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 ~~September~~March 3031, ~~2015~~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 oNo ¨

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 ~~November~~May 1213, ~~2015~~2016, the registrant had ~~490~~885.~~7327~~6999 units of ~~general~~limited partner interest outstanding, 9and 8.~~2197~~9697 units of general partner interest and 1.~~0500~~3000 ~~units~~ of limited partner interest held by the managing general partner~~, and 395~~.~~9672 units of limited partner interest outstanding.~~

Table of Contents

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

Form 10-Q Index

PART I — FINANCIAL INFORMATION		1
ITEM 1.	Financial Statements	1
	Condensed Balance Sheets	1
	Condensed Statements of Operations	2
	Condensed Statements of Cash Flows	3
	Notes to Condensed Financial Statements	4
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	12
ITEM 4.	Controls and Procedures	12
PART II — OTHER INFORMATION		13
ITEM 1.	Legal Proceedings	13
ITEM 1A.	Risk Factors	13
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	13
ITEM 3.	Default Upon Senior Securities	13
ITEM 4.	Mine Safety Disclosures	13
ITEM 5.	Other Information	13
ITEM 6.	Exhibits	13
Signatures		14

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

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

Condensed Balance Sheets

	September 30, 2015			December 31, 2014
	March 31, 2016			December 31, 2015
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	~~575~~548,~~314~~773		$	~~368~~1,~~620~~515,010
Accounts receivable from affiliates	~~355~~46,~~967~~650			~~183~~135,~~078~~851
Total current assets	931,281			551,698
Prepaid expenses	5,826			—
Total current assets	601,249			1,650,861
Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $61,785,821 and $66,651,471	4,495,150			11,116,897
Proved properties, net of accumulated depletion of $13,952,864 and $14,737,574	573,840			760,460
Net oil and gas properties	4573,~~495,150~~840			11760,~~116,897~~460
Total assets	$	51,~~426~~175,~~431~~089		$	112,~~668~~411,~~595~~321
Liabilities and partnership equity
Current liabilities:
Accounts payable	$	1023,~~385~~759		$	109,~~479~~996
Accrued liabilities	—			6,247
Total current liabilities	23,759			9,996
Total current liabilities	10,385			16,726
Long term liabilities
Asset retirement obligation	~~716~~520,~~904~~070			2591,~~528,422~~945
Total long term liabilities	~~716~~520,~~904~~070			2591,~~528,422~~945
Commitments and contingencies (Note 6)
Partnership equity
General partners	~~2,738,692~~—			51,~~230~~302,~~521~~555
Limited partners	1707,~~630,340~~659			3468,~~645,712~~462
Managing general partner	~~330~~(76,~~110~~399		)	~~247~~38,~~214~~363
Total partnership equity	4631,~~699,142~~260			91,~~123~~809,~~447~~380
Total liabilities and partnership equity	$	51,~~426~~175,~~431~~089		$	112,~~668~~411,~~595~~321

See accompanying notes to condensed financial statements (unaudited).

Table of Contents

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

Condensed Statements of Operations

(Unaudited)

	For the three months ended September 30,						For the nine months ended September 30,
	For the three months ended March 31,
	2015			2014			2015			2014
	2016			2015
Oil, gas and NGL sales	$	~~272~~68,~~980~~754		$	1495,~~182,939~~113		$	~~1,336,922~~		$	~~3,491,179~~
Costs and expenses:
Lease operating expenses	~~175~~111,~~741~~628			~~653~~510,~~340~~364			~~1,122,520~~			~~1,793,072~~
Production taxes	2811,~~903~~862			6729,~~755~~533			~~91,866~~			~~203,326~~
Depreciation, depletion and amortization	~~114~~31,~~562~~125			~~320~~227,~~907~~543			~~491,429~~			~~943,210~~
Accretion of asset retirement obligation	5,~~643~~280			4240,~~916~~330			~~51,600~~			~~121,499~~
Property impairment	1117,~~735,074~~187			—2,645,066			~~5,204,490~~			—
Gain on sale of oil & gas properties	—(100,543		)	—			~~(1,673,100~~		)	—
General and administrative	~~140~~92,~~174~~152			~~155~~166,~~423~~616			~~454,863~~			~~503,411~~
Total costs and expenses	2268,~~200,097~~691			13,~~240~~619,~~341~~452			~~5,743,668~~			~~3,564,518~~
Loss from operations	(1199,~~927,117~~937		)	(573,~~402~~124,339		)	~~(4,406,746~~		)	~~(73,339~~		)
Other income (expense)
Miscellaneous income	931,817			67—			93			~~706~~
Interest income (expense)	—			(1,854		)	2			(17,200		)
Interest income	—			2
Amortization of deferred financing fees	—			(5,491		)	—			(10,904		)
Total other income	1,817			2
Total other income (expense)	93			(7,278		)	95			(27,398		)
Net loss	$	(198,120	)	$	(3,124,337	)
Net loss	$	(1,927,024	)	$	(64,680	)	$	(4,406,651	)	$	(100,737	)
Net loss per general partner unit	$	—		$	(3,455	)
Net loss per general partner unit	$	(2,140	)	$	(101	)	$	(5,058	)	$	(207	)
Net loss per limited partner unit	$	(216	)	$	(3,455	)
Net loss per limited partner unit	$	(2,140	)	$	(101	)	$	(5,058	)	$	(207	)
Net loss per managing partner unit	$	(776	)	$	(6,290	)
Net income (loss) per managing partner unit	$	(2,929	)	$	2,784		$	9,543		$	9,280

See accompanying notes to condensed financial statements (unaudited).

Table of Contents

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

Condensed Statements of Cash Flows

(Unaudited)

	For the nine months ended September 30,
	For the three months ended March 31,
	2015			2014
	2016			2015
Cash flows from operating activities
Net loss	$	(4198,~~406,651~~120	)	$	(~~100~~3,~~737~~124,337	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Plugging and abandonment costs paid from ARO	(3,355		)	(5,437		)
Adjustments to reconcile net loss to net cash used in operating activities:
Plugging and abandonment costs paid from ARO	(4,784		)	(1,424		)
Adjustments for non-cash transactions:
Depletion, depreciation and amortization	~~491~~31,~~429~~125			~~943~~227,~~210~~543
Accretion of asset retirement obligation	515,~~600~~280			~~121~~40,~~499~~330
Amortization of deferred financing fees	—			10,904
Property impairment	117,187			2,645,066
Gain on sale of oil and gas properties	(~~1,673,~~100,543		)	—
Property impairment	5,204,490			—
Changes in operating assets and liabilities
Accounts receivable from affiliates	889,~~721~~201			~~(219~~183,~~197~~078		)
Accounts payable	—			65
Prepaid expenses	(5,826		)	—
Accrued liabilities	~~(6,247~~—		)	89,~~000~~853
Net cash provided by (used in) operating activities	(333,113		)	758,307
Accounts payable to affiliates	—			19,891
Net cash used in operating activities	(66,480		)	—
Cash flows from investing activities:
Proceeds from sale of oil and gas properties	~~830~~104,~~464~~567			~~134,798~~—
Property development	(~~272~~38,~~909~~087		)	~~(434,486~~—		)
Net cash provided by (used in) investing activities	557,555			(299,688		)
Net cash provided by investing activities	66,480			—
Cash flows from financing activities:
Payment of note payable	—			(600,000		)
Distributions to partners	(966,237		)	(280		)
Payment of debt issuance costs	—			(1,316		)
Net cash used in financing activities	(966,237		)	(280		)
Distributions to partners	(17,748		)	(168,800		)
Net decrease in cash and cash equivalents	(966,237		)	(280		)
Net cash used in financing activities	(17,748		)	(770,116		)
Cash and cash equivalents, beginning of year	1,515,010			368,320
Net increase (decrease) in cash and cash equivalents	206,694			(311,497		)
Cash and cash equivalents, end of year	$	548,773		$	368,040
Cash and cash equivalents, beginning of year	368,620			651,936
Cash and cash equivalents, end of year	$	575,314		$	340,439
Supplemental cash flow disclosure
Cash paid for interest expense on note payable	$	—		$	17,200
Supplemental disclosure of non-cash investing transactions
Asset retirement obligation sold	$	(1,859,763	)	$	(4,692	)
Property additions included in accounts payable to affiliates	$	—		$	177,692
Property sales included in accounts receivable from affiliates	$	181,610
Asset retirement obligation reduction resulting from sale and disposition of proved properties	$	72,371		—
Supplemental disclosure of non-cash financing transactions
Partner distributions included in accounts payable	$	186		$	2,071
Partner distributions suspensed and included in accounts payable	$	13,763		—

See accompanying notes to condensed financial statements (unaudited).

Table of Contents

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

Notes to Condensed Financial Statements (unaudited)

~~September~~March 3031, ~~2015~~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 ~~nine~~three months of ~~2015~~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, ~~2014~~2015 (the “Annual Report”). The results of operations for the three ~~and nine~~ month ~~periods~~period ended ~~September~~March 3031, ~~2015~~2016 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2015~~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. 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.

Abandonment of Partnership Interests

During January 2016, two investor partners owning 0.50 units of general partner interest and 0.50 units of limited partner interest abandoned their interests in the Partnership. As such, the Partnership reduced the total number of investor partner units outstanding as of January 1, 2016 to reflect these abandonments.

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 ~~of oil~~ (“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 second quarter of 2015, the Partnership recognized a gain of $1,673,100 in connection with the sale of the Slaughter Field in Cochran Country, Texas (the “Slaughter Dean Properties”).

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 nine month periods ended September 30, 2015, the Partnership recognized $1,735,074 and $5,204,490 of impairment expense of proved properties, respectively. During the three and nine month periods ended September 30, 2014, the Partnership recognized no impairment of proved properties.

Estimates of Proved Oil and Gas Reserves

The estimates of the Partnership’s proved reserves at September 30, 2015 and December 31, 2014 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 September 30, 2015 was based upon evaluations prepared by the senior reservoir engineer for Reef Exploration, L.P. (“RELP”), an affiliate of the Partnership and

Table of Contents

~~Reef~~accounted ~~Oil~~for ~~and~~as ~~Gas~~adjustments ~~Partners~~to capitalized costs, Lwith no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.P. ~~(“Reef”),~~During the ~~managing~~three ~~general~~month ~~partner~~period ofended March 31, 2016, the Partnership recognized a gain of $100,543 in connection with a sale of oil and gas properties. ~~The~~During ~~Partnership’s~~the ~~proved~~three ~~reserve~~month ~~information~~period atended ~~December~~March 31, ~~2014~~2015, ~~was~~the ~~based~~Partnership ~~upon~~did ~~evaluations~~not ~~prepared~~have byany ~~independent~~sales ~~petroleum~~of ~~engineers~~oil and gas properties.

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 month periods ended March 31, 2016 and 2015, the Partnership recognized $117,187 and $2,645,066 of impairment expense of proved properties, respectively.

Estimates of Proved Oil and Gas Reserves

The estimates of the Partnership’s proved reserves at March 31, 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 March 31, 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~~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.

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 nine month period ended September 30, 2015 and the year ended December 31, 2014.

	Nine months ended September 30, 2015			Year ended December 31, 2014
Beginning asset retirement obligation	$	2,528,422		$	2,463,175
Additions related to new properties	—			2,014
Retirement related to property sales and dispositions	(1,859,763		)	(4,692		)
Retirement related to property abandonment and restoration	(3,355		)	(95,565		)
Accretion expense	51,600			163,490
Ending asset retirement obligation	$	716,904		$	2,528,422

Table of Contents

The following table summarizes the Partnership’s asset retirement obligation for the three month period ended March 31, 2016 and the year ended December 31, 2015.

	Three months ended March 31, 2016			Year ended December 31, 2015
Beginning asset retirement obligation	$	591,945		$	2,528,422
Retirement related to sale and disposition of proved properties	(72,371		)	(1,988,403		)
Retirement related to property abandonment and restoration	(4,784		)	(4,170		)
Accretion expense	5,280			56,096
Ending asset retirement obligation	$	520,070		$	591,945

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable from affiliates, ~~accounts~~prepaid ~~payable,~~expenses and ~~accrued~~accounts ~~liabilities~~payable approximates their carrying value due to their short-term nature.

Comprehensive Income

Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.

Recent Accounting Developments — Revenue Recognition

The ~~Financial~~following ~~Accounting~~recently ~~Standards Board (“FASB”)~~ issued ~~an Accounting Standards Update (“ASU”) in May 2014 which provides~~ accounting ~~guidance~~pronouncement ~~for~~has ~~all~~been ~~revenues~~adopted ~~arising from contracts to provide goods~~ or ~~services~~may toimpact ~~customers. The core principle of~~ the ~~guidance~~Partnership ~~is that an entity should recognize revenue to depict the transfer of promised goods or services to customers~~ in anfuture 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 from the new ASU will supersede prior revenue recognition requirements and most prior industry-specific guidance throughout the FASB’s ASC, 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.:

The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) 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 from the new ASU 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~~Investor ~~partners~~Partners and Reef pays no drilling or completion expenses for this interest. In addition, Reef ~~owns~~has ~~1.05 units of limited partner interest and~~ purchased ~~an additional 0~~1.2530 units of ~~general~~Partnership ~~partner~~ interest from investor partners ~~during the third quarter of 2015~~. ~~Therefore,~~Effective ~~effective October~~September 1, 2015 Reef ~~also~~ receives 011.13% ofand ~~the~~investor ~~distributions~~partners ~~paid~~receive to88.87% ~~investor~~of ~~partners~~total cash distributions. AsDuring ~~such,~~the ~~effective~~three ~~October~~month periods ended March 131, 2016 and 2015, Reef ~~receives~~received ~~11.13%~~$109,088 and ~~investor~~$0, ~~partners~~respectively, ~~receive~~in ~~88.87%~~cash ofdistributions ~~total~~related ~~cash~~to ~~distributions~~its Partnership interest.

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. Prior to the June 2015 sale, RELP served as the operator of the Slaughter Dean Properties and the wells in which the Partnership held an interest thereon, and received drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership. 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 well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point. In addition, total well costs 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 nine month period ended September 30, 2015 and the year ended December 31, 2014, RELP received $11,725 and $21,201, 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 nine month periods ended September 30, 2015, the Partnership paid

Table of Contents

~~Reef~~The ~~and~~Partnership ~~its~~has ~~affiliates~~no ~~$17~~employees. RELP employs a staff including geologists,~~895~~ ~~and~~petroleum ~~$67~~engineers,~~963,~~ ~~respectively~~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 ~~direct~~all non-operated wells. Total well costs include all drilling and ~~paid~~equipment ~~Reef~~costs, including intangible development costs, tangible costs during drilling and ~~its~~completion ~~affiliates~~of ~~$206~~a well, costs of storage and $2other surface facilities,~~579~~ and the costs of gathering pipelines necessary to connect the well to the nearest appropriate delivery point. In addition, ~~respectively~~total well costs include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for ~~out~~a well or any other activity incident to the operations of ~~pocket~~a ~~expenses~~well, excluding ordinary well operating costs after completion. Total well costs do not include costs relating to lease acquisitions. During the three ~~and nine~~ month ~~periods~~period ended ~~September~~March 3031, ~~2014,~~2016 and the ~~Partnership~~year ~~paid~~ended ~~Reef~~December 31, ~~and~~2015, ~~its~~RELP ~~affiliates~~received $291,~~096~~274 and $7913,~~568~~564, respectively, ~~for~~in ~~direct~~drilling ~~costs~~compensation. Drilling ~~and~~compensation ~~paid~~payments ~~Reef~~are ~~and~~included ~~its~~in ~~affiliates~~oil ~~$289~~ and ~~$887,~~gas ~~respectively,~~properties ~~for~~in ~~out~~the offinancial ~~pocket expenses~~statements.

~~RELP~~Additionally, ~~allocates~~Reef ~~its general~~ and ~~administrative~~its ~~expenses~~affiliates asare ~~overhead~~reimbursed tofor ~~all~~direct ofcosts ~~the partnerships to which it provides services,~~ and ~~this~~documented ~~allocation is a significant portion~~ out-of-pocket ~~the Partnership’s general and administrative~~ expenses. ~~The~~incurred ~~allocation~~on ofbehalf ~~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~~Partnership. During the three ~~and nine~~ month periods ended ~~September~~March 3031, 2016 and 2015, the ~~administrative overhead charged by RELP to the~~ Partnership ~~totaled~~paid ~~$82,796~~Reef and ~~$275,005,~~its ~~respectively.~~affiliates ~~During the three and nine month periods ended September 30, 2014, the administrative overhead charged by RELP to the Partnership totaled~~ $~~117~~32,~~568~~949 and $~~346~~24,~~385~~019, respectively., ~~The~~for ~~administrative~~direct ~~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~~paid ~~expenses,~~Reef ~~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~~$2,065 ~~whether~~and ~~generated by RELP~~$967, ~~its affiliates or third parties~~respectively, ~~but~~for ~~excluding~~out ~~direct~~of ~~and~~pocket ~~operating costs~~expenses.

RELP ~~processes~~allocates ~~joint~~its ~~interest~~general ~~billings~~ and ~~revenue~~administrative ~~payments~~expenses onas ~~behalf~~overhead to all of the ~~Partnership.~~partnerships Atto ~~September 30,~~which ~~2015~~it ~~and~~provides ~~December 31~~services, ~~2014,~~and ~~RELP~~this ~~owed~~allocation is a significant portion of the Partnership’s ~~$174,357~~general and ~~$183,078,~~administrative ~~respectively,~~expenses. ~~for~~The ~~net~~allocation ~~revenues~~of ~~processed~~RELP’s inoverhead ~~excess~~to ofthe ~~joint~~partnerships ~~interest~~to which it provides services is based upon several factors, including the level of drilling ~~compensation~~activity, ~~direct~~revenues, ~~costs~~and capital and ~~out-~~operating expenditures of~~-pocket~~ ~~expenses.~~each ~~The~~partnership ~~cash~~compared ~~associated~~to ~~with~~the ~~net~~total ~~revenues~~levels ~~processed~~of byall ~~RELP~~partnerships. isDuring ~~normally~~the ~~received~~three bymonth ~~RELP~~periods ~~from~~ended ~~oil~~March 31, 2016 and ~~gas~~2015, ~~purchasers~~the ~~30-60~~administrative ~~days~~overhead ~~after~~charged ~~the~~by ~~end~~RELP ofto the ~~month~~Partnership tototaled ~~which~~$26,006 ~~the~~and ~~revenues~~$92,927, ~~pertain~~respectively. InThe ~~addition,~~administrative asoverhead ofcharged ~~September 30,~~by ~~2015~~ RELP ~~owed~~is ~~the~~included ~~Partnership~~in ~~approximately~~general ~~$181,610~~and ~~associated~~administrative ~~with~~expense in the ~~sale~~accompanying condensed statements of ~~the~~operations. ~~Partnership~~RELP’s ~~Slaughter~~general ~~Dean~~and ~~Properties.~~administrative ~~This~~costs ~~amount~~include ~~represents~~all ~~post-closing~~customary ~~purchase~~and ~~price~~routine ~~adjustments~~expenses, ~~which~~accounting, ~~have~~office ~~not~~rent, ~~yet~~telephone, ~~been~~secretarial, ~~received~~salaries ~~from~~and other incidental expenses incurred by RELP or its affiliates that are necessary to the ~~purchaser~~conduct of the ~~Slaughter~~Partnership’s ~~Dean~~business, ~~Properties.~~whether ~~The~~generated ~~Partnership~~by ~~settles~~RELP, its ~~balances~~affiliates ~~with~~or ~~Reef~~third ~~and~~parties, ~~RELP~~but onexcluding atdirect ~~least~~and aoperating ~~quarterly basis~~costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At March 31, 2016, and December 31, 2015, RELP owed the Partnership $46,650 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 a quarterly basis.

4. Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three ~~and nine~~ month periods ended ~~September~~March 3031, 2016 and 2015 is detailed below:

For the three months ended ~~September~~March 3031, ~~2015~~2016

Type of Unit	Number of Units	Net (loss)			Net (loss) per unit
Managing general partner	98.~~2197~~9697	$	(276,~~009~~962	)	$	(~~2,929~~776	)
General partner	490.7327	(1,050,295		)	$	(2,140	)
Limited partner	886.9999	(191,158		)	$	(216	)
Limited partner	397.0172	(849,720		)	$	(2,140	)
Total	895.9696	$	(198,120	)
Total	896.9696	$	(1,927,024	)

For the nine months ended September 30, 2015

Type of Unit	Number of Units	Net income (loss)			Net income (loss) per unit
Managing general partner	9.2197	$	84,860		$	9,543
General partner	490.7327	(2,483,155		)	$	(5,058	)
Limited partner	397.0172	(2,008,356		)	$	(5,058	)
Total	896.9696	$	(4,406,651	)

Table of Contents

For the three months ended March 31, 2015

Type of Unit	Number of Units	Net (loss)			Net (loss) per unit
Managing general partner	8.9697	$	(56,416	)	$	(6,290	)
General partner	490.9827	(1,696,280		)	$	(3,455	)
Limited partner	397.0172	(1,371,641		)	$	(3,455	)
Total	896.9696	$	(3,124,337	)

5. Subsequent Event

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~~, including, without limitation, the risk factors listed in the section captioned “RISK FACTORS” contained in the Partnership’s Annual Report~~. 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 ~~undertake no obligation and~~ 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.

Overview

Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership. The primary objectives of the Partnership are 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 no later than 2015, in order to maximize return to the partners of the Partnership. Reef Oil & Gas Partners, L.P. (“Reef”) is the managing general partner of the Partnership.

On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but will not engage in exploratory drilling for unproved reserves, should acreage

Table of Contents

~~purchased~~Going by the Partnership be deemed to contain unproved drilling locations. Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships or entities formed and/or managed by Reef. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with its 2010 purchase of certain working interests in oil and gas properties (the “Azalea properties”) represented by leases, covering more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and agrees to participate or declines to participate in such additional drilling based upon Reef’s evaluations of such proposals. In order to protect or preserve the value of the Partnership’s holdings, the Partnership may participate in such developmental drilling, in which case funds to drill may be taken from current net cash flows available for distributions to investors. The Partnership does not expect to purchase interests in any additional properties. During the first nine months of 2015, the Partnership did not receive any drilling proposals. Drilling costs and drilling compensation recorded by the Partnership during the first nine months of 2015 were related to drilling proposals that were approved during 2014.Concern

~~The~~Management ~~Partnership~~is ~~made~~currently ~~three~~pursuing ~~major property acquisitions, referred to as~~ the ~~Slaughter~~sale ~~Dean~~of ~~acquisition,~~all ~~Azalea~~Partnership ~~acquisition,~~assets ~~and Lett acquisition,~~ with the ~~capital~~intent ~~raised~~to bywind ~~the~~up ~~Partnership,~~ and ~~acquired~~terminate ~~interests in over 1,500 wells located in twelve states. The management of~~ the ~~operations and other business of the~~ Partnership isduring ~~the responsibility of Reef~~2016. ~~Reef~~ ~~Exploration,~~As ~~L.P.~~a ~~(“RELP”)~~result, ~~an affiliate of Reef and~~ the Partnership, ~~served~~is asnot ~~the~~expected ~~operator~~to ofcontinue ~~the~~as ~~Slaughter~~a ~~Dean~~going ~~Properties~~concern. ~~located~~In inaccordance ~~Cochran~~with ~~County,~~generally ~~Texas~~accepted ~~prior~~accounting toprinciples ~~their~~for ~~sale~~a inlimited ~~June 2015.~~life ~~All~~entity, ~~other properties that have been acquired by~~ the Partnership ~~are~~has ~~operated by third party operators~~ not ~~affiliated~~applied ~~with~~ the ~~Partnership,~~liquidation ~~Reef~~basis ~~or any~~ of ~~Reef’s~~accounting ~~affiliates.~~to ~~The~~these ~~Partnership~~financial ~~operates in only one industry segment, which is the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGL’s”) in the United States~~statements.

AsOverview a/ result of the decline in crude oil prices that began during the third quarter of 2014 and has continued during calendar year 2015, the Partnership’s plans to sell significant properties acquired in the Azalea and Lett acquisitions were delayed by Reef. The Partnership sold its interest in the Slaughter Dean Properties during the second quarter of 2015. The Partnership sold the Slaughter Dean Properties in 2015 in spite of current conditions because the waterflood development project implemented by Reef was not successful, and the field was an older field with higher operating costs and significant workover costs. Operating costs had exceeded oil and gas sales revenues during 2015 at the time of sale.Outlook

~~The~~Reef ~~continuing~~Oil & ~~depressed~~Gas ~~level~~Income ~~of oil~~ and ~~gas~~Development ~~prices~~Fund ~~during~~III, ~~2015~~L.P. ~~has~~is ~~had~~ a ~~significant~~Texas ~~adverse~~limited ~~effect~~partnership formed on ~~the~~November 27, ~~Partnership’s~~2007. ~~results~~The ofPartnership ~~operations~~was ~~and~~formed ~~financial~~to ~~position. Lease~~purchase ~~operating~~working ~~costs,~~interests ~~production~~in ~~taxes,~~oil and ~~general~~gas ~~and~~properties ~~administrative~~with ~~costs~~the ~~exceeded~~purposes ~~sales~~of ~~revenues~~(i) growing ~~during~~ the ~~third~~value ~~quarter~~ of ~~2015.~~properties ~~Since~~through ~~Reef~~the isdevelopment ~~unable~~of toproved ~~project~~undeveloped ~~when~~reserves, or(ii) generating ifrevenue ~~prices~~from ~~may~~the ~~recover~~production toof acrude ~~level~~oil ~~that~~and ~~would~~natural ~~reverse quarterly declines in working capital~~gas, we(iii) distributing ~~have~~cash ~~decided~~ to ~~resume~~the ~~efforts~~partners toof ~~market~~ the Partnership’s, ~~significant Azalea~~ and ~~Lett~~(iv) selling ~~acquisition~~the ~~assets.~~properties, ~~Reef~~subject ~~has~~to ~~already~~certain ~~been~~market ~~marketing~~conditions, ~~smaller~~no ~~property~~earlier ~~interests~~than ~~acquired~~2010, inbut ~~the~~expected ~~Azalea~~no ~~and~~later ~~Lett~~than ~~acquisitions~~2015, ~~that~~in ~~cannot~~order beto ~~operated~~maximize atreturn ato ~~profit in~~ the ~~current~~partners ~~oil~~of ~~and~~the ~~gas~~Partnership. ~~price~~The ~~environment,~~term ~~primarily~~of inthe anPartnership ~~effort~~commenced toon ~~eliminate~~the ~~future~~formation ~~plugging~~date and ~~abandonment~~continues ~~costs. One~~until ~~such~~December 31, ~~sale~~2016, ~~was~~unless ~~completed~~terminated insooner. Reef is the ~~third~~managing ~~quarter~~general ~~and~~partner isof ~~described~~the ~~below~~Partnership.

OnThe ~~June 12, 2015, the~~ Partnership ~~completed~~sought ~~the~~to ~~sale~~purchase ofworking ~~its~~interests ~~working~~in ~~interest~~oil and ~~related~~gas ~~assets~~properties ~~acquired~~with inboth ~~the~~proved ~~Slaughter~~producing ~~Dean~~reserves ~~Properties~~and ~~located~~proved inundeveloped ~~Cochran~~reserves. ~~County,~~Between ~~Texas~~November 27, ~~retroactive~~2007 toand ~~December~~June 130, ~~2014~~2010, tothe ~~Red~~Partnership ~~Sea~~made ~~2012, Inc.~~three ~~for~~major aproperty ~~purchase~~acquisitions ~~price~~with ofthe ~~$700,000,~~capital ~~less~~raised ~~fees~~by ~~paid of $5,765, subject to certain revenue and cost adjustments retroactive to~~ the ~~effective date~~Partnership. ~~The~~On ~~Slaughter~~all ~~Dean~~properties ~~Properties included working interests in (i) the Dean Unit~~purchased, ~~(ii)~~ the ~~Dean~~Partnership ~~“B”~~planned ~~Unit,~~to ~~and~~produce ~~(iii) the~~existing ~~Dean~~proved ~~“K”~~reserves ~~unit,~~ and ~~included~~develop inany ~~excess~~proved ofundeveloped ~~100 producing~~reserves, ~~non-producing,~~but ~~shut-in,~~not ~~water~~to ~~source,~~engage ~~injection,~~in ~~and~~exploratory ~~disposal~~drilling ~~wells~~for unproved reserves. In Drilling ~~accordance~~locations with ~~the~~unproved ~~full~~reserves, ~~cost~~if ~~method of accounting~~any, ~~the~~could ~~Partnership~~be ~~recorded~~farmed aout ~~gain~~or onsold ~~sale totaling $1,673,100 related~~ to ~~the~~third ~~sale~~parties ofor ~~the~~other ~~Slaughter~~partnerships ~~Dean~~formed ~~Properties~~by Reef.

~~Subsequent~~The toPartnership ~~the~~made ~~sale~~three ofmajor property acquisitions between 2007 and 2010, referred to as the Slaughter Dean ~~Properties~~acquisition, Azalea acquisition, and Lett acquisition, with the ~~Partnership’s~~capital ~~primary~~raised ~~assets~~by ~~consist~~the ofPartnership, ~~working~~and thereby acquired interests in ~~oil~~over 1,500 wells located in twelve states. The management of the operations and ~~gas~~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 ~~acquired~~prior to their sale in 2015. All wells included in the Azalea and Lett acquisitions ~~represented~~are operated by ~~leases,~~third ~~covering~~parties ~~more~~not ~~than~~affiliated ~~400~~with ~~properties~~the Partnership, ~~including~~Reef, ~~more~~or ~~than~~any ~~1,400~~other ~~wells,~~Reef ~~located~~affiliate. The most significant property acquired in ~~Texas,~~the ~~California,~~Azalea ~~New~~and ~~Mexico,~~Lett ~~Louisiana,~~acquisitions ~~Oklahoma,~~was ~~North~~a ~~Dakota,~~working ~~Mississippi,~~interest ~~Alabama,~~in ~~Kansas,~~the ~~Montana,~~Thums ~~Colorado~~Long ~~and~~Beach ~~Arkansas~~Unit located underneath the Long Beach Harbor in Southern California.

~~During~~As a result of the ~~second~~decrease in commodity prices which began during the third quarter of ~~2015~~2014, Reef decided to delay the ~~Partnership~~sale ~~also~~of ~~sold~~Partnership ~~its~~properties ~~working~~until ~~interest~~prices inrecovered, awith ~~well~~the ~~located~~hope inof ~~Woods~~maximizing ~~County,~~return ~~Oklahoma~~to ~~for~~the ~~$84,332~~investor partners. The ~~property~~sole ~~began~~exception ~~drilling~~to ~~operations~~this ~~during~~policy ~~December 2014,~~was ~~with~~the ~~first~~Partnership’s ~~production~~working ~~beginning~~interest ~~February 2015~~in the Slaughter Dean acquisition properties. InThe ~~accordance~~waterflood ~~with~~development project implemented by Reef on the ~~full~~Slaughter ~~cost~~Dean ~~method~~acquisition ofproperties ~~accounting~~had not proven to be successful, ~~the~~and ~~Partnership~~this ~~did~~older ~~not~~field ~~record~~exhibited ~~any~~high ~~gain~~operating orcosts ~~loss~~and ~~related~~also tohigh ~~the~~workover ~~sale~~costs. ofThe Slaughter Dean acquisition properties were sold during the ~~property~~second quarter of 2015.

As commodity prices continued to decline, 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, Reef believes the Partnership must either borrow funds from Reef or sell properties to generate cash to cover the deficits. As Reef is unable to project when or if commodity prices will 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.

During the first quarter of 2016, the Partnership made six oil and gas property sales, totaling approximately 75 wells and representing 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.

Table of Contents

~~During~~As ~~the third quarter~~ of ~~2015~~March 31, 2016, the Partnership ~~sold~~continues ~~its~~to own working ~~interest~~interests in ~~six~~more than 500 wells ~~located~~acquired in ~~Blaine~~the ~~County~~Azalea acquisition, ~~Oklahoma~~located ~~for~~in $3Texas,~~965.~~ InNew ~~accordance~~Mexico, ~~with~~Louisiana, ~~the~~Oklahoma, ~~full~~North ~~cost~~Dakota, ~~method~~Mississippi, ofKansas, ~~accounting~~Montana, ~~the~~and Colorado. The Partnership ~~did~~divested ~~not~~of ~~record~~all ~~any~~of ~~gain~~its orAlabama ~~loss~~and ~~related~~Arkansas toproperties during the ~~sale~~first quarter of ~~the property~~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 ~~September~~March 3031, ~~2015~~2016, the Partnership had expended $81,~~325~~407,~~217~~630 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 ~~increased~~declined during the first ~~nine~~quarter ~~months~~ of ~~2015~~2016, from $~~534~~1,~~972~~640,865 at December 31, ~~2014~~2015 to $~~920~~577,~~896~~490 at ~~September~~March 3031, ~~2015~~2016, primarily as a result of ~~the~~distributing ~~sale~~proceeds ofreceived ~~the~~from ~~Slaughter~~property ~~Dean~~sales ~~properties~~made during 2015 to the ~~second~~investor partners during the first quarter of ~~2015~~2016. The ~~Subsequent~~Partnership has maintained a portion of the cash received from property sales to ~~expending~~cover any deficits during the ~~initial~~divestiture ~~available~~of ~~Partnership~~all ~~capital~~remaining ~~contributions~~properties onand ~~property~~the ~~acquisitions~~winding up and ~~development,~~termination of the Partnership. ~~working~~The ~~capital~~Partnership ~~consists~~generally ~~primarily~~maintains ofnominal working capital, as cash flows ~~from~~are ~~productive~~normally ~~properties~~ utilized to pay monthly cash distributions to investors. Sources of future funding ~~are expected to~~ 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~~. As~~ ain ~~result,~~order ~~the Partnership’s future ability~~ to ~~participate~~achieve inits ~~the~~objective ~~further development~~ of ~~properties~~selling ~~in which the~~ Partnership ~~holds~~properties anon ~~interest~~terms ~~may~~that beprovide ~~restricted,~~a ~~unless~~favorable ~~the~~return ~~Partnership chooses~~ to ~~utilize cash flows from operations available for distributions to~~ investors.

The Partnership has not and does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes. As such, the Partnership’s revenues, cash flows, and reserve values are substantially dependent upon the prevailing prices of crude oil and natural gas. The decline in crude oil prices that began during the third quarter of 2014 has had a significant adverse effect on the Partnership’s results of operations and financial position.

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.

The following table provides information about sales volumes and ~~crude~~sales ~~oil and natural gas~~ prices received for the periods indicated ~~on a BOE basis~~.

	Three months ended March 31, 2016		Three months ended March 31, 2015
Sales volumes:
Oil and NGL’s (Bbls)	1,790		10,107
Natural gas (Mcf)	16,117		17,897

Sales revenues:
Oil and NGL’s (Bbls)	$	47,134	$	447,353
Natural gas (Mcf)	$	21,620	$	47,760

Average sales price received:
Oil and NGL’s (Bbls)	$	26.33	$	44.26
Natural gas (Mcf)	$	1.34	$	2.67

Table of Contents

	For the three months									For the nine months
	ended September 30, 2015									ended September 30, 2015
	Slaughter Dean properties			Azalea properties		Lett properties		Total		Slaughter Dean properties		Azalea properties		Lett properties		Total
Sales volumes:
Oil (Bbls)	(515		)	2,387		3,581		5,453		7,195		8,087		11,163		26,445
Natural gas (Mcf)	—			17,101		1,330		18,431		622		50,981		4,051		55,654
Oil and NGL sales	$	(27,000	)	$	97,210	$	164,762	234,972		$	302,267	$	351,307	$	552,998	$	1,206,572
Gas sales	—			35,159		2,849		38,008		773		121,013		8,564		130,350
Production taxes	(1,890		)	19,060		11,733		28,903		8,084		44,473		39,309		91,866
Lease operating expenses	(33,633		)	128,518		80,856		175,741		455,870		385,150		281,500		1,122,520
Average sales prices received:
Oil (Bbls)	$	52.43		$	40.72	$	46.01	$	43.09	$	42.01	$	43.44	$	49.54	$	45.63
Natural gas (Mcf)	$	—		$	2.06	$	2.14	$	2.06	$	1.24	$	2.37	$	2.11	$	2.34

Sales volumes declined as a result of the property sales made during 2015, but even more significant was the decline in prices received during the periods. The first quarter of 2016 saw oil prices drop below $30.00 per Bbl, and average gas price received drop below $2.00 per Mcf. Prices received dropped to their lowest level since the decline in commodity prices began during the third quarter of 2014. Many operators have not shut-in their production, and these extreme prices led to many properties operating at a loss during the first quarter of 2015. The month of April has seen a recovery in oil prices to a current level above $40 per Bbl. Should this price hold or continue to escalate, second quarter results could improve significantly.

	For the three months								For the nine months
	ended September 30, 2014								ended September 30, 2014
	Slaughter Dean properties		Azalea properties		Lett properties		Total		Slaughter Dean properties		Azalea properties		Lett properties		Total
Sales volumes:
Oil (Bbls)	4,825		4,074		3,764		12,663		14,252		10,664		11,799		36,715
Natural gas (Mcf)	633		20,617		709		21,959		2,149		65,434		3,412		70,995
Oil and NGL sales	$	385,470	$	351,781	$	360,321	$	1,097,572	$	1,173,392	$	822,280	$	1,192,282	$	3,187,954
Gas sales	1,011		81,842		2,514		85,367		4,064		285,413		13,748		303,225
Production taxes	10,560		31,796		25,399		67,755		30,483		90,820		82,023		203,326
Lease operating expenses	431,855		139,044		82,441		653,340		1,046,163		403,722		343,187		1,793,072
Average sales prices received:
Oil (Bbls)	$	79.89	$	86.35	$	95.73	$	86.68	$	82.33	$	77.11	$	101.05	$	86.83
Natural gas (Mcf)	$	1.60	$	3.97	$	3.55	$	3.89	$	1.89	$	4.36	$	4.03	$	4.27

General and administrative costs have also declined significantly, primarily as a result of the overhead allocation made by RELP to the Partnership. As a result of property sales, the activity of this Partnership accounts for a smaller percentage of the activity of all Partnerships managed by RELP.

The ~~sharp~~estimated ~~decline~~net inproved ~~average prices received for both~~ crude oil and natural gas ~~during~~reserves ~~the~~at ~~first nine months of 2015 has had a significant adverse impact on the Partnership’s results of operations. The Partnership’s Slaughter Dean Properties~~March 31, ~~which~~2016 ~~were an older, higher cost waterflood unit, had lease operating costs in excess of oil~~ and ~~gas sales revenues prior to their sale during June~~ 2015. ~~The~~are ~~sale~~summarized ~~of the Slaughter Dean Properties is expected to improve the Partnership’s overall results of operations during the remainder of 2015~~below. ~~Nonetheless,~~Reserve asestimates ~~prices~~are ~~continue~~calculated tousing ~~remain~~pricing ~~significantly~~based ~~lower~~upon ~~than they were during 2014,~~ the ~~Partnership expects to incur additional impairment of oil and gas assets during the fourth quarter of 2015. We expect the~~ un-weighted arithmetic average of the first -day-of-the-month commodity prices over the preceding 12 -month period toand ~~decline~~end ~~again~~of atperiod ~~December~~costs. At March 31, ~~2015~~2016, asthe ~~higher~~un-weighted ~~fourth~~arithmetic ~~quarter~~average ~~2014 commodity~~ prices ~~are~~were ~~replaced~~$46.16 inper ~~the~~Bbl ~~average~~of bycrude ~~lower~~oil ~~fourth~~and ~~quarter~~$2.41 ~~2015~~per ~~commodity~~thousand ~~prices.~~cubic ~~The~~feet ~~amount~~(“Mcf”) of ~~such~~natural ~~additional~~gas, ~~impairment~~compared isto ~~contingent~~$82.72 ~~upon~~per ~~the~~Bbl ~~price~~ of crude oil, ~~natural gas,~~ and ~~natural~~$3.88 ~~gas~~per ~~liquids~~Mcf ~~for the remainder~~ of ~~2015,~~natural ~~increases~~gas orat ~~decreases in our reserve base~~March 31, ~~and changes in estimated operating costs and expenses~~2015.

~~The~~Proved ~~estimated net proved~~ crude oil and natural gas reserves atdiscussed ~~September 30,~~in ~~2015~~this ~~and~~section ~~2014~~include ~~are~~only ~~summarized~~the ~~below.~~amounts ~~Reserve~~which ~~estimates~~the ~~are~~Partnership ~~calculated~~can ~~using~~estimate ~~pricing~~with ~~based~~reasonable ~~upon~~certainty ~~the~~to ~~un-weighted~~be ~~arithmetic~~economically ~~average~~producible ofin ~~the~~future ~~first-day-of-the-month~~years ~~commodity~~from ~~prices~~known ~~over~~oil ~~the~~and ~~preceding~~gas ~~12-month~~reservoirs ~~period~~under ~~and~~existing ~~end~~economic ofconditions, ~~period~~operating ~~costs~~methods, and government regulations. AtProved ~~September 30,~~reserves ~~2015,~~include only quantities that the ~~un-weighted~~Partnership ~~arithmetic~~expects ~~average~~to ~~prices~~recover ~~were~~commercially ~~$59.32~~using ~~per~~current ~~Bbl~~prices, ofcosts, ~~crude~~existing ~~oil~~regulatory practices, and $3technology.00 ~~per~~Therefore, ~~Mcf~~any ofchanges ~~natural~~in ~~gas~~future prices, ~~compared~~costs, toregulations, ~~$104.23~~technology ~~per~~or ~~Bbl~~other ofunforeseen ~~crude~~factors ~~oil~~could ~~and~~materially ~~$4.38~~increase ~~per~~or ~~Mcf~~decrease ofthe ~~natural~~proved ~~gas~~reserve ~~at September 30, 2014~~estimates.

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

Net proved reserves	Oil (Bbl)	Gas (Mcf)
March 31, 2016	44,330	330,580
March 31, 2015	492,930	608,170

Three months ended March 31, 2016 compared to the three months ended March 31, 2015

The Partnership had a net loss of $198,120 for the three month period ended March 31, 2016, compared to a net loss of $3,124,337 for the three month period ended March 31, 2015. The primary reason for the change in operating results is impairment of proved properties during the three months ended March 31, 2015.

During the three month period ended March 31, 2015, the Partnership recognized impairment expense of proved property totaling $2,645,066, primarily due to lower commodity prices. During the last three quarters of 2015, the Partnership incurred impairment expense of proved properties totaling an additional $2,787,300, as commodity prices continued to decline. At December 31, 2015 the Partnership had written its proved property value down to $760,460. During the three month period ended March 31, 2016, the Partnership recognized impairment of proved properties totaling $117,187, and wrote down its proved property value to $573,840.

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 March 31, 2015, estimated reserves were calculated using average prices of $82.72 per Bbl for crude oil and $3.88 per Mcf of natural gas. At March 31, 2016, estimated reserves were calculated using average prices of $46.16 per Bbl for crude oil and $2.41 per Mcf of natural gas. While the Partnership has seen improving commodity prices during April 2016, it is likely that the average commodity prices during the second quarter of 2016 will be lower than the average commodity prices during the second quarter of 2015. Therefore, as a result of second quarter 2016 commodity prices replacing the second quarter 2015 commodity prices for the June 30, 2016 ceiling test calculation, the Partnership expects to incur additional impairment charges in during the second quarter of 2016.

Partnership revenues totaled $68,754 for the three month period ended March 31, 2016 compared to $495,113 for the three month period ended March 31, 2015, a decrease of 86.1% due primarily to the sale of oil and gas properties during 2015 and 2016, as well as continued decreases in oil and natural gas sales prices. Oil and gas sales volumes decreased during the three month period ended March 31, 2016 compared to the three month period ended March

Table of Contents

~~regulatory~~31, ~~practices~~2015 by approximately 65.8% on a BOE basis, primarily as a result of the 2015 and ~~technology~~2016 property sales. ~~Therefore,~~Prices ~~any~~also ~~changes~~had ina ~~future~~significant ~~prices~~impact on sales revenues, ~~costs~~with the average sales price for crude oil decreasing by 40.5%, ~~regulations~~to an average price of $26.33 per Bbl for the three month period ended March 31, ~~technology~~2016 orcompared ~~other~~to ~~unforeseen~~an ~~factors~~average ~~could~~price ~~materially~~of ~~increase~~$44.26 orper ~~decrease~~Bbl for the ~~proved~~three ~~reserve~~month ~~estimates~~period ended March 31, 2015. The ~~September~~average sales price for natural gas decreased by 49.8%, to an average price of $1.34 per Mcf for the three month period ended March 3031, ~~2014~~2016 ~~net~~compared ~~proved~~to ~~reserves~~an ~~included~~average 98price of $2.67 per Mcf for the three month period ended March 31,~~890~~ ~~Bbl~~2015. At ~~and~~March 31, 632016,~~940~~ ~~Mcf~~approximately in44.6% of the Partnership’s reserves ~~attributable~~are tocrude oil reserves and 55.4% of the ~~Slaughter~~Partnership’s ~~Dean~~reserves ~~Properties~~are ~~sold~~natural bygas reserves, so the ~~Partnership~~average inprice ~~June 2015~~of both commodities significantly impacts Partnership results.

~~The~~While ~~lower~~crude ~~commodity~~oil prices ~~experienced~~have been rising during ~~the~~April 2016, ~~first~~they ~~nine~~are ~~months~~likely ofto ~~2015~~remain ~~will~~volatile, beand ~~included~~commodity inprices ~~future~~will ~~ceiling~~have ~~test~~a ~~limitations~~significant ~~for~~impact on the ~~2015~~Partnership’s ~~year~~future ~~end~~results ~~computation~~of operations. ~~Therefore,~~The ~~the~~ Partnership ~~expects~~has ~~estimated~~not ~~net~~and ~~proved~~is ~~crude~~currently ~~oil~~not ~~and~~engaged ~~natural~~in ~~gas~~commodity ~~reserves~~futures totrading, ~~continue~~hedging ~~to decline~~activities, ~~and~~or ~~that~~derivative ~~the~~financial ~~Partnership~~instrument ~~will~~transactions ~~incur~~for ~~additional~~trading ~~impairment~~or ~~charges~~other inspeculative ~~the~~purposes. ~~fourth~~The ~~quarter~~Partnership sells substantially all of ~~2015.~~its ~~While~~production ~~impairment~~from ~~charges~~successful dooil ~~not~~and ~~impact~~gas ~~cash~~wells ~~flows~~on ~~from~~a ~~operating~~month-to-month ~~activities,~~basis ~~continuing~~at ~~lower~~current spot market prices. Accordingly, the Partnership is at risk for ~~crude~~the volatility in commodity prices inherent in the oil and natural gas ~~have~~industry, aand ~~significant~~the ~~impact~~level onof ~~revenues~~commodity ~~and~~prices ~~operating~~has ~~cash~~a ~~flow~~significant ~~and~~impact on the ~~ability~~Partnership’s toresults ~~sell~~of ~~producing properties~~operations.

Net proved reserves	Oil (Bbl)	Gas (Mcf)
September 30, 2015	380,860	495,710
September 30, 2014	513,420	839,030

Lease operating expenses decreased from $510,364 for the three month period ended March 31, 2015 to $111,628 for the three month period ended March 31, 2016, primarily due to property sales during 2015 and 2016. The first quarter of 2016 produced the lowest average sales prices since the decline in commodity prices began during the third quarter of 2014. Many operators are unable to shut-in wells for fear of damaging the productive reservoir, and, as a result, the Partnership had an operating deficit totaling $54,736 during the first quarter of 2016. During the first quarter of 2015, the Partnership’s operating deficit was the result of high operating costs on the Slaughter Dean acquisition properties, which had oil and gas revenues totaling $154,868, but incurred production tax and lease operating expenses totaling $288,346, producing an operating deficit of $133,478.

~~Three~~General ~~months~~and administrative costs decreased from $166,616 for the three month period ended ~~September~~March 3031, 2015 to $92,152 for the three month period ended March 31, 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. The administrative overhead charged to the Partnership decreased from $92,927 for the three ~~months~~month period ended ~~September~~March 3031, ~~2014~~2015 to $26,006 for the three month period ended March 31, 2016.

The Partnership had a net loss of $1,927,024 for the three month period ended September 30, 2015, compared to a net loss of $64,680 for the three month period ended September 30, 2014. The primary cause of this change in operating results is the impairment of proved properties and decreases in average sales prices for crude oil and natural gas.

During the three month period ended September 30, 2015, the Partnership recognized impairment expense of proved property totaling $1,735,074, primarily due to lower commodity prices which reduced proved recoverable reserves. During the three month period ended September 30, 2014, the Partnership had no impairment of proved property.

Partnership revenues totaled $272,980 for the three month period ended September 30, 2015 compared to $1,182,939 for the three month period ended September 30, 2014. The three month period ended September 30, 2014 included Slaughter Dean Properties revenue totaling $379,143, while the three month period ended September 30, 2015 includes prior quarter accrual reversals of $27,000 from the Slaughter Dean Properties. On a comparative basis (i.e., disregarding revenues from the Slaughter Dean Properties) revenues fell from $803,796 to $299,980, a drop of 62.7%, due primarily to decreases in both oil and natural gas sales prices. The average sales price for crude oil decreased by 50.3%, to an average price of $43.09 per Bbl for the three month period ended September 30, 2015 compared to an average price of $86.68 per Bbl for the three month period ended September 30, 2014. The average sales price for natural gas decreased by 47.0%, to an average price of $2.06 per Mcf for the three month period ended September 30, 2015 compared to an average price of $3.89 per Mcf for the three month period ended September 30, 2014. Over 80% of the Partnership’s reserves are crude oil reserves, so the average price of crude oil has a greater impact on Partnership results than the average price of natural gas.

After reaching a June high of $61.05 per Bbl, NYMEX West Texas Intermediate (“NYMEX-WTI”) crude oil prices declined during the third quarter of 2015, dropping below $50 per Bbl in late July and remaining in the $40-$50 range during the remainder of the third quarter, closing just above $45 per Bbl on September 30, 2015. The Partnership believes that crude oil prices are likely to remain volatile. Commodity prices have a direct and 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 productive 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 direct and significant impact on the Partnership’s results of operations.

Lease operating expenses decreased from $653,340 for the three month period ended September 30, 2014 to $175,741 for the three month period ended September 30, 2015. The decrease was almost entirely the result of the sale of the Slaughter Dean Properties in June 2015. Excluding Slaughter Dean Properties lease operating expenses, lease operating expenses dropped from $221,485 for the three month period ended September 30, 3014 to $209,375 for the three month period ended September 30, 2015. Azalea and Thums Long Beach Unit lease operating expenses

Table of Contents

were generally consistent between years. Production taxes also decreased in conjunction with the decline in oil and gas sales revenues. After excluding third quarter 2014 production taxes associated with the Slaughter Dean Properties, production taxes on a comparative basis fell from $57,195 during the three month period ended September 30, 2014 to $30,793 during the three month period ended September 30, 2015.

General and administrative costs decreased from $155,423 for the three month period ended September 30, 2014 to $140,174 for the three month period ended September 30, 2015. 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 for which it performs 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. The administrative overhead charged to the Partnership decreased from $117,568 for the three month period ended September 30, 2014 to $82,796 for the three month period ended September 30, 2015. Third party engineering costs increased approximately $16,800 over the corresponding periods.

Nine months ended September 30, 2015 compared to the nine months ended September 30, 2014

The Partnership had a net loss of $4,406,651 for the nine month period ended September 30, 2015, compared to a net loss of $100,737 for the nine month period ended September 30, 2014. After adjusting for the gain on sale of the Slaughter Dean Properties of $1,673,100, the net loss for the nine month period ended September 30, 2015 was $6,079,751. The primary reasons for the change in operating results are impairment of proved properties and decreases in average sales prices for crude oil and natural gas.

During the nine month period ended September 30, 2015, the Partnership recognized impairment expense of proved property totaling $5,204,490, primarily due to lower commodity prices which reduced proved recoverable reserves. During the nine month period ended September 30, 2014, the Partnership had no impairment of proved property.

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 December 31, 2014, estimated reserves were calculated using average prices of $93.63 per Bbl for crude oil and $4.22 per Mcf of natural gas. At September 30, 2015, as a result of including the first-day-of-the month commodity prices for the first nine months of 2015 in this calculation, estimated reserves were calculated using average prices of $59.32 per Bbl for crude oil and $3.00 per Mcf of natural gas. Because the average price uses the preceding 12 month period, the higher fourth quarter 2014 commodity prices will not be included in the fourth quarter 2015 ceiling test limitation, and the Partnership expects to incur additional impairment charges in the fourth quarter of 2015. While impairment charges do not impact cash flows from operating activities, continuing lower prices for crude oil and natural gas have a significant impact on revenues and operating cash flow.

Partnership revenues totaled $1,336,922 for the nine month period ended September 30, 2015 compared to $3,491,179 for the nine month period ended September 30, 2014. Excluding revenues related to the Slaughter Dean Properties, which were sold in June 2015, revenues for all other Partnership properties totaled $1,036,175 for the nine months ended September 30, 2015, compared to $2,320,012 during the nine months ended September 30, 2014, a decrease of 55.3% due primarily to decreases in both oil and natural gas sales prices. The average sales price for crude oil deceased by 47.4%, to an average of $45.63 per Bbl for the nine month period ended September 30, 2015 compared to an average price of $86.83 for the nine month period ended September 30, 2014. The average sales price for natural gas decreased by 45.2%, to an average price of $2.34 per Mcf for the nine month period ended September 30, 2015 compared to an average price of $4.27 per Mcf for the nine month period ended September 30, 2014. Over 80% of the Partnership’s reserves are crude oil reserves, so the average price of crude oil has a greater impact on Partnership results than the average price of natural gas.

Crude oil prices during calendar year 2015 have been volatile. After reaching a mid-March low of $43.29 per Bbl, NYMEX-WTI crude oil prices rose during most of the second quarter, reaching a high of $61.05 per Bbl in late June. Prices then declined to below $40.00 per Bbl, reaching a low of $38.24 per Bbl in late August. Subsequent to that date, prices rose back into the mid-forties. The Partnership believes that crude oil prices are likely to remain volatile. Commodity prices have a direct and 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

Table of Contents

its production from productive 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 direct and significant impact on the Partnership’s results of operations.

Lease operating expenses decreased from $1,793,072 for the nine month period ended September 30, 2014 to $1,122,520 for the nine month period ended September 30, 2015. After excluding costs related to the Slaughter Dean Properties in order to provide comparative numbers on the Partership’s current properties, lease operating expenses decreased from $746,909 for the nine month period ended September 30, 2014 to $666,652 for the nine month period ended September 30, 2015. During the first nine months of 2014, the Partnership experienced higher operating costs in connection with projects on its non-operated Thums Long Beach Unit (a property interest purchased in the Azalea and Lett acquisitions) due to the completion of several projects. After excluding production taxes related to the Slaughter Dean Properties, production taxes decreased from $172,842 for the nine month period ended September 30, 2014 to $83,782 for the nine month period ended September 30, 2015.

General and administrative costs decreased from $503,411 for the nine month period ended September 30, 2014 to $454,863 for the nine month period ended September 30, 2015. 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 for which it performs 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. The administrative overhead charged to the Partnership decreased from $346,385 for the nine month period ended September 30, 2014 to $275,005 for the nine month period ended September 30, 2015. This decrease was offset by increases in third party engineering costs and landmen charges associated with property sales that have taken place during 2015.

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~~12

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Table of Contents

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended March 31, 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.

Item 1A. Risk Factors

~~There~~The ~~were~~Partnership nois ~~material~~a ~~changes~~“smaller inreporting company” as defined by Rule 12b-2 promulgated under the ~~Risk~~Securities ~~Factors~~Exchange ~~applicable~~Act toof 1934, as amended (the ~~Partnership~~“Exchange Act”), and, as ~~set~~such, ~~forth~~is innot required to provide the ~~Annual~~information ~~Report~~required under this item.

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

None.

Item 3. Default Upon Senior Securities

None.

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

1513

Table of Contents

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 12, 2015		By:	/s/ Michael J. Mauceli
Dated: May 13, 2016		By:	/s/ Michael J. Mauceli
			Michael J. Mauceli
			Manager and Member
			(Principal Executive Officer)
Dated: November 12, 2015		By:	/s/ Daniel C. Sibley
Dated: May 13, 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)

1614

Table of Contents

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

1715

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