UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended ~~June~~September 30, 2016

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: 000-53795

REEF OIL & GAS INCOME AND DEVELOPMENT FUND III, L.P.

(Exact name of registrant as specified in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)

26-0805120
(I.R.S. Employer
Identification No.)

1901 N. Central Expressway, Suite 300, Richardson, Texas 75080-3610

(Address of principal executive offices including zip code)

(Registrant’s telephone number, including area code) — (972) 437-6792

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 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 x 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.

Large accelerated filer ¨o Accelerated filer ¨o Non-accelerated filer o Smaller reporting company x

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

As of ~~August~~November 1215, 2016, the registrant had 885.6999 units of limited partner interest outstanding, and 8.9697 units of general partner interest and 1.3000 of limited partner interest held by the managing general partner.

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Reef Oil & Gas Income and Development Fund III, L.P.

Form 10-Q Index

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements
	Condensed Balance Sheets
	Condensed Statements of Operations
	Condensed Statements of Cash Flows
	Notes to Condensed Financial Statements

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

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

ITEM 4.	Controls and Procedures

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings

ITEM 1A.	Risk Factors

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds

ITEM 3.	Default Upon Senior Securities

ITEM 4.	Mine Safety Disclosures

ITEM 5.	Other Information

ITEM 6.	Exhibits

Signatures

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Reef Oil & Gas Income and Development Fund III, L.P.

Condensed Balance Sheets

	June 30, 2016			December 31, 2015
	September 30, 2016			December 31, 2015
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	~~545~~344,~~798~~264		$	1,515,010
Accounts receivable from affiliates	~~159~~106,~~503~~855			135,851
Prepaid expenses	3,352			—
Total current assets	451,119			1,650,861
Total current assets	708,653			1,650,861
Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $12,566,334 and $14,737,574	416,470			760,460
Proved properties, net of accumulated depletion of $10,352,321 and $14,737,574	298,346			760,460
Net oil and gas properties	~~416~~298,~~470~~346			760,460
Total assets	$	1749,~~125,123~~465		$	2,411,321
Liabilities and partnership equity
Current liabilities:
Accounts payable	$	2224,~~040~~889		$	9,996
Total current liabilities	22,040			9,996
Accrued liabilities	13,534			—
Total current liabilities	38,423			9,996
Long term liabilities
Asset retirement obligation	~~427~~360,~~589~~505			591,945
Total long term liabilities	~~427~~360,~~589~~505			591,945
Partnership equity
General partners	—			1,302,555
Limited partners	~~742~~453,~~424~~060			468,462
Managing general partner	(66102,~~930~~523		)	38,363
Total partnership equity	~~675~~350,~~494~~537			1,809,380
Total liabilities and partnership equity	$	1749,~~125,123~~465		$	2,411,321

See accompanying notes to condensed financial statements (unaudited).

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Reef Oil & Gas Income and Development Fund III, L.P.

Condensed Statements of Operations

(Unaudited)

	For the three months ended June 30,						For the six months ended June 30,
	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
Oil, gas and NGL sales	$	~~100,279~~468		$	~~568~~272,~~829~~980		$	169,~~033~~501		$	1,~~063~~336,~~942~~922
Costs and expenses:
Lease operating expenses	~~(53~~66,~~064~~650		)	~~436~~175,~~415~~741			58125,~~564~~214			~~946~~1,~~779~~122,520
Production taxes	6(13,~~648~~748		)	3328,~~430~~903			184,~~510~~762			6291,~~963~~866
Depreciation, depletion and amortization	231,~~216~~518			~~149~~114,~~324~~562			5455,~~341~~859			~~376~~491,~~867~~429
Accretion of asset retirement obligation	52,~~215~~946			5,~~627~~643			1013,~~495~~441			4551,~~957~~600
Property impairment	~~22,816~~—			~~824~~1,~~350~~735,074			140,003			35,~~469~~204,~~416~~490
Gain on sale of oil & gas properties	—			~~(1,673,100~~—		)	(100,543		)	(1,673,100		)
General and administrative	5168,~~218~~084			~~148~~140,~~073~~174			~~143~~211,~~370~~454			~~314~~454,~~689~~863
Total costs and expenses	56125,~~049~~450			~~(75~~2,~~881~~200,097		)	~~324~~450,~~740~~190			35,~~543~~743,~~571~~668
Income (loss) from operations	44,230			644,710			(155,707		)	(2,479,629		)
Loss from operations	(124,982		)	(1,927,117		)	(280,689		)	(4,406,746		)
Other income
Miscellaneous income	425			—93			1,~~821~~846			—93
Interest income	—			—			—			2
Total other income	425			—93			1,~~821~~846			295
Net income (loss)	$	44,234		$	644,710		$	(153,886	)	$	(2,479,627	)
Net loss	$	(124,957	)	$	(1,927,024	)	$	(278,843	)	$	(4,406,651	)
Net income (loss) per general partner unit	$	—		$	537		$	—		$	(2,918	)
Net loss per general partner unit	$	—		$	(2,140	)	$	—		$	(5,058	)
Net income (loss) per limited partner unit	$	39		$	537		$	(177	)	$	(2,918	)
Net loss per limited partner unit	$	(125	)	$	(2,140	)	$	(302	)	$	(5,058	)
Net income per managing partner unit	$	1,056		$	18,762		$	280		$	12,472
Net income (loss) per managing partner unit	$	(1,516	)	$	(2,929	)	$	(1,236	)	$	9,543

See accompanying notes to condensed financial statements (unaudited).

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Reef Oil & Gas Income and Development Fund III, L.P.

Condensed Statements of Cash Flows

(Unaudited)

	For the six months ended June 30,
	For the nine months ended September 30,
	2016			2015
Cash flows from operating activities
Net loss	$	(~~153~~278,~~886~~843	)	$	(24,~~479~~406,~~627~~651	)
Adjustments to reconcile net loss to net cash used in operating activities:
Plugging and abandonment costs paid from ARO	(8,840		)	(23,~~686~~355		)
Adjustments for non-cash transactions:
Depletion, depreciation and amortization	5455,~~341~~859			~~376~~491,~~867~~429
Accretion of asset retirement obligation	1013,~~495~~441			4551,~~957~~600
Gain on sale of oil and gas properties	(100,543		)	(1,673,100		)
Property impairment	140,003			35,~~469~~204,~~416~~490
Changes in operating assets and liabilities
Accounts receivable from affiliates	~~(23~~28,~~652~~996		)	~~(164~~8,~~751~~721		)
Prepaid expenses	(3,352		)	—
Accrued liabilities	13,534			(6,247		)
Accrued liabilities	—			3,677
Net cash used in operating activities	(136,393		)	(333,113		)
Net cash used in operating activities	(85,434		)	(424,247		)
Cash flows from investing activities:
Proceeds from sale of oil and gas properties	~~121~~174,~~607~~594			~~778~~830,~~567~~464
Property development	(3743,~~429~~840		)	(~~229~~272,~~878~~909		)
Net cash provided by investing activities	84130,~~178~~754			~~548~~557,~~689~~555
Cash flows from financing activities:
Distributions to partners	(~~967~~1,~~956~~165,107		)	(~~280~~17,748		)
Net cash used in financing activities	(~~967~~1,~~956~~165,107		)	(~~280~~17,748		)
Net increase (decrease) in cash and cash equivalents	(~~969~~1,~~212~~170,746		)	~~124~~206,~~162~~694
Cash and cash equivalents, beginning of period	1,515,010			368,620
Cash and cash equivalents, end of period	$	~~545~~344,~~798~~264		$	~~492~~575,~~782~~314
Supplemental cash flow disclosure
Supplemental disclosure of non-cash investing transactions
Asset retirement obligation reduction resulting from sale and disposition of proved properties	$	~~166~~236,~~011~~041		$	1,~~851~~859,~~493~~763
Partner distributions suspensed and included in accounts payable	$	1214,~~044~~893		$	186
Property sales included in accounts receivable from affiliates	$	—		$	~~229~~181,~~542~~610

See accompanying notes to condensed financial statements (unaudited).

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Reef Oil & Gas Income and Development Fund III, L.P.

Notes to Condensed Financial Statements (unaudited)

~~June~~September 30, 2016

1. Organization and Basis of Presentation

The condensed financial statements of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first ~~six~~nine months of 2016. Therefore, please read these unaudited condensed financial statements and notes to unaudited condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “Annual Report”). The results of operations for the three and ~~six~~nine month periods ended ~~June~~September 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Going Concern

The accompanying financial statements have been prepared assuming the Partnership is a going concern. Our independent registered public accounting firm’s opinion included in our Annual Report includes an explanatory paragraph regarding the Partnership’s limited life, and management’s plan to sell all remaining assets of the Partnership, wind up and terminate the Partnership during 2016, as specified in the Partnership’s governing documents at its inception. It is likely that the sale of all Partnership assets will not be completed until early 2017, and the termination of the Partnership will not occur until 2017. As of September 30, 2016 the Partnership owned interests in approximately 280 wells, compared to over 600 wells at December 31, 2015. Reef does not expect sales proceeds from the sale of the Partnership’s remaining assets will allow partners to recover their full investment in the Partnership. In accordance with generally accepted accounting principles for a limited life entity, the Partnership has not applied the liquidation basis of accounting to these financial statements.

Conversion of General Partner Interests

In accordance with the Partnership’s Limited Partnership Agreement, all units of general partner interest are to be converted to units of limited partner interest in the year following completion of drilling activities of the Partnership. During October of 2015, management of the Partnership initiated a plan to sell all of the Partnership’s assets, and, in connection with that plan, the Partnership has ceased participation in drilling activities. Effective March 1, 2016, with the exception of certain interest held by the managing general partner, all other units of general partner interest held by investor partners were converted into units of limited partner interest. Investor general partners will have limited liability as a limited partner for any Partnership operations conducted after the conversion date. However, investor general partners continue to have unlimited liability regarding Partnership activities that occurred prior to the conversion date.

2. Summary of Accounting Policies

Oil and Gas Properties

The Partnership follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful, as well as unsuccessful, exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 thousand cubic feet (“Mcf”) of natural gas to 1 barrel (“Bbl”) of crude oil. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would ~~significantly alter the relationship between capitalized costs and proved reserves. During the three and six month~~

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significantly alter the relationship between capitalized costs and proved reserves. During the three and nine month periods ended ~~June~~September 30, 2016, the Partnership recognized gain on sale of oil and gas properties totaling $0 and $100,543, respectively. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2015, the Partnership recognized gain on sale of oil and gas properties totaling $~~1,673,100~~0 and $1,673,100, respectively.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost ceiling, which is defined as the sum of the estimated future net revenues from the Partnership’s proved reserves using prices that are the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2016, the Partnership recognized $~~22,816~~0 and $140,003 of impairment expense of proved properties, respectively. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2015, the Partnership recognized $~~824~~1,~~350~~735,074 and $35,~~469~~204,~~416~~490 of impairment expense of proved properties, respectively.

Estimates of Proved Oil and Gas Reserves

The estimates of the Partnership’s proved reserves at ~~June~~September 30, 2016 and December 31, 2015 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and end of period costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information at ~~June~~September 30, 2016 and December 31, 2015 was based upon evaluations prepared by the senior reservoir engineer for Reef Exploration, L.P. (“RELP”), an affiliate of the Partnership and Reef Oil and Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership.

Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing future net income. A decline in estimated proved reserves and future cash flows, whether caused by declining commodity prices or downward adjustments to the rate of production from Partnership wells, also reduces the capitalized cost ceiling and may result in increased impairment expense.

Restoration, Removal, and Environmental Liabilities

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or reliably determinable.

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The Partnership has recognized an estimated liability for future plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.

The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.

The following table summarizes the Partnership’s asset retirement obligation for the ~~six~~nine month period ended ~~June~~September 30, 2016 and the year ended December 31, 2015.

	Six months ended June 30, 2016			Year ended December 31, 2015
	Nine months ended September 30, 2016			Year ended December 31, 2015
Beginning asset retirement obligation	$	591,945		$	2,528,422
Retirement related to sale and disposition of proved properties	(~~166~~236,~~011~~041		)	(1,988,403		)
Retirement related to property abandonment and restoration	(8,840		)	(4,170		)
Accretion expense	1013,~~495~~441			56,096
Ending asset retirement obligation	$	~~427~~360,~~589~~505		$	591,945

Fair Value of Financial Instruments

The estimated fair value of cash and cash equivalents, accounts receivable from affiliates, ~~prepaid~~accounts ~~expenses~~payable, and ~~accounts~~accrued ~~payable~~liabilities approximates their carrying value due to their short-term nature.

Recent Accounting Developments — Revenue Recognition

The following recently issued accounting pronouncement has been adopted or may impact the Partnership in future periods:

The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”) in May 2014, which provides accounting guidance for all revenues arising from contracts to provide goods or services to customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following five steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract(s); (5) recognize revenue when (or as) the entity satisfies a performance obligation. The requirements of ASU 2014-09 will supersede prior revenue recognition requirements and most prior industry-specific guidance throughout the FASB’s accounting standards codification, and will be effective for all interim and annual periods beginning after December 15, 2017. The Partnership is still considering the method of adoption but does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flow.

3. Transactions with Affiliates

Reef initially purchased 1% of the total Partnership units (8.9697 units of general partner interest), and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. In addition, Reef has purchased 1.30 units of Partnership interest from investor partners. Effective September 1, 2015 Reef receives 11.13% and investor partners receive 88.87% of total cash distributions. During the ~~six~~nine month periods ended ~~June~~September 30, 2016 and 2015, Reef received $~~109~~131,~~088~~349 and $01,965, respectively, in cash distributions related to its Partnership interest.

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The Partnership has no employees. RELP employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. RELP is entitled to receive drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP served as the operator of the Partnership’s Slaughter Field in Cochran County, Texas and the wells in which the Partnership held an interest thereon (the “Slaughter Dean Wells”) prior to their sale during the second quarter of 2015. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for all non-operated wells. ~~Total~~While ~~well~~the ~~costs~~Partnership ~~include~~has ~~all~~not ~~drilling~~engaged ~~and~~in ~~equipment~~oil ~~costs,~~and ~~including~~gas ~~intangible~~drilling ~~development~~activities ~~costs, tangible costs~~ during ~~drilling and completion of a well~~2016, ~~costs of storage and other surface facilities, and the costs of gathering pipelines necessary to connect the well to the nearest appropriate delivery point. In addition,~~ total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion. Total well costs do not include costs relating to lease acquisitions. During the ~~six~~nine month period ended ~~June~~September 30, 2016 and the year ended December 31, 2015, RELP received $1,~~158~~175 and $13,564, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.

Additionally, Reef and its affiliates are reimbursed for direct costs and documented out-of-pocket expenses incurred on behalf of the Partnership. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2016, the Partnership paid or accrued to Reef and its affiliates $20,~~063~~583 and $5344,~~012~~595, respectively, for direct costs and paid or accrued to Reef and its affiliates $~~740~~0 and $2,805, respectively, for out of pocket expenses. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2015, the Partnership paid or accrued to Reef and its affiliates $2617,~~019~~895 and $5067,~~068~~963, respectively, for direct costs and paid or accrued to Reef and its affiliates $~~1,406~~206 and $2,~~373~~579, respectively, for out of pocket expenses.

RELP allocates its general and administrative expenses as overhead to all of the partnerships to which it provides services, and this allocation is a significant portion of the Partnership’s general and administrative expenses. The allocation of RELP’s overhead to the partnerships to which it provides services is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2016, the administrative overhead charged by RELP to the Partnership totaled $333,~~241~~079 and $2962,~~247~~326, respectively. During the three and ~~six~~nine month periods ended ~~June~~September 30, 2015, the administrative overhead charged by RELP to the Partnership totaled $9982,~~282~~796 and $~~192~~275,~~209~~005, respectively. The administrative overhead charged by RELP is included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or third parties, but excluding direct and operating costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At ~~June~~September 30, 2016, and December 31, 2015, RELP owed the Partnership $~~159~~106,~~503~~855 and $135,851, respectively, for net revenues processed in excess of joint interest, drilling compensation, direct costs, and out-of-pocket expenses. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month to which the revenues pertain. The Partnership settles its balances with Reef and RELP on at least aan ~~quarterly~~annual basis.

4. Partnership Equity

Information regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the three and ~~six~~nine month periods ended ~~June~~September 30, 2016 is detailed below:

For the three months ended ~~June~~September 30, 2016

Type of Unit	Number of Units	Net ~~income~~loss			Net ~~income~~loss per unit
Managing general partner	8.9697	$	9(13,~~469~~593	)	$	(1,~~056~~516	)
Limited partner	886.9999	34(111,~~765~~364		)	$	39(125	)
Total	895.9696	$	44(124,~~234~~957	)

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For the ~~six~~nine months ended ~~June~~September 30, 2016

Type of Unit	Number of Units	Net ~~income (~~loss)			Net ~~income (~~loss) per unit
Managing general partner	8.9697	$	2(11,~~507~~086	)	$	~~280~~(1,236	)
Limited partner	886.9999	(~~156~~267,~~393~~757		)	$	(~~177~~302	)
Total	895.9696	$	(~~153~~278,~~886~~843	)

5. Subsequent Events

We have evaluated subsequent events through the filing date of this Form 10-Q and determined that no subsequent events have occurred that would require recognition in the financial statements or disclosure in the notes thereto other than as discussed in the accompanying notes.

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

The following is a discussion of the Partnership’s financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our unaudited condensed financial statements and related notes thereto, included in this Quarterly Report, and the audited financial statements and the related notes thereto, included in the Annual Report.

This Quarterly Report contains forward-looking statements that involve risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, and plans and objectives of management are forward looking statements. You should exercise extreme caution with respect to all forward-looking statements made in this Quarterly Report. Specifically, the following statements are forward-looking:

· statements regarding the Partnership’s overall strategy for acquiring and disposing of oil and gas properties;

· statements regarding the state of the oil and gas industry and the opportunity to profit within the oil and gas industry, competition, pricing, level of production, or the regulations that may affect the Partnership;

· statements regarding the amounts and timing of distributions;

· statements regarding the plans and objectives of Reef for future operations, including, without limitation, the uses of Partnership funds and the size and nature of the costs the Partnership expects to incur and people and services the Partnership may employ;

· any statements using the words “anticipate,” “believe,” “estimate,” “expect” and similar such phrases or words; and

· any statements of other than historical fact.

Reef believes that it is important to communicate its future expectations to our investors. Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions. Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein. All forward looking statements speak as of the filing date of this report. All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement.

Except as otherwise required by applicable law, we disclaim any duty to update forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

Going Concern

Management is currently pursuing the sale of all Partnership assets. As a result, the Partnership is not expected to continue as a going concern. While the original intent was to wind up and terminate the Partnership during 2016, it

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~~Going~~is ~~Concern~~likely that the sale of all Partnership assets will not be completed until early 2017, and the termination of the Partnership will not occur until 2017. As of September 30, 2016 the Partnership owned interests in approximately 280 wells, compared to over 600 wells at December 31, 2015. Reef does not expect sales proceeds from the sale of the Partnership’s remaining assets will allow partners to recover their full investment in the Partnership. In accordance with generally accepted accounting principles for a limited life entity, the Partnership has not applied the liquidation basis of accounting to these financial statements.

Management is currently pursuing the sale of all Partnership assets with the intent to wind up and terminate the Partnership during 2016. As a result, the Partnership is not expected to continue as a going concern. Reef does not expect sales proceeds from the sale of the Partnership’s remaining assets will allow partners to recover their investment in the Partnership. In accordance with generally accepted accounting principles for a limited life entity, the Partnership has not applied the liquidation basis of accounting to these financial statements.

Overview / Outlook

Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership formed on November 27, 2007. The Partnership was formed to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties, subject to certain market conditions, no earlier than 2010, but expected no later than 2015, in order to maximize return to the partners of the Partnership. ~~The term of the Partnership commenced on the formation date and continues until December 31, 2016, unless terminated sooner.~~ Reef is the managing general partner of the Partnership.

The Partnership sought to purchase working interests in oil and gas properties with both proved producing reserves and proved undeveloped reserves. Between November 27, 2007 and June 30, 2010, the Partnership made three major property acquisitions with the capital raised by the Partnership, referred to as the Slaughter Dean acquisition, Azalea acquisition, and Lett acquisition, and acquired working interests in over 1,500 wells located in twelve states. On all properties purchased, the Partnership planned to produce existing proved reserves and develop any proved undeveloped reserves, but not to engage in exploratory drilling for unproved reserves. Drilling locations with unproved reserves, if any, could be farmed out or sold to third parties or other partnerships formed by Reef.

The management of the operations and other business of the Partnership is the responsibility of RELP, an affiliate of Reef and the Partnership. RELP served as operator of the Slaughter Dean acquisition properties prior to their sale in 2015. All wells included in the Azalea and Lett acquisitions are operated by third parties not affiliated with the Partnership, Reef, or any other Reef affiliate. The most significant property acquired in the Azalea and Lett acquisitions was a working interest in the Thums Long Beach Unit located underneath the Long Beach Harbor in Southern California. The Thums Long Beach Unit was sold during the fourth quarter of 2015.

As a result of the decrease in commodity prices which began during the third quarter of 2014, Reef decided to delay the sale of Partnership properties until prices recovered, with the hope of maximizing return to the investor partners. The sole exception to this policy was the Partnership’s working interest in the Slaughter Dean acquisition properties. The waterflood development project implemented by Reef on the Slaughter Dean acquisition properties had not proven to be successful, and this older field exhibited high operating costs and also high workover costs. The Slaughter Dean acquisition properties were sold during the second quarter of 2015.

As commodity prices continued to decline throughout 2015, the Partnership saw its results of operations, financial position, and cash flows being severely adversely affected. The Partnership is not engaged in commodity futures trading or hedging activities, and does not have significant cash reserves on hand, since cash flows are normally distributed on a regular basis to the investor partners. During the first two quarters of 2015 working capital was being drained because the Slaughter Dean acquisition properties were being operated at a deficit. During the third quarter of 2015, lease operating costs, production taxes, and general and administrative expenses of the remaining Azalea and Lett acquisition properties exceeded revenues. Without a recovery in commodity prices, the Partnership would need to either borrow funds from Reef or sell properties to generate cash to cover the deficits. As Reef was unable to project when or if commodity prices would significantly recover, a decision was made in October 2015 to begin marketing the remaining assets of the Partnership, with expectation to complete the divestiture of properties, wind up, and terminate the Partnership during 2016. Currently Reef believes that all remaining assets will not be sold until early 2017, and the termination of the Partnership will therefore occur during 2017.

During the first quarter of 2016, the Partnership made six oil and gas property sales, totaling approximately 75 wells and representing, in the aggregate, approximately 6.5% of the Partnership’s total reserves on a BOE basis, as measured by the Partnership’s December 31, 2015 reserve report. Cash proceeds from these oil and gas property sales totaled $104,567.

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measured by the Partnership’s December 31, 2015 reserve report. Cash proceeds from these oil and gas property sales totaled $104,567.

During the second quarter of 2016, the Partnership made four oil and gas property sales, totaling approximately 125 wells and representing, in the aggregate, approximately 9.5% of the Partnership’s total reserves on a BOE basis, as measured by the Partnership’s December 31, 2015 reserve report. Cash proceeds from these oil and gas property sales totaled $17,040.

AsDuring ofthe ~~June 30,~~third quarter of 2016, the Partnership ~~continues~~made tonine ~~own~~oil ~~working~~and ~~interests~~gas inproperty ~~more~~sales, ~~than~~totaling ~~375~~approximately 135 wells ~~acquired~~and representing, in the ~~Azalea acquisition~~aggregate, ~~located~~approximately in12.2% ~~Texas,~~of ~~New~~the ~~Mexico,~~Partnership’s ~~Louisiana,~~total ~~Oklahoma,~~reserves ~~North~~on ~~Dakota,~~a ~~Mississippi~~BOE basis, ~~Montana~~as ~~and~~measured ~~Colorado.~~by ~~The~~the Partnership’s ~~divested~~December 31, of2015 ~~all~~reserve ofreport. ~~its~~Cash ~~Kansas,~~proceeds ~~Alabama,~~from ~~and~~these ~~Arkansas~~oil ~~properties~~and ~~during~~gas ~~the~~property ~~first~~sales ~~half~~totaled ~~of 2016~~$52,987.

As of September 30, 2016, the Partnership continues to own working interests in approximately 280 wells acquired in the Azalea acquisition, located in Texas, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi and Montana. The Partnership has divested of all of its Colorado, Kansas, Alabama, and Arkansas properties during the first nine months of 2016.

Liquidity and Capital Resources

The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef. Non-Reef partners purchased 490.9827 units of general partner interest and 397.0172 units of limited partner interest for $88,648,094, net of adjustments for sales to brokers for their own accounts, who were permitted to buy units at a price net of the commission that they would normally earn on sales of units. Reef contributed $762,425 for the purchase of 8.9697 units of general partner interest at a price of $85,000 per unit, which is net of the 15% management fee paid by non-Reef investors. The 15% management fee used to pay organization and offering costs, including sales commissions, totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of ~~June~~September 30, 2016, the Partnership had expended $81,~~406~~413,~~972~~383 on property acquisition and development costs, prior to sales of the Partnership’s interests or portions of its interests in certain properties. Expenditures in excess of available capital have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

Working capital has declined during the first ~~half~~nine months of 2016, from $1,640,865 at December 31, 2015 to $~~686~~412,~~613~~696 at ~~June~~September 30, 2016, primarily as a result of the distribution of sales proceeds totaling $1,165,107 received from property sales made during 2015 and 2016 to the investor partners during the first ~~quarter~~nine months of 2016. The Partnership has ~~maintained~~retained a portion of the cash received from property sales to cover any deficits during the divestiture of all remaining properties and the winding up and termination of the Partnership. The Partnership generally maintains nominal working capital, as cash flows are normally utilized to pay monthly cash distributions to ~~investors~~the partners. Sources of future funding consist of cash on hand, cash flow from operations, and cash flow from sales of properties. The Partnership may not be able to sell properties at the values desired in order to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. This discussion should be read in conjunction with the unaudited condensed financial statements and the related notes to the unaudited condensed financial statements included in this Quarterly Report.

Partnership gross revenues from the sale of oil and natural gas from Partnership properties during the third quarter of 2016 were approximately $30,000 per month, and are slowly declining as properties are divested. However, during the third quarter the Partnership reviewed and adjusted previous revenue accruals, which included revising downward the amounts of previous revenue accruals, as well as reversing previous revenue accruals on sold properties. The ~~following~~adjustment ~~table~~to ~~provides~~revenue, ~~information~~which ~~about~~totaled ~~sales~~$90,287, ~~volumes~~reduced oil and gas sales revenues from $90,755 to $468 for the third quarter of 2016. The accrual adjustments also affected production taxes by $23,368, and reduced production taxes from $9,620 to a negative amount of $13,748 for the third quarter of 2016. The Partnership expects that during the fourth quarter, assuming oil and gas prices remain relatively stable, revenues will decline from the approximate $30,000 per month level of the prior quarter, as properties continue to be divested. The Partnership saw a slight decline in the average oil price received ~~for~~from $38.37 per Bbl in the ~~periods~~second ~~indicated~~quarter to $36.00 per Bbl in the third quarter. Gas prices received rose slightly from $1.66 per Mcf during the second quarter to $1.78 per Mcf

	Three months ended June 30, 2016		Three months ended June 30, 2015		Six months ended June 30, 2016		Six months ended June 30, 2015
Sales volumes:
Oil and NGL’s (Bbls)	2,137		10,866		3,927		20,993
Natural gas (Mcf)	11,005		19,325		27,122		37,222
Sales revenues:
Oil and NGL’s (Bbls)	$	81,991	$	524,248	$	129,125	$	971,601
Natural gas (Mcf)	$	18,288	$	44,581	$	39,908	$	92,341
Average sales price received:
Oil and NGL’s (Bbls)	$	38.37	$	48.16	$	32.88	$	46.28
Natural gas (Mcf)	$	1.66	$	2.31	$	1.47	$	2.48

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~~Sales revenues declined primarily as a result of the property sales made beginning in the second quarter of 2015, but also as a result of the decline in sales prices received~~ during the ~~comparable~~third ~~periods. The second~~ quarter ~~of 2016 saw oil prices begin to recover from their low point of under $30~~.00 per Bbl reached during the first quarter of 2016, and also saw natural gas prices begin to rise. Second quarter 2016 average prices of $38.37 per Bbl of crude oil and $1.66 per Mcf of natural gas were an improvement from the average prices of $26.33 per Bbl and $1.34 received during the first quarter of 2016. However, second quarter 2016 prices for both crude oil and natural gas were still below second quarter 2015 prices by more than 20%, and average crude oil and natural gas prices for the first half of 2016 were below prices received during the first half of 2015 by 29.0% and 40.7%, respectively. Prices for crude oil have continued to hold in excess of $40 per barrel during July 2016, and natural gas prices have also been in excess of $2.00 per Mcf since July 1, 2016. Nonetheless, as a result of the property sales already made by the Partnership, it is difficult for oil and gas revenues from the Partnership’s remaining properties to cover both operating as well as administrative costs at current price levels.

The estimated net proved crude oil and natural gas reserves at ~~June~~September 30, 2016 and 2015 are summarized below. Reserve estimates are calculated using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and end of period costs. At ~~June~~September 30, 2016, the un-weighted arithmetic average prices were $4241.9197 per Bbl of crude oil and $2.2440 per Mcf of natural gas, compared to $7159.7332 per Bbl of crude oil and $3.3200 per Mcf of natural gas at ~~June~~September 30, 2015.

Proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership can estimate with reasonable certainty to be economically producible in future years from known oil and gas reservoirs under existing economic conditions, operating methods, and government regulations. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

Net proved reserves	Oil (Bbl)	Gas (Mcf)
June 30, 2016	33,250	250,650
September 30, 2016	24,880	190,060
June 30, 2015	390,180	547,390
September 30, 2015	380,860	495,710

Three months ended ~~June~~September 30, 2016 compared to the three months ended ~~June~~September 30, 2015

The Partnership had a net ~~income~~loss of $44124,~~234~~957 for the three month period ended ~~June~~September 30, 2016, compared to a net ~~income~~loss of $~~644~~1,~~710~~927,024 for the three month period ended ~~June~~September 30, 2015. ~~The~~During ~~Partnership~~the ~~recorded~~three amonth ~~gain~~period onended ~~the~~September 30, ~~sale~~2015, ofthe ~~its~~Partnership’s ~~Slaughter~~net ~~Dean~~loss ~~properties~~of ~~totaling~~ $1,~~673~~927,~~100~~024 inwas ~~June 2015,~~impacted ~~which~~by ~~was~~impairment ~~the~~of ~~primary~~proved ~~reason~~property ~~for~~totaling ~~the~~ $~~644~~1,~~710~~735,074, inwhich ~~net~~was ~~income~~recognized ~~for~~primarily ~~the~~due ~~three~~to ~~months~~lower ~~ended June 30,~~ 2015. ~~During~~commodity ~~the~~prices ~~second~~which ~~quarter~~reduced ofproved ~~2016,~~recoverable ~~the~~reserves. The Partnership ~~reversed~~did annot ~~accrual~~recognize ~~for~~any ~~2015~~impairment adof ~~valorem~~proved ~~taxes~~properties ~~totaling~~during ~~$140,000 related to~~ the ~~Slaughter~~three ~~Dean~~month ~~properties~~period ~~sold~~ended ~~during 2015~~September 30, ~~which~~2016. ~~was~~Excluding ~~the~~impairment ~~primary~~of ~~reason~~proved ~~for~~properties, the Partnership ~~having~~ net ~~income~~loss ~~during~~for the ~~second~~three ~~quarter~~month ofperiod ~~2016~~ended September 30, 2015 totaled $191,950.

~~During~~Partnership revenues totaled $468 for the three month ~~periods~~period ended ~~June~~September 30, 2016 ~~and~~compared ~~2015~~to $272,980 for the ~~Partnership~~three ~~recognized~~month ~~impairment~~period ~~expense~~ended ofSeptember 30, ~~proved~~2015. ~~property~~Third quarter 2016 revenues were impacted by downward revisions to prior revenue accruals totaling $2290,~~816~~287 as discussed above, and totaled $~~824~~90,~~350~~755 prior to the accrual adjustments. Production taxes, ~~respectively~~which totaled $9,620 ~~primarily~~for ~~due~~the third quarter of 2016 prior to ~~declines~~adjustment, inwere ~~the~~adjusted ~~un-weighted~~downward ~~arithmetic~~by ~~average~~$23,368 to a negative amount of $13,748 for the ~~first-day-~~third quarter of~~-the-month~~ ~~commodity~~2016. ~~price~~Sales ~~over~~volumes and sales revenues are continuing to decline as a result of the ~~preceding~~divestiture 12of ~~month~~Partnership ~~periods~~properties ~~ended~~during ~~June~~2016. As of September 30, 2016, gross revenues from Partnership oil and ~~2015.~~gas ~~Property~~sales, ~~impairment~~at ~~expense~~current inpricing, ~~2016~~are isapproximately ~~greatly~~$30,000 ~~reduced~~per ~~from~~month, ~~2015~~and ~~levels~~sales volumes will continue to decline during the fourth quarter. At September 30, as2016, 44% of the Partnership’s ~~recorded~~reserves ~~impairment~~are ~~expense~~oil inreserves ~~excess~~and 56% of ~~$5.4~~the ~~million~~Partnership’s ~~during~~reserves ~~2015,~~are ~~resulting~~natural ingas reserves on a ~~proved~~BOE ~~property~~basis, ~~valuation~~so the average price of ~~only~~both ~~$760,460~~commodities assignificantly ofimpacts ~~December 31,~~Partnership ~~2015~~results.

~~Estimates~~While ofcrude ~~reserves~~oil ~~and~~prices ~~future~~have ~~net~~remained ~~revenues~~relatively ~~from~~stable ~~those~~since ~~reserves~~June 2016, Reef believes they are ~~calculated~~likely ~~based~~to ~~upon~~remain ~~the~~volatile, ~~un-weighted~~and ~~arithmetic~~commodity ~~average~~prices ofwill ~~the~~have ~~first-day-of-the-month~~a ~~commodity~~significant ~~prices~~impact ~~over~~on the ~~preceding~~Partnership’s ~~12-month~~future ~~period.~~results Atof ~~June 30,~~operations. ~~2015,~~The ~~estimated~~Partnership ~~reserves~~has ~~were~~not ~~calculated~~and ~~using~~is ~~average~~currently ~~prices~~not ofengaged ~~$71.73~~in ~~per~~commodity ~~Bbl~~futures ~~for~~trading, ~~crude~~hedging ~~oil~~activities, ~~and~~or ~~$3.32~~derivative ~~per~~financial ~~Mcf~~instrument oftransactions ~~natural~~for ~~gas.~~trading Ator ~~June 30,~~other ~~2016,~~speculative ~~estimated~~purposes. ~~reserves~~The ~~were~~Partnership ~~calculated~~sells ~~using~~substantially ~~average~~all ~~prices~~ of ~~$42.91~~its ~~per~~production ~~Bbl~~from ~~for~~successful ~~crude~~ oil and ~~$2.24~~gas ~~per~~wells ~~Mcf~~on ofa ~~natural~~month-to-month ~~gas~~basis at current spot market prices. ~~While~~Accordingly, the Partnership ~~has~~is ~~seen~~at ~~improving~~risk for the volatility in commodity prices ~~during~~inherent ~~June and~~in ~~July 2016,~~the itoil isand ~~likely~~natural ~~that~~gas industry, and the ~~average~~level of commodity prices ~~during~~has ~~the~~a ~~third~~significant ~~quarter~~impact ofon ~~2016~~the ~~will~~Partnership’s beresults ~~lower~~of ~~than the~~operations.

Lease operating expenses decreased from $175,741 for the three month period ended September 30, 2015 to $66,650 for the three month period ended September 30, 2016, primarily as a result of the Partnership’s divestiture of properties. Lease operating expenses on the Thums Long Beach Unit and the Slaughter Dean acquisition properties, which were sold in 2015, totaled $47,223 of the $175,741 in lease operating expense incurred during the third quarter of 2015. Currently oil and gas sales revenues are no longer sufficient to satisfy lease operating and general

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~~average~~and ~~commodity~~administrative ~~prices~~costs, ~~during~~and ~~the~~we ~~third~~expect ~~quarter~~this oftrend ~~2015.~~to ~~Therefore,~~continue ~~the~~until ~~Partnership~~all ~~may~~properties ~~incur~~have ~~additional~~been ~~impairment~~divested ~~charges~~and ~~in during~~ the ~~third~~Partnership ~~quarter of 2016~~terminated.

~~Partnership~~General ~~revenues~~and ~~totaled~~administrative costs decreased from $~~100~~140,~~279~~174 for the three month period ended ~~June~~September 30, ~~2016~~2015 ~~compared~~ to $~~568~~68,~~829~~084 for the three month period ended ~~June~~September 30, ~~2015,~~2016. aThe ~~decrease~~allocation of ~~82.4%~~RELP’s ~~due~~overhead ~~primarily~~ to the ~~sale~~Partnership ofis ~~oil~~a ~~and~~significant ~~gas~~portion ~~properties~~of ~~during~~general ~~2015~~ and ~~2016,~~administrative ~~as well as continued depressed oil and natural gas sales prices~~expenses. ~~Oil~~The ~~and~~allocation ~~gas~~of ~~sales~~RELP’s ~~volumes~~overhead ~~decreased~~to ~~during~~partnerships ~~the~~is ~~three~~based ~~month~~upon ~~period~~several ~~ended June 30~~factors, ~~2016~~including ~~compared to~~ the ~~three~~level ~~month~~of ~~period~~drilling ~~ended~~activity, ~~June 30~~revenues, ~~2015~~and bycapital ~~approximately~~and ~~71.8%~~operating onexpenditures aof ~~BOE~~each ~~basis,~~partnership ~~primarily~~compared asto ~~a result of~~ the ~~2015~~total ~~and~~levels ~~2016~~of ~~property~~all ~~sales~~partnerships. ~~Prices~~As ~~also~~properties ~~had~~are asold ~~significant~~and ~~impact on sales revenues, with~~ the ~~average~~Partnership’s ~~sales~~operations ~~price~~wind ~~for crude oil decreasing by 20.3%~~down, toits anoverhead ~~average~~allocation ~~price~~has ofdecreased ~~$38~~accordingly.37 ~~per~~The ~~Bbl~~administrative ~~for~~overhead ~~the~~charged ~~three month period ended June 30, 2016 compared~~ to anthe ~~average~~Partnership ~~price~~decreased offrom $~~48.16~~82,796 ~~per Bbl~~ for the three month period ended ~~June~~September 30, 2015. ~~The average sales price for natural gas decreased by 28.1%,~~ to ~~an average price of~~ $~~1.66~~33,079 ~~per Mcf~~ for the three month period ended ~~June~~September 30, 2016 ~~compared to an average price of $2~~.31 ~~per~~In ~~Mcf~~addition, ~~for~~during the three month period ended ~~June~~September 30, 2015~~. At June 30~~, ~~2016, approximately 44.3% of~~ the Partnership’s ~~reserves~~incurred ~~are~~third ~~crude~~party ~~oil~~engineering ~~reserves~~costs ~~and 55.7%~~ of ~~the~~approximately ~~Partnership’s reserves are natural gas reserves on a BOE basis~~$20, ~~so the average price of both commodities significantly impacts Partnership results~~000.

Nine months ended September 30, 2016 compared to the nine months ended September 30, 2015

The Partnership had a net loss of $278,843 for the nine month period ended September 30, 2016, compared to a net loss of $4,406,651 for the nine month period ended September 30, 2015. After adjusting for the gain on sales of oil and gas properties, the Partnership had a net loss of $379,386 for the nine month period ended September 30, 2016, compared to a net loss of $6,079,846 for the nine month period ended September 30, 2015. The primary reasons for the change in operating results are depreciation, depletion and amortization expense and impairment expense.

During the nine month periods ended September 30, 2016 and 2015, the Partnership recognized impairment expense of proved property totaling $140,003 and $5,204,490, respectively, primarily due to declines in the un-weighted arithmetic average of the first-day-of-the-month commodity price over the preceding 12 month periods ended September 30, 2016 and 2015. Property impairment expense in 2016 is greatly reduced from 2015 levels, as the Partnership recorded impairment expense in excess of $5.4 million during 2015, in addition to selling its working interests in the Thums Long Beach Unit and Slaughter Dean acquisition properties, resulting in a proved property valuation of only $760,460 as of December 31, 2015. Given the higher property basis and higher production volumes that existed during 2015, depletion expense for the nine month period ended September 30, 2015 totaled $491,429, compared to $55,859 for the nine month period ended September 30, 2016.

Estimates of reserves and future net revenues from those reserves are calculated based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period. At September 30, 2015, estimated reserves were calculated using average prices of $59.32 per Bbl for crude oil and $3.00 per Mcf of natural gas. At September 30, 2016, estimated reserves were calculated using average prices of $41.97 per Bbl for crude oil and $2.40 per Mcf of natural gas. The Partnership has seen commodity prices remain relatively stable since June 2016. The Partnership did not record any impairment of proved properties during the third quarter of 2016, and we do not expect to record impairment of proved properties during the fourth quarter of 2016.

Partnership revenues totaled $169,501 for the nine month period ended September 30, 2016 compared to $1,336,922 for the nine month period ended September 30, 2015. Sales revenues were impacted by adjustments to revenue accruals totaling $90,287 during the third quarter of 2016, and totaled $259,788 prior to the accrual adjustments. Sales revenues from the Partnership’s two major properties sold during 2015, the Slaughter Dean acquisition properties and the Thums Long Beach Unit, totaled $864,602, or 64.7% of the $1,336,922 in revenues received during the first nine months of 2015. At current oil and gas prices, the gross sales revenues received by the Partnership for its remaining oil and gas properties are approximately $30,000 per month, and this level will decline as additional properties are divested. Production taxes, which totaled $28,130 for the nine month period ended September 30, 2016 prior to adjustment, were impacted by the revenue accrual adjustments and were adjusted downward by $23,368 to a reported amount of $4,762 for the nine month period ended September 30, 2016.

While crude oil prices have risen into the mid-forties during June and July 2016, Reef believes they are likely to remain volatile, and commodity prices will have a significant impact on the Partnership’s future results of operations. The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells substantially all of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and natural gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

Lease operating expenses, after removing the $140,000 credit for ad valorem taxes recorded during the second quarter of 2016, decreased from $436,415 for the three month period ended June 30, 2015 to $86,936 for the three month period ended June 30, 2016. Lease operating expenses on the Thums Unit and the Slaughter Dean properties, which were sold in 2015, totaled $330,757 of the $436,415 in lease operating expense incurred during the second quarter of 2015. Improved sales prices received during the second quarter of 2016, when compared to the first quarter of 2016, allowed the Partnership to post an operating profit of $6,695 during the second quarter of 2016, compared to an operating deficit totaling $54,736 during the first quarter of 2016. During the second quarter of 2015, the Partnership’s operating profit was $98,984. While the Partnership posted an operating profit for the three months ended June 30, 2016, the Partnership was unable to cover both operating and general and administrative costs. As the Partnership continues to sell properties in order to terminate the Partnership prior to December 31, 2016, sales revenues are not expected to cover both operating and general and administrative costs.

General and administrative costs decreased from $148,073 for the three month period ended June 30, 2015 to $51,218 for the three month period ended June 30, 2016. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. As properties are sold and the Partnership’s operations wind down, its overhead allocation has decreased accordingly. The administrative overhead charged to the Partnership decreased from $99,282 for the three month period ended June 30, 2015 to $3,241 for the three month period ended June 30, 2016.

Six months ended June 30, 2016 compared to the six months ended June 30, 2015

The Partnership had a net loss of $153,886 for the six month period ended June 30, 2016, compared to a net loss of $2,479,627 for the six month period ended June 30, 2015. After adjusting for the gain on sales of oil and gas properties, the Partnership had a net loss of $254,429 for the six month period ended June 30, 2016, compared to a net loss of $4,152,727 for the six month period ended June 30, 2015. The primary reasons for the change in operating results are depreciation, depletion and amortization expense and impairment expense.

During the six month periods ended June 30, 2016 and 2015, the Partnership recognized impairment expense of proved property totaling $140,003 and $3,469,416, respectively, primarily due to declines in the un-weighted arithmetic average of the first-day-of-the-month commodity price over the preceding 12 month periods ended June

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~~30,~~Lease ~~2016~~operating ~~and~~expenses ~~2015.~~decreased ~~Property~~from ~~impairment~~$1,122,520 ~~expense~~for inthe ~~2016~~nine ismonth ~~greatly~~period ~~reduced~~ended ~~from~~September 30, 2015 ~~levels~~to $125,214 asfor the ~~Partnership~~nine ~~recorded~~month ~~impairment~~period ~~expense~~ended inSeptember 30, ~~excess~~2016, primarily as a result of $5the Partnership’s divestiture of properties.4 ~~million~~Lease ~~during~~operating ~~2015,~~expenses ~~resulting~~on inthe aThums ~~proved~~Long ~~property~~Beach ~~valuation~~Unit ofand ~~only~~the ~~$760,460~~Slaughter asDean ofacquisition ~~December 31~~properties, ~~2015.~~which ~~Given~~were ~~the~~sold ~~higher~~in ~~property~~2015, ~~basis~~totaled ~~that~~$737,371, ~~existed~~or ~~during~~65.7%, ~~2015~~of the $1,122,520 ~~depletion~~in lease operating expense ~~for~~incurred during the ~~six~~nine month period ended ~~June~~September 30, 2015. ~~totaled~~As ~~$376,867,~~a ~~compared~~result of property sales made to ~~$54~~date,~~341~~ ~~for~~and expected continued property sales as the ~~six~~Partnership ~~month~~moves ~~period~~to ~~ended~~wind ~~June 30~~up operations and terminate, ~~2016~~the Partnership’s sales revenues are not sufficient to satisfy both operating and general and administrative costs.

~~Estimates~~General ~~of reserves~~ and ~~future~~administrative ~~net~~costs ~~revenues~~decreased from ~~those~~$454,863 ~~reserves~~for ~~are calculated based upon~~ the ~~un-weighted~~nine ~~arithmetic~~month ~~average~~period ofended ~~the~~September 30, ~~first-day-of-the-month~~2015 ~~commodity~~to ~~prices~~$211,454 ~~over~~for the ~~preceding~~nine ~~12-~~month period. Atended ~~June~~September 30, ~~2015,~~2016. ~~estimated~~The ~~reserves~~allocation ~~were~~of ~~calculated~~RELP’s ~~using~~overhead ~~average~~to ~~prices~~the ofPartnership ~~$71.73~~is ~~per~~a ~~Bbl~~significant ~~for~~portion ~~crude~~of ~~oil~~general and $3administrative expenses.32 ~~per~~The ~~Mcf~~allocation of ~~natural~~RELP’s ~~gas.~~overhead Atto ~~June 30,~~partnerships ~~2016,~~is ~~estimated~~based ~~reserves~~upon ~~were~~several ~~calculated~~factors, ~~using~~including ~~average~~the ~~prices~~level of ~~$42.91~~drilling ~~per~~activity, ~~Bbl~~revenues, ~~for~~and ~~crude~~capital ~~oil~~ and ~~$2.24~~operating ~~per~~expenditures ~~Mcf~~ of ~~natural~~each ~~gas.~~partnership ~~While~~compared to the ~~Partnership~~total ~~has~~levels ~~seen~~of ~~improving~~all ~~commodity~~partnerships. ~~prices~~As ~~during~~properties ~~June~~ are sold and ~~July 2016~~the Partnership’s operations wind down, itits isoverhead ~~likely~~allocation ~~that~~has ~~the~~decreased ~~average~~accordingly. ~~commodity~~The ~~prices~~administrative ~~during~~overhead charged to the ~~third~~Partnership ~~quarter~~decreased offrom ~~2016~~$275,005 ~~will~~for bethe ~~lower~~nine ~~than~~month ~~the~~period ~~average~~ended ~~commodity~~September 30, ~~prices~~2015 ~~during~~to $62,326 for the ~~third~~nine ~~quarter~~month ofperiod ~~2015~~ended September 30, 2016. ~~Therefore~~In addition, during the ~~Partnership~~nine ~~may~~month ~~incur~~period ~~additional~~ended ~~impairment~~September 30, ~~charges~~2015, inthe ~~during~~Partnership ~~the~~incurred third ~~quarter~~party engineering costs of ~~2016~~approximately $25,000.

Partnership revenues totaled $169,033 for the six month period ended June 30, 2016 compared to $1,063,942 for the six month period ended June 30, 2015, a decrease of 84.1% due primarily to the sale of oil and gas properties during 2015 and 2016, as well as continued depressed oil and natural gas sales prices. Sales revenues from the Partnership’s two major properties sold during 2015, the Slaughter Dean properties and the Thums Unit, totaled $723,991 of the $1,063,942 in revenues received during the first six months of 2015. Oil and gas sales volumes decreased during the six month period ended June 30, 2016 compared to the six month period ended June 30, 2015 by approximately 68.9% on a BOE basis, primarily as a result of the 2015 and 2016 property sales. Prices also had a significant impact on sales revenues, with the average sales price for crude oil decreasing by 29.0%, to an average price of $32.88 per Bbl for the six month period ended June 30, 2016 compared to an average price of $46.28 per Bbl for the six month period ended June 30, 2015. The average sales price for natural gas decreased by 40.7%, to an average price of $1.47 per Mcf for the six month period ended June 30, 2016 compared to an average price of $2.48 per Mcf for the six month period ended June 30, 2015. At June 30, 2016, approximately 44.3% of the Partnership’s reserves are crude oil reserves and 55.7% of the Partnership’s reserves are natural gas reserves on a BOE basis, so the average price of both commodities significantly impacts Partnership results.

Lease operating expenses, after removing the $140,000 credit for ad valorem taxes recorded during the second quarter of 2016, decreased from $946,779 for the six month period ended June 30, 2015 to $198,564 for the six month period ended June 30, 2016. Lease operating expenses on the Thums Unit and the Slaughter Dean properties, which were sold in 2015, totaled $690,149 of the $947,729 in lease operating expense incurred during the six month period ended June 30, 2015. As a result of property sales made to date, and expected continued property sales as the Partnership moves to wind up operations and terminate during 2016, the Partnership’s sales revenues are currently unable to cover both operating and general and administrative costs. While sales prices have improved during June and July 2016 we do not expect this situation to change.

General and administrative costs decreased from $314,689 for the six month period ended June 30, 2015 to $143,370 for the six month period ended June 30, 2016. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. As properties are sold and the Partnership’s operations wind down, its overhead allocation has decreased accordingly. The administrative overhead charged to the Partnership decreased from $192,209 for the six month period ended June 30, 2015 to $29,247 for the six month period ended June 30, 2016.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership is a “smaller reporting company” as defined by Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as such, is not required to provide the information required under this Item.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Quarterly Report. Based on that evaluation, the principal executive officer and principal financial officer have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding financial disclosure.

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended ~~June~~September 30, 2016 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

None.

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Item 1A. Risk Factors

The Partnership is a “smaller reporting company” as defined by Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and, as such, is not required to provide the information required under this item.

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

None.

Item 3. Default Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1		Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**

32.2		Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**

101.INS		XBRL Instance Document *

101.SCH		XBRL Taxonomy Extension Schema Document *

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document *

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document *

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document *

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document *

*Filed herewith

**Furnished herewith

1514

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SIGNATURES

Pursuant to the requirements 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.

REEF OIL & GAS INCOME AND DEVELOPMENT FUND III, L.P.

	REEF OIL & GAS INCOME AND DEVELOPMENT FUND III, L.P.

	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner

	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner


Dated: November 23, 2016	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)


Dated: November 23, 2016	By:	/s/ Daniel C. Sibley
		Daniel C. Sibley
		Chief Financial Officer and General Counsel of Reef Oil & Gas Partners, L.P.
		(Principal Financial and Accounting Officer)

	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner
	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner
Dated: August 12, 2016	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)
Dated: August 12, 2016	By:	/s/ Daniel C. Sibley
		Daniel C. Sibley
		Chief Financial Officer and General Counsel of
		Reef Oil & Gas Partners, L.P.
		(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibits

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1		Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**

32.2		Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**

101.INS		XBRL Instance Document *

101.SCH		XBRL Taxonomy Extension Schema Document *

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document *

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document *

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document *

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document *

*Filed herewith

**Furnished herewith

1716

Filing Compare · Reef Oil & Gas Income & Development Fund III LP