for doubtful accounts to $0.3 million.

General and Administrative. General and administrative expense totaled $2.6 million for the three months ended September 30, 2009 compared with $2.3 million for the three months ended September 30, 2008, a net increase of $0.3 million, or 14.2%. General and administrative expenses of a recurring nature decreased by $0.4 million compared to the same period in 2008, but were offset by $0.7 million of expenses attributable to the going private proposals incurred in the three months ended September 30, 2009.

Other Income (Expense). Other income (expense) totaled $(2.8) million for the three months ended September 30, 2009 compared with $(3.3) million for the three months ended September 30, 2008, a decrease in expense of $0.5 million, or (15.2%). The decrease is primarily attributable lower interest rates incurred during the three months ended September 30, 2009 compared to interest rates incurred during the three months ended September 30, 2008, offset by interest expense of $0.5 million related to an interest rate swap during the three months ended September 30, 2009 which did not exist in 2008.

Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008

Revenues. Total revenues (midstream and compression) were $157.3 million for the nine months ended September 30, 2009 compared to $322.7 million for the nine months ended September 30, 2008, a decrease of $165.4 million, or (51.3%). This $165.4 million decrease was primarily due to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems combined with decreased natural gas and NGL sales volumes in all but three of our gathering systems. As a result of significant reduced drilling activity in 2009 at our mid-continent areas of operations, natural gas sales volumes decreased by 4,046 MMBtu/d, or (17.5%) at the Eagle Chief gathering system and 1,954 MMBtu/d, or (13.5%) at the Matli gathering system for the nine months ended September 30, 2009 compared to the same period in 2008. NGL sales volumes decreased by 100 Bbls/d, or (9.9%) at the Eagle Chief gathering system for the nine months ended September 30, 2009 compared to the same period in 2008. Conversely, due to a 36.5% increase in inlet Mcf/d at the Woodford Shale gathering system for the nine months ended September 30, 2009, natural gas sales volumes increased by 3,011 MMBtu/d, or 18.1% and NGL sales volumes increased by 917 Bbls/d, or 80.5% compared to the same period in 2008. Due to a 44.4% increase in inlet Mcf/d at the Badlands gathering system for the nine months ended September 30, 2009, NGL sales volumes increased by 451 Bbls/d, a 50.4% increase compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed natural gas sales volumes of 1,791 MMBtu/d and NGL sales volumes of 193 Bbls/d during the nine months ended September 30, 2009. Revenues from compression assets were the same for both periods.

Midstream revenues were $153.7 million for the nine months ended September 30, 2009 compared to $319.1 million for the nine months ended September 30, 2008, a decrease of $165.4 million, or (51.8%). Of this $165.4 million net decrease in midstream revenues, approximately $188.1 million was attributable to significantly lower average realized natural gas and NGL sales prices for all of our gathering systems, approximately $2.0 million attributable to revenues from overall decreases in natural gas sales volumes, offset by approximately $24.7 million attributable to increases in NGL sales volumes for the nine months ended September 30, 2009 as compared to the same period in 2008. The North Dakota Bakken gathering system, which commenced operations in April 2009, contributed $3.2 million in midstream revenues for the three months ended September 30, 2009.

Inlet natural gas was 268,937 Mcf/d for the nine months ended September 30, 2009 compared to 245,098 Mcf/d for the nine months ended September 30, 2008, an increase of 23,839 Mcf/d, or 9.7%. This increase is primarily attributable to volume growth totaling 28,544 Mcf/d, or 16.2% at the Kinta Area, Badlands and Woodford Shale gathering systems, volumes of 2,137 Mcf/d at the North Dakota Bakken

gathering system, which commenced operations in April 2009, primarily offset by volume declines totaling 6,530 Mcf/d, or (15.8%) at the Eagle Chief and Matli gathering systems.

Natural gas sales volumes were 88,703 MMBtu/d for the nine months ended September 30, 2009 compared to 89,615 MMBtu/d for the nine months ended September 30, 2008, a net decrease of 912 MMBtu/d, or (1.0%). This 912 MMBtu/d net increase in natural gas sales volumes was attributable to decreased natural gas sales volumes totaling 6,000 MMBtu/d, or (15.9%) at the Eagle Chief and Matli gathering systems, offset by natural gas sales volumes of 1,791 MMBtu/d at the North Dakota Bakken gathering system, which commenced operations in April 2009, and increased natural gas sales volumes totaling 3,402 MMBtu/d, or 13.2% at the Woodford Shale and Kinta Area gathering systems.

NGL sales volumes were 7,141 Bbls/d for the nine months ended September 30, 2009 compared to 5,763 Bbls/d for the nine months ended September 30, 2008, a net increase of 1,378 Bbls/d, or 23.9%. This 1,378 Bbls/d net increase in NGL sales volumes is primarily attributable to increased NGL sales volumes totaling 1,368 Bbls/d, or 67.3% at our Woodford Shale and Badlands gathering systems, NGL sales volumes of 193 Bbls/d at the North Dakota Bakken gathering system, which commenced operations in April 2009, offset by reduced NGL sales volumes totaling 177 Bbls/d, or (5.4%) at our Eagle Chief and Montana Bakken gathering systems.

Average realized natural gas sales prices were $3.32 per MMBtu for the nine months ended September 30, 2009 compared to $8.00 per MMBtu for the nine months ended September 30, 2008, a decrease of $4.68 per MMBtu, or (58.5%). Average realized NGL sales prices were $0.67 per gallon for the nine months ended September 30, 2009 compared to $1.53 per gallon for the nine months ended September 30, 2008, a decrease of $0.86 per gallon or (56.2%). The decrease in our average realized natural gas and NGL sales prices was primarily a result of significantly lower index prices for natural gas and posted prices for NGLs during the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008.

Net cash received from our counterparty on cash flow swap contracts for natural gas sales and natural gas purchase derivative transactions that closed during the nine months ended September 30, 2009 totaled $7.3 million compared to $1.4 million for the nine months ended September 30, 2008. The $7.3 million gain for the nine months ended September 30, 2009 increased averaged realized natural gas prices to $3.32 per MMBtu from $3.02 per MMBtu, an increase of $0.30 per MMBtu, or 9.9%. The $1.4 million net gain for the nine months ended September 30, 2008 increased averaged realized natural gas prices to $8.00 per MMBtu from $7.95 per MMBtu, an increase of $0.05 per MMBtu, or 0.6%. We had no cash flow swap contracts for NGLs during the nine months ended September 30, 2009. Cash paid to our counterparty on cash flow swap contracts for NGL derivative transactions that closed during the nine months ended September 30, 2008 totaled $7.9 million. The $7.9 million loss for the nine months ended September 30, 2008 reduced averaged realized NGL prices to $1.53 per gallon from $1.64 per MMBtu, a decrease of $0.11 per gallon, or (6.7%).

Compression revenues were $3.6 million for the each of the nine months ended September 30, 2009 and 2008.

Midstream Purchases. Midstream purchases were $88.5 million for the nine months ended September 30, 2009 compared to $238.6 million for the nine months ended September 30, 2008, a decrease of $150.1 million, or (62.9%). This $150.1 million decrease is primarily due to significantly reduced natural gas and NGL purchase prices, resulting in decreased midstream purchases for all of our gathering systems compared to the same period in 2008, with the exception of $1.7 million of midstream purchases at the North Dakota Bakken gathering system, which commenced operations in April 2009.

Midstream Segment Margin. Midstream segment margin was $65.2 million for the nine months ended September 30, 2009 compared to $80.5 million for the nine months ended September 30, 2008, a decrease of $15.3 million, or (19.0%). The decrease is primarily due to unfavorable gross processing spreads and significantly lower average realized natural gas and NGL prices, an overall decrease in natural gas sales volumes, offset by an overall increase in NGL sales volumes, and additionally offset by approximately $2.3 million of foregone margin as a result of the nitrogen rejection plant at the Badlands gathering system being taken out of service due to equipment failure during the three months ended March 31, 2008. As a

percent of midstream revenues, midstream segment margin was 42.4% for the nine months ended September 30, 2009 compared to 25.2% for the nine months ended September 30, 2008, an increase of 17.2%. This increase is attributable to (i) the positive impact of fixed fee arrangement contracts which are not affected by realized natural gas and NGL selling prices, (ii) improvements in third party processing arrangements at the Woodford Shale gathering system, (iii) increased volumes under favorable percentage-of-proceeds contracts at the North Dakota Bakken and Badlands gathering systems and (iv) gains on closed/settled derivative transactions and unrealized non-cash gains on open derivative transactions for the nine months ended September 30, 2009 totaling $7.1 million compared to net losses of $6.4 million on closed/settled derivative transactions and unrealized non-cash losses on open derivative transactions for the nine months ended September 30, 2008, offset by an unrealized non-cash gain of $3.6 million related to a non-qualifying mark-to-market cash flow hedge for forecasted sales in 2010.

Operations and Maintenance. Operations and maintenance expense totaled $23.2 million for the nine months ended September 30, 2009 compared with $22.2 million for the nine months ended September 30, 2008, a net increase of $1.0 million, or 4.6%. The net increase in operations and maintenance of $0.9 million compared to the same period in 2008 includes (i) increases of $1.0 million at the Badlands gathering system, (ii) $1.0 million attributable to the North Dakota Bakken gathering system, which commenced operations in April 2009, (iii) decreases totaling $0.9 million at the Kinta Area, Worland, Eagle Chief, Matli and Woodford Shale gathering systems and (iv) a decrease of $0.2 million related to compression operations.

Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense totaled $31.0 million for the nine months ended September 30, 2009 compared with $27.7 million for the nine months ended September 30, 2008, an increase of $3.3 million, or 12.0%. This $3.3 million increase was primarily attributable to increased depreciation of $1.1 million on the Kinta Area gathering system, $0.9 million on the Woodford Shale gathering system, $0.6 million on the Badlands gathering system and $0.5 million attributable to the North Dakota Bakken gathering system, which commenced operations in April 2009.

Property Impairments. As a result of recent volume declines and projected future volume declines at our Kinta Area gathering system located in southeastern Oklahoma, we recognized impairment charges of $20.5 million in September 2009. Additionally, as a result of volume declines at our natural gas gathering systems located in Texas and Mississippi, combined with significantly reduced natural gas prices, we recognized impairment charges of $1.0 million in March 2009. We had no property impairments during the nine months ended September 30, 2008.

Bad Debt. We had no bad debts for the nine months ended September 30, 2009. For the nine months ended September 30, 2008, we recorded an uncollectible trade accounts receivable of $0.3 million from a significant customer. We initially reserved an allowance for uncollectible accounts of $8.1 million from this customer during the second quarter of 2008, but reversed $7.8 million in the third quarter of 2008 upon determination that the trade receivable was collectible.

General and Administrative. General and administrative expense totaled $8.4 million for the nine months ended September 30, 2009 compared with $6.4 million for the nine months ended September 30, 2008, an increase of $2.0 million, or 31.0%. Expenses related to the going private proposals were $2.1 million for the nine months ended September 30, 2009. All other general and administrative expenses decreased by $0.1 million during the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008.

Other Income (Expense). Other income (expense) totaled $(8.1) million for the nine months ended September 30, 2009 compared with $(10.0) million for the nine months ended September 30, 2008, a decrease in expense of $2.0 million, or (20.0%). The decrease is primarily attributable lower interest rates incurred during the nine months ended September 30, 2009 compared to interest rates incurred during the nine months ended September 30, 2008, offset by interest expense of $1.4 million related to an interest rate swap during the nine months ended September 30, 2009 which did not exist in 2008.

LIQUIDITY AND CAPITAL RESOURCES

U.S. Natural Gas, Crude Oil and NGL Supplies and Outlook

The drop in demand for natural gas, crude oil and NGL products since the third quarter of 2008 continues to impact the price for natural gas, crude oil and NGLs. Natural gas prices have declined significantly since the peak NYMEX Henry Hub last day settle price of $13.11/MMBtu in July 2008 to the NYMEX Henry Hub last day settle price of $3.73 in October 2009, a 72% decline. Natural gas storage levels have recently approached 3.7 Tcf, which surpassed the November 2007 record working gas storage of 3.5 Tcf. We believe that current natural gas prices will continue to result in reduced natural gas-related drilling in our service areas until the economic environment in the United States improves and increases the demand for natural gas. WTI crude oil pricing has declined from a peak of $134.62/bbl in July 2008 to a low of $33.87/Bbl in January 2009, a 75% decline, increasing to $71.55/Bbl in October 2009, a 47% decline from July 2008. Conway NGL basket pricing, which historically has correlated to WTI crude oil pricing, has dropped since the peak Conway NGL basket pricing of $1.97/gallon in June 2008 to a low of $0.61/gallon in December 2008, a 69% decline, increasing to $0.99/gallon in September 2009, a 50% decline from June 2008. In addition, current pricing and the forward curve pricing for WTI crude oil and the Conway NGL basket has recently improved. A number of the areas in which we operate are experiencing a significant decline in drilling activity as a result of the recent decline in natural gas and crude oil prices. While we anticipate continued exploration and production activities in the areas in which we operate, albeit at depressed levels, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of natural gas and crude oil reserves. Drilling activity generally decreases as natural gas and crude oil prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Disruption to Functioning of Capital Markets

Multiple events during 2008 and 2009 involving numerous financial institutions have effectively restricted current liquidity within the capital markets throughout the United States and around the world. Despite efforts by treasury and banking regulators in the United States, Europe and other nations around the world to provide liquidity to the financial sector, capital markets currently remain constrained, particularly for non-investment grade midstream companies like Hiland. We expect that our ability to issue debt and equity at prices that are similar to offerings in recent years will be limited over the next three to six months and possibly longer should capital markets remain constrained. Although we intend to move forward with our planned capital expenditures attributable to our existing facilities, we may revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our capital expenditures may be muted by substantial cost of capital increases during this period.

Overview

Our senior secured revolving credit facility requires us to meet certain financial tests, including a maximum consolidated funded debt to EBITDA covenant ratio of 4.0 to 1.0 as of the last day of any fiscal quarter; provided that in the event that we make certain permitted acquisitions or capital expenditures, this ratio may be increased to 4.75 to 1.0 for the three fiscal quarters following the quarter in which such permitted acquisition or capital expenditure occurs. We met the permitted capital expenditure requirements for the four quarter period ended March 31, 2009 and elected to increase the ratio to 4.75 to 1.0 on March 31, 2009 for the quarters ended March 31, 2009, June 30, 2009 and September 30, 2009. During this step-up period, the applicable margin with respect to loans under the credit facility increases by 35 basis points per annum and the unused commitment fee increases by 12.5 basis points per annum. The ratio will revert back to 4.0 to 1.0 for the quarter ended December 31, 2009. If commodity prices and inlet natural gas volumes do not improve above the current forward prices and expected inlet natural gas volumes for the fourth quarter of 2009, the Partnership could be in violation of the maximum consolidated funded debt to EBITDA covenant ratio as early as December 31, 2009, unless this ratio is amended, the Partnership receives an infusion of equity capital, the Partnership’s debt is restructured or the Partnership is able to monetize “in-the-money” hedge positions. Management is continuing discussions with certain lenders under the credit facility as to ways to address a potential covenant violation. While no potential solution has been agreed to, the Partnership expects that any

solution will require the assessment of fees and increased rates, the infusion of additional equity capital or the incurrence of subordinated indebtedness by the Partnership and the suspension of distributions for a certain period of time. There can be no assurance that any such agreement will be reached with the lenders, that any required equity or debt financing will be available to the Partnership, or that the Partnership will have sufficient “in-the-money” hedges to monetize to address the maximum consolidated funded debt to EBITDA covenant ratio.

Cash Flows from Operating Activities

Our cash flows from operating activities increased by $11.8 million to $38.5 million for the nine months ended September 30, 2009 from $26.7 million for the nine months ended September 30, 2008. During the nine months ended September 30, 2009 we received cash flows from customers of approximately $165.2 million attributable to significantly lower average realized natural gas and NGL sales prices and decreased natural gas sales volumes, partially offset by increased NGL sales volumes, received $3.2 million from early settlements of derivative contracts, made cash payments to our suppliers and employees of approximately $122.7 million and made payments of interest expense of $8.0 million, net of amounts capitalized, resulting in cash received from operating activities of $37.7 million. During the same nine month period in 2008, we received cash flows from customers of approximately $303.9 million attributable to increased natural gas and NGL volumes and significantly higher average realized natural gas and NGL sales prices, made cash payments to our suppliers and employees of approximately $267.5 million and made payments of interest expense of $9.7 million, net of amounts capitalized, resulting in cash received from operating activities of $26.7 million.

Changes in cash receipts and payments are primarily due to the timing of collections at the end of our reporting periods. We collect and pay large receivables and payables at the end of each calendar month. The timing of these payments and receipts may vary by a day or two between month-end periods and cause fluctuations in cash received or paid. Working capital items, exclusive of cash, provided $5.0 million of cash flows from operating activities during the nine months ended September 30, 2009 and used $16.5 million of cash flows from operating activities during the nine months ended September 30, 2008.

Net loss for the nine months ended September 30, 2009 was $(23.4) million, an increase in net loss of $40.9 million from a net income of $17.5 million for the nine months ended September 30, 2008. Depreciation, amortization, accretion and property impairments increased by $24.8 million to $52.4 million for the nine months ended September 30, 2009 from $27.7 million for the nine months ended September 30, 2008.

Cash Flows Used for Investing Activities

Our cash flows used for investing activities, which represent investments in property and equipment, decreased by $4.9 million to $32.3 million for the nine months ended September 30, 2009 from $37.1 million for the nine months ended September 30, 2008 primarily due to reduced capital expenditures in nearly all of our gathering systems, offset by cash flows invested related to the construction of the North Dakota Bakken gathering system.

Cash Flows from Financing Activities

Our cash flows used in financing activities was $3.9 million for the nine months ended September 30, 2009, a decrease of $16.0 million from $12.1 million provided by financing activities for the nine months ended September 30, 2008. During the nine months ended September 30, 2009, we borrowed $12.0 million under our credit facility to fund internal expansion projects, repaid $11.0 million on our credit facility, distributed $4.3 million to our unitholders, and made $0.6 million payments on capital lease obligations.

During the nine months ended September 30, 2008, we borrowed $41.0 million under our credit facility to fund internal expansion projects, we received capital contributions of $1.1 million as a result of issuing common units due to the exercise of 40,705 vested unit options, we distributed $29.2 million to our unitholders, incurred debt issuance costs of $0.4 million associated with the fourth amendment to our credit facility amended in February 2008 and made $0.4 million payments on capital lease obligations.

Capital Requirements

The midstream energy business is capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:


	•	maintenance capital expenditures, which 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, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

	•	expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems, processing plants, treating facilities and fractionation facilities and to construct or acquire similar systems or facilities.

We believe that cash generated from the operations of our business will be sufficient to meet anticipated maintenance capital expenditures for the next twelve months. We anticipate that any future expansion capital expenditures may be funded through operating cash flow, long-term borrowings or other debt financings and/or equity offerings. See “Credit Facility” below for information related to our credit agreement.

North Dakota Bakken

Our North Dakota Bakken gathering system presently consists of a 68-mile gathering system located in northwestern North Dakota that gathers natural gas associated with crude oil produced from the Bakken shale and Three Forks/Sanish formations. Construction of the gathering system, associated compression and treating facilities and a processing plant commenced in October 2008 and became fully operational in May 2009. As of September 30, 2009, we have invested approximately $24.0 million in the project.

Financial Derivatives and Commodity Hedges

We have entered into certain financial derivative instruments that are classified as cash flow hedges and relate to forecasted natural gas sales in 2009 and 2010. We entered into these financial swap instruments to hedge the forecasted natural gas sales against the variability in expected future cash flows attributable to changes in commodity prices. Under these swap agreements, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold.

The following table provides information about our commodity based derivative instruments at September 30, 2009:


			Average		Fair
			Fixed		Value
Description and Production Period	Volume		Price		Asset
	(MMBtu)		(per MMBtu)

Natural Gas — Sold Fixed for Floating Price Swaps
October 2009 — September 2010		2,136,000	$	6.87	$	3,537
October 2010 — December 2010		534,000	$	6.73		341

					$	3,878

We have entered into a financial derivative instrument that is classified as a cash flow hedge and relates to forecasted interest payments under our credit facility in 2009. We entered into this financial swap instrument to hedge forecasted interest payments against the variable interest payments under our credit facility. Under this swap agreement, we pay a fixed interest rate and receive a floating rate based on one

month LIBOR on the notional amount for the contract period. The following table provides information about our interest rate swap at September 30, 2009 for the periods indicated:


						Fair Value
	Notional		Interest			Asset
Description and Period	Amount		Rate			(Liability)

Interest Rate Swap
October 2009 — December 2009	$	100,000		2.245	%	$	(512	)

Off-Balance Sheet Arrangements

We had no significant off-balance sheet arrangements as of September 30, 2009.

Available Credit

Credit markets in the United States and around the world remain constrained due to a lack of liquidity and confidence in a number of financial institutions. As a non-investment grade midstream company, we are currently experiencing difficulty accessing bank credit markets. Additionally, existing constraints in the credit markets may increase the rates we are charged for utilizing these markets.

Credit Facility

Our borrowing capacity under our senior secured revolving credit facility, as amended, is $300.0 million consisting of a $291.0 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “Acquisition Facility”) and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “Working Capital Facility”).

Indebtedness under the credit facility will bear interest, at our option, at either: (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of: (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus 1/2 of 1%. We have elected for the indebtedness to bear interest at LIBOR plus the applicable margin. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility. During the step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be increased by 12.5 basis points per annum. At September 30, 2009, the interest rate on outstanding borrowings from our credit facility was 2.87%.

We are subject to interest rate risk on our credit facility and have entered into an interest rate swap to reduce this risk. See Note 5 “Derivatives” for a discussion of our interest rate swap.

The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from such distributions. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material changes to the nature of its business, amend its material agreements, including the Omnibus Agreement or enter into a merger, consolidation or sale of assets.

The credit facility limits distributions to our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the revolving working capital facility. The revolving working capital facility is subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.

Impact of Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods presented.

Recent Accounting Pronouncements

for SEC registrants. Codification is not intended to change GAAP. The adoption of this new accounting guidance had no impact on our financial statements and disclosures therein.

to evaluate the nature and financial effects of the business combination. This guidance was adopted effective January 1, 2009 and will apply to future business combinations.

In December 2007, the FASB issued authoritative guidance clarifying that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This guidance requires the equity amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income are now determined without deducting minority interest; however, earnings-per-share information continues to be calculated on the basis of the net income attributable to the parent’s shareholders. Additionally, this guidance establishes a single method for accounting for changes in a parent’s ownership interest in a subsidiary that does not result in deconsolidation and that the parent recognize a gain or loss in net income when a subsidiary is deconsolidated. This guidance is effective for fiscal years beginning on or after December 15, 2008, was adopted effective January 1, 2009 and did not have a material impact on our financial position, results of operations or cash flows.

Significant Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical.

There have been no material changes in our significant accounting policies and estimates during the three and nine months ended September 30, 2009. See our disclosure of significant accounting policies and estimates in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 9, 2009.


Item 3.	*Quantitative and Qualitative Disclosures about Market Risk*

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk for natural gas and NGLs. We also incur, to a lesser extent, risks related to interest rate fluctuations. We do not engage in commodity energy trading activities.

Commodity Price Risks. Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Our cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders. To illustrate the impact of changes in prices for natural gas and NGLs on our operating results, we have provided the table below, which reflects, for the three months ended September 30, 2009 and 2008, respectively, the impact on our midstream segment margin of a $0.01 per gallon change (increase or decrease) in NGL prices coupled with a $0.10 per MMBtu change (increase or decrease) in the price of natural gas.


				Natural Gas Price Change ($/MMBtu)
				Three Months Ended September 30,
				2009						2008

				$	0.10		$	(0.10	)	$	0.10		$	(0.10	)
NGL Price Change ($/gal)	$	0.01		$	177,000		$	159,000		$	130,000		$	156,000
	$	(0.01	)	$	(159,000	)	$	(177,000	)	$	(159,000	)	$	(134,000	)

The increase in commodity exposure is the result of increased NGL product sales volumes offset by decreased natural gas sales volumes during the three months ended September 30, 2009 compared to the three months ended September 30, 2008 and the increased exposure to NGL product prices in 2009 as the result of no NGL hedging contracts in 2009 compared to NGL products hedged during the three months ended September 30, 2008. The magnitude of the impact on total segment margin of changes in natural gas and NGL sales prices presented may not be representative of the magnitude of the impact on total segment margin for different commodity prices or contract portfolios. Natural gas and crude oil prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services.

We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets and the use of derivative contracts. As a result of these derivative swap contracts, we have hedged a portion of our expected exposure to natural gas prices in 2009 and 2010. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant. The following table provides information about our commodity-based derivative instruments at September 30, 2009 for the periods indicated:


			Average		Fair
			Fixed		Value
Description and Production Period	Volume		Price		Asset
	(MMBtu)		(Per MMBtu)

Natural Gas — Sold Fixed for Floating Price Swaps
October 2009 — September 2010		2,136,000	$	6.87	$	3,537
October 2010 — December 2010		534,000	$	6.73		341

					$	3,878

Interest Rate Risk. We have elected for the indebtedness under our credit facility to bear interest at LIBOR plus the applicable margin. We are exposed to changes in the LIBOR rate as a result of our credit facility, which is subject to floating interest rates. On October 7, 2008, we entered into a floating-to-fixed interest rate swap agreement with an investment grade counterparty whereby we pay a monthly fixed interest rate of 2.245% and receive a monthly variable rate based on the one month posted LIBOR interest rate on a notional amount of $100.0 million. This swap agreement was effective on January 2, 2009 and terminates on January 1, 2010. As of September 30, 2009, we had approximately $253.1 million of indebtedness outstanding

under our credit facility, of which $153.1 million is exposed to changes in the LIBOR rate. The impact of a 100 basis point increase in interest rates on the amount of current debt exposed to variable interest rates would for the remainder of 2009, result in an increase in annualized interest expense and a corresponding decrease in annualized net income of approximately $1.5 million. The following table provides information about our interest rate swap at September 30, 2009:


						Fair Value
	Notional		Interest			Asset
Description and Period	Amount		Rate			(Liability)

Interest Rate Swap
October 2009 — December 2009	$	100,000		2.245	%	$	(512	)

Credit Risk. Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. Our four largest customers for the nine months ended September 30, 2009, accounted for approximately 21%, 14%, 12% and 9%, respectively, of our revenues. Consequently, changes within one or more of these companies operations have the potential to impact, both positively and negatively, our credit exposure and make us subject to risks of loss resulting from nonpayment or nonperformance by these or any of our other customers. Any material nonpayment or nonperformance by our key customers could materially and adversely affect our business, financial condition or results of operations and reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Our counterparties for our commodity based derivative instruments as of September 30, 2009 are BP Energy Company and Bank of Oklahoma, N.A. Our counterparty to our interest rate swap as of September 30, 2009 is Wells Fargo Bank, N.A.

On July 22, 2008, SemGroup, L.P. and certain subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. In October 2008, the United States Bankruptcy Court for the District of Delaware entered an order approving the assumption of a Natural Gas Liquids Marketing Agreement (the “SemStream Agreement”) between SemStream, L.P., an affiliate of SemGroup, L.P., and us relating to sales of natural gas liquids and condensate at our Bakken and Badlands plants and gathering systems, restoring us and SemStream, L.P. to our pre-bankruptcy contractual relationship. Our pre-petition credit exposure to SemGroup, L.P. relating to condensate sales to SemCrude, LLC in our mid-continent region is approximately $0.3 million, which continues to be reserved as of September 30, 2009.


Item 4.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2009, to ensure that information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

(b) Changes in internal control over financial reporting.

During the three months ended September 30, 2009, there were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.	*Legal Proceedings*

On July 10, 2009, the court in which the Oklahoma case is pending granted our motion to stay the Oklahoma lawsuit in favor of the Delaware lawsuits. On July 31, 2009, the plaintiff in the first-filed Delaware case (Pasternack) filed an Amended Class Action Complaint and a motion to enjoin the mergers. This Amended Class Action Complaint alleges, among other things, that (i) the original consideration and revised consideration offered by the Hamm Parties is unfair and inadequate, (ii) the members of the conflicts committees of the general partner of each of the Partnership and Hiland Holdings that were charged with reviewing the proposals and making a recommendation to each committee’s respective board of directors lacked any meaningful independence, (iii) the defendants acted in bad faith in recommending and approving the Hiland Partners Merger or the Hiland Holdings Merger, and (iv) the disclosures in the Preliminary Proxy Statement filed by the Partnership and Hiland Holdings are materially misleading. The Pasternack plaintiff seeks to preliminarily enjoin the defendants from proceeding with or consummating the mergers and seeks an order requiring defendants to supplement the Preliminary Proxy Statement with certain information. On August 13, 2009, the Partnership, Hiland Holdings and certain individual defendants moved to dismiss the claims added in the July 31, 2009 Amended Class Action Complaint. The plaintiffs moved to expedite proceedings on September 4, 2009. On September 4, 2009, the plaintiffs filed a motion to expedite the proceedings. On September 9, 2009, the Delaware Chancery Court requested that the defendants file a response to plaintiffs’ motion that same day and set a hearing on plaintiffs’ motion for September 11, 2009. Defendants responded to plaintiffs’ motion as ordered by the Court, and, following the hearing on September 11, 2009, plaintiffs’ motion to expedite the proceedings was denied.

We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits.

We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.


Item 1A.	*Risk Factors*

The failure to complete the Hiland Partners Merger could adversely affect the price of our common units and otherwise have an adverse effect on us.

There can be no assurance that the conditions to the completion of the Hiland Partners Merger, many of which are out of our control, will be satisfied by the December 11, 2009 deadline set forth in the amended merger agreement. Among other things, we cannot be certain that (i) holders of a majority of our common units (other than Hiland Holdings) will vote in favor of the Hiland Partners Merger and the merger agreement; (ii) no injunction will be granted in any of the three pending unitholder lawsuits challenging the Hiland

Partners Merger (as described elsewhere in this Form 10-Q); or (iii) that the Hiland Holdings Merger will be completed concurrently with the Hiland Partners Merger (the completion of which is a condition to Harold Hamm’s obligation to complete the Hiland Partners Merger). Additionally, if we do not receive the required unitholder approval of the Hiland Partners Merger Agreement and the Hiland Partners Merger at a special meeting held on or before December 4, 2009, pursuant to the terms of our Partnership Agreement, we will have to set a new record date and resolicit proxies in connection with a new vote on the proposals. Whether or not we will be able to hold a unitholder vote on or before December 4, 2009 is subject to a variety of risks, including the risk that we will not receive clearance of the proxy supplement a sufficient amount of time prior to December 4, 2009 to permit distribution of the supplement. This could materially delay the completion of the Hiland Partners Merger.

If the Hiland Partners Merger is not completed, the price of our common units could fall to the extent that the current market price of our common units reflects an assumption that a transaction will be completed. Further, a failed transaction may result in negative publicity and/or a negative impression of us in the investment community and may affect our relationship with employees, vendors, creditors and other business partners.

Additionally, we are subject to the following risks related to the Hiland Partners Merger:


	•	Certain costs relating to the Hiland Partners Merger, including legal, accounting and financial advisory fees, are payable by us whether or not the Hiland Partners Merger is completed.

	•	Under circumstances set out in the merger agreement, if the Hiland Partners Merger is not completed we may be required to reimburse up to $1,420,000 of Mr. Hamm and his affiliates’ expenses associated with the Hiland Partners Merger.

	•	Our management’s and our employees’ attention will have been diverted from our day-to-day operations, we may experience unusually high employee attrition and our business and customer relationships may be disrupted.

We are subject to litigation related to the Hiland Partners Merger.

We are actively defending three putative unitholder class action lawsuits which have been filed relating to the Hiland Partners Merger and the Hiland Holdings Merger. These lawsuits are as follows: (i) Robert Pasternack v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4397-VCS; (ii) Andrew Jones v. Hiland Partners, LP et al., In the Court of Chancery of the State of Delaware, Civil Action No. 4558-VCS; and (iii) Arthur G. Rosenberg v. Hiland Partners, LP et al., In the District Court of Garfield County, State of Oklahoma, Case No. C3-09-211-02. The lawsuits name as defendants the Partnership, Hiland Holdings, the general partner of each of the Partnership and Hiland Holdings, and the members of the board of directors of each of the Partnership and Hiland Holdings. The lawsuits challenge both the Hiland Partners Merger and the Hiland Holdings Merger. The lawsuits allege claims of breach of the Partnership Agreement and breach of fiduciary duty on behalf of (i) a purported class of common unitholders of the Partnership and (ii) a purported class of our common unitholders of Hiland Holdings.

order requiring defendants to supplement the Preliminary Proxy Statement with certain information. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Hiland Partners Merger or seek monetary relief from us.

While the Hiland Companies do not believe these lawsuits have merit and intend to defend themselves vigorously, we cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. An unfavorable resolution of any such litigation surrounding the Hiland Partners Merger could delay or prevent the consummation of the Hiland Partners Merger. In addition, the cost to us of defending the litigation, even if resolved in our favor, could be substantial. Such litigation could also divert the attention of our management and our resources in general from day-to-day operations.

If commodity prices and inlet natural gas volumes do not improve above the expected prices and inlet natural gas volumes for the fourth quarter of 2009, we may be in violation of the maximum consolidated funded debt to EBITDA covenant ratio as early as December 31, 2009, unless the ratio is amended, the senior secured revolving credit facility is restructured, we receive an infusion of equity capital or the Partnership is able to monetize “in-the-money” hedge positions. Failure to comply with the covenants could cause an event of default under our credit facility.

Our credit facility contains covenants requiring us to maintain certain financial ratios and comply with certain financial tests, which, among other things, require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios or conditions as follows:


	•	EBITDA to interest expense of not less than 3.0 to 1.0; and

	•	consolidated funded debt to EBITDA of not more than 4.0 to 1.0 with the option to increase the consolidated funded debt to EBITDA ratio to not more than 4.75 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $40 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).

As of September 30, 2009, we were in compliance with each of these ratios, which are tested quarterly. Our EBITDA to interest expense ratio was 4.93 to 1.0 and our consolidated funded debt to EBITDA ratio was 4.50 to 1.0. We temporarily increased the ratio to 4.75 to 1.0 on March 31, 2009, but such ratio will be reduced to 4.0 to 1.0 on December 31, 2009. Our ability to remain in compliance with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If commodity prices and inlet natural gas volumes do not improve above the expected prices and inlet natural gas volumes for the fourth quarter of 2009, we may be in violation of the maximum consolidated funded debt to EBITDA ratio as early as December 31, 2009, unless the ratio is amended, the senior secured revolving credit facility is restructured, we receive an infusion of equity capital or the Partnership is able to monetize “in-the-money” hedge positions. Our failure to comply with any of the restrictions and covenants under our revolving credit facility could lead to an event of default and the acceleration of our obligations under those agreements. We may not have sufficient funds to make such payments. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our common units or other equity, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing the Partnership. Additional risks

and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/ or operating results.


Item 2.	*Unregistered Sales of Equity Securities and Use of Proceeds*

None.


Item 3.	*Defaults Upon Senior Securities*

None.


Item 4.	*Submission of Matters to a Vote of Security Holders*

None.


Item 5.	*Other Information*

None.


Item 6.	*Exhibits*


Exhibit
Number				Description

	2	.1	—	Acquisition Agreement by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of September 1, 2005 (incorporated by referenced to Exhibit 2.1 of Registrant’s Form 8-K filed September 29, 2005).
	2	.2	—	Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K.
	2	.3	—	Equity Commitment Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC (incorporated by reference to Exhibit 2.2 of Registrant’s Form 8-K filed on June 1, 2009).
	2	.4	—	Support Agreement, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.3 of Registrant’s Form 8-K filed on June 1, 2009).LLC (incorporated by reference to Exhibit 2.3 of Registrant’s Form 8-K filed on June 1, 2009).
	2	.5	—	Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K.
	2	.6	—	Equity Commitment Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC (incorporated by reference to Exhibit 2.3 of Hiland Holdings’ Form 8-K filed on June 1, 2009).
	2	.7	—	Support Agreement, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, Harold Hamm, Continental Gas Holdings, Inc., Bert Mackie, as trustee of the Harold Hamm DST Trust and the Harold Hamm HJ Trust, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1, 2009).
	2	.8	—	Amendment No. 1, dated October 26, 2009, to the Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K filed on October 27, 2009).


Exhibit
Number				Description

	2	.9	—	Amendment No. 1, dated October 26, 2009, to the Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on October 27, 2009).
	3	.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to Exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
	3	.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
	3	.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).
	4	.1	—	Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
	4	.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to Exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
	4	.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
	4	.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).
	19	.1	—	Code of Ethics for Chief Executive Officer and Senior Finance Officers (incorporated by reference to Exhibit 19.1 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
	31	.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.


†		Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

*		Constitutes management contracts or compensatory plans or arrangements.

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 in Enid, Oklahoma, on this 9th day of November, 2009.

HILAND PARTNERS, LP

By: Hiland Partners GP, LLC, its general partner


	By:	/s/ Joseph L. Griffin

Joseph L. Griffin

Chief Executive Officer, President and Director

(principal executive officer)


	By:	/s/ Matthew S. Harrison

Matthew S. Harrison

Chief Financial Officer, Vice President-Finance, Secretary and Director (principal financial and accounting officer)

Exhibit Index


2	.1	—	Acquisition Agreement by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of September 1, 2005 (incorporated by referenced to Exhibit 2.1 of Registrant’s Form 8-K filed September 29, 2005).
2	.2	—	Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K.
2	.3	—	Equity Commitment Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC (incorporated by reference to Exhibit 2.2 of Registrant’s Form 8-K filed on June 1, 2009).
2	.4	—	Support Agreement, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.3 of Registrant’s Form 8-K filed on June 1, 2009).
2	.5	—	Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1, 2009). Schedules and Exhibits are omitted pursuant to Section 601(b)(2) of Regulation S-K.
2	.6	—	Equity Commitment Letter Agreement, dated as of June 1, 2009, by and between Harold Hamm and HH GP Holding, LLC (incorporated by reference to Exhibit 2.3 of Hiland Holdings’ Form 8-K filed on June 1, 2009).
2	.7	—	Support Agreement, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, Harold Hamm, Continental Gas Holdings, Inc., Bert Mackie, as trustee of the Harold Hamm DST Trust and the Harold Hamm HJ Trust, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on June 1, 2009).
2	.8	—	Amendment No. 1, dated October 26, 2009, to the Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Partners, LP, Hiland Partners GP, LLC, HH GP Holding, LLC and HLND MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Registrant’s Form 8-K filed on October 27, 2009).
2	.9	—	Amendment No. 1, dated October 26, 2009, to the Agreement and Plan of Merger, dated as of June 1, 2009, by and between Hiland Holdings GP, LP, Hiland Partners GP Holdings, LLC, HH GP Holding, LLC and HPGP MergerCo, LLC (incorporated by reference to Exhibit 2.1 of Hiland Holdings’ Form 8-K filed on October 27, 2009).
3	.1	—	Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3	.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
3	.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
3	.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).
4	.1	—	Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
4	.2	—	First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to Exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
4	.3	—	Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)).
4	.4	—	Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to Exhibit 10.2 of Registrant’s Form 8-K filed on September 29, 2006).


19	.1	—	Code of Ethics for Chief Executive Officer and Senior Finance Officers (incorporated by reference to Exhibit 19.1 of Registrant’s annual report on Form 10-K filed on March 30, 2005).
31	.1	—	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
31	.2	—	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
32	.1	—	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
32	.2	—	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.


†		Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

*		Constitutes management contracts or compensatory plans or arrangements.

Hiland Partners, LP 10-Q