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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 30, 2015

or

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

For the Transition Period from          to        

Commission File Number: 000-53795

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

(Exact name of registrant as specified in its charter)

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.

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 13, 2015, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest and 1.0500 units of limited partner interest held by the managing general partner, and 395.9672 units of limited partner interest outstanding.

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

Form 10-Q Index

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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

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)

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)

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 30, 2015

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 months of 2015. 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 (the “Annual Report”). The results of operations for the three and six month periods ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015.

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”). 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 six month periods ended June 30, 2015, the Partnership recognized $824,350 and $3,469,416 of impairment expense of proved properties, respectively. During the three and six month periods ended June 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 June 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 June 30, 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

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Partners, L.P. (“Reef”), the managing general partner of the Partnership. The Partnership’s proved reserve information at December 31, 2014 was based upon evaluations prepared by independent petroleum engineers.

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.

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

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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 payable, and accrued liabilities 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.

3. Transactions with Affiliates

Reef purchased 1% of the Partnership units, 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. Reef also owns 1.05 units of limited partner interest, of which 0.45 units were acquired March 1, 2015. Therefore, effective March 1, 2015 Reef also receives 0.11% of the distributions paid to investor partners. As such, effective March 1, 2015 Reef receives 11.11% and investor partners receive 88.89% of total cash distributions. Prior to March 1, 2015, Reef received 11.06% and investor partners received 88.94% of total cash distributions.

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 six month period ended June 30, 2015 and the year ended December 31, 2014, RELP received $10,215 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 six month periods ended June 30, 2015, the Partnership paid Reef and its affiliates $26,049 and $50,068, respectively, for direct costs and paid Reef and its affiliates $1,406 and $2,373, respectively, for out of pocket expenses. During the three and six month periods ended June 30, 2014, the Partnership paid Reef and its affiliates $34,830 and $50,472, respectively, for direct costs and paid Reef and its affiliates $402 and $598, 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 month periods ended June 30, 2015, the administrative overhead charged by RELP to the Partnership totaled $99,282 and $192,209, respectively. During the three and six month periods ended June 30, 2014, the administrative overhead charged by RELP to the Partnership totaled $105,583 and $228,817, 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

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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 30, 2015 and December 31, 2014, RELP owed the Partnership $347,829 and $183,078, 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. In addition, as of June 30, 2015 RELP owed the Partnership approximately $229,542 associated with the sale of the Partnership’s Slaughter Dean Properties. 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 six month periods ended June 30, 2015 is detailed below:

For the three months ended June 30, 2015

For the six months ended June 30, 2015

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;

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·                                     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 purchased 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 six months of 2015, the Partnership did not receive any drilling proposals. Drilling costs and drilling compensation recorded by the Partnership during the first six months of 2015 were related to drilling proposals that were approved during 2014.

The Partnership made three major property acquisitions, referred to as the Slaughter Dean acquisition, Azalea acquisition, and Lett acquisition, with the capital raised by the Partnership, and acquired interests in over 1,500 wells located in twelve states. The management of the operations and other business of the Partnership is the responsibility of Reef.  Reef Exploration, L.P. (“RELP”), an affiliate of Reef and the Partnership, served as the operator of the Slaughter Dean Properties located in Cochran County, Texas, prior to their sale in June 2015. All other properties that have been acquired by the Partnership are operated by third party operators not affiliated with the Partnership, Reef or any of Reef’s affiliates. The Partnership operates in only one industry segment, which is the exploration, development and

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production of oil, condensate, natural gas and natural gas liquids (“NGL’s”) in the United States.

As a result of the significant decline in crude oil prices that began during the third quarter of 2014 and has continued into the third quarter of 2015, the Partnership has delayed any attempt to sell the properties acquired in the Azalea and Lett acquisitions.

On June 12, 2015, the Partnership completed the sale of its working interest and related assets acquired in the Slaughter Dean Properties located in Cochran County, Texas, retroactive to December 1, 2014, to Red Sea 2012, Inc. for a purchase price of $700,000, less fees paid of $5,765, subject to certain revenue and cost adjustments retroactive to the effective date. The Slaughter Dean Properties include working interests in (i) the Dean Unit, (ii) the Dean “B” Unit, and (iii) the Dean “K” unit, and include in excess of 100 producing, non-producing, shut-in, water source, injection, and disposal wells. The Slaughter Dean Properties accounted for approximately 30.8% of the Partnership’s total sales revenues during the six month period ended June 30, 2015. In accordance with the full cost method of accounting, the Partnership recorded a gain on sale totaling $1,673,100 related to the sale of the Slaughter Dean Properties.

Subsequent to the sale of the Slaughter Dean Properties, the Partnership owns working interests in oil and gas properties acquired in the Azalea and Lett acquisitions 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.

During the second quarter of 2015, the Partnership also sold its working interest in a well located in Woods County, Oklahoma for $84,332. The property began drilling operations during December 2014, with first production beginning February 2015. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to the sale of the property.

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 30, 2015, the Partnership had expended $81,282,186 on property acquisition and development costs. 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 during the first six months of 2015, from $534,972 at December 31, 2014 to $1,050,030 at June 30, 2015, primarily as a result of property sales during the second quarter of 2015. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, Partnership working capital consists primarily of cash flows from productive properties utilized to pay 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 a result, the Partnership’s future ability to participate in the further development of properties in which the Partnership holds an interest may be restricted, unless the 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.

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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 oil and natural gas prices for the periods indicated on a BOE basis.

The sharp decline in average prices received for both crude oil and natural gas during the first half of 2015 has had a significant adverse impact on the Partnership’s results of operations.  The Partnership’s Slaughter Dean Properties, which were an older, higher cost waterflood unit, had lease operating costs in excess of oil and gas sales revenues for the three and six month periods ended June 30, 2015. The sale of the Slaughter Dean Properties is expected to improve the Partnership’s overall results of operations during the remainder of 2015. Nonetheless, as prices continue to remain significantly lower than they were during the summer of 2014, the Partnership expects to incur additional impairment of oil and gas assets during the third and fourth quarters of 2015.

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The estimated net proved crude oil and natural gas reserves at June 30, 2015 and 2014 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 30, 2015, the un-weighted arithmetic average prices were $71.73 per Bbl of crude oil and $3.32 per thousand cubic feet (“Mcf”) of natural gas, compared to $105.28 per Bbl of crude oil and $4.29 per Mcf of natural gas at June 30, 2014.

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. Crude oil and natural gas reserves attributable to the Slaughter Dean properties sold during June 2015 totaled 104,760 barrels of crude oil and 67,860 Mcf of natural gas at June 30, 2014.

The lower commodity prices experienced during the first six months of 2015 will be included in future ceiling test limitations for each of the next two quarterly computations. Therefore, the Partnership expects estimated net proved crude oil and natural gas reserves to continue to decline, and that the Partnership will incur additional impairment charges in future quarters of 2015. While impairment charges do not impact cash flows from operating activities, continuing lower prices for crude oil and natural gas would have a significant impact on revenues and operating cash flow and the ability to sell producing properties.

Three months ended June 30, 2015 compared to the three months ended June 30, 2014

The Partnership had net income of $644,710 for the three month period ended June 30, 2015, compared to net income of $122,083 for the three month period ended June 30, 2014. Excluding the gain on sale of $1,673,100 recorded in connection with the sale of the Slaughter Dean Properties, the Partnership had a net loss of $1,028,390 for the three month period ended June 30, 2015. Other than the sale of the Slaughter Dean Properties, 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 three month period ended June 30, 2015, the Partnership recognized impairment expense of proved property totaling $824,350, primarily due to lower commodity prices. During the three month period ended June 30, 2014, the Partnership had no impairment of proved property.

Partnership revenues totaled $568,829 for the three month period ended June 30, 2015 compared to $1,172,696 for the three month period ended June 30, 2014, a decrease of 51.5% due primarily to decreases in oil and natural gas sales prices. Oil and gas sales volumes decreased during the three month period ended June 30, 2015 compared to the three month period ended June 30, 2014 by approximately 5.7% on a BOE basis as a result of natural declining production from existing wells. However, prices had a greater impact on sales revenues, with the average sales price for crude oil decreasing by 48.0%, to an average price of $48.16 per Bbl for the three month period ended June 30, 2015 compared to an average price of $92.65 per Bbl for the three month period ended June 30, 2014. The average sales price for natural gas decreased by 50.4%, to an average price of $2.31 per Mcf for the three month period ended June 30, 2015 compared to an average price of $4.66 per Mcf for the three month period ended June 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 mid-March low of $43.29 per Bbl, NYMEX West Texas Intermediate (“NYMEX-WTI”) crude oil prices rose during most of the second quarter of 2015, reaching as high as $61.05 per Bbl in late June before beginning to decline. These movements show that crude oil prices are likely to remain volatile, and commodity prices 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

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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 decreased from $481,534 for the three month period ended June 30, 2014 to $436,415 for the three month period ended June 30, 2015. During the second quarter of 2014, the Partnership experienced higher operating costs in connection with projects on its non-operated Thums Long Beach Unit (property interest purchased in the Azalea and Lett acquisitions) due to the completion of several projects. In addition, expenses on the Slaughter Dean Properties decreased as the Partnership shut-in wells and delayed workover expenses. In addition, lease operating expenses on the Slaughter Dean Properties ceased as of June 12, 2015, the date of sale of such properties. Production taxes also decreased in conjunction with the decline in oil and gas sales revenues, dropping from $66,334 for the three month period ended June 30, 2014 to $33,430 for the three month period ended June 30, 2015.

General and administrative costs decreased from $165,753 for the three month period ended June 30, 2014 to $148,073 for the three month period ended June 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 $105,583 for the three month period ended June 30, 2014 to $99,282 for the three month period ended June 30, 2015. In addition, third party engineering costs declined by approximately $13,500.

Six months ended June 30, 2015 compared to the six months ended June 30, 2014

The Partnership had a net loss of $2,479,627 for the six month period ended June 30, 2015, compared to a net loss of $36,057 for the six month period ended June 30, 2014. After adjusting for the gain on sale of the Slaughter Dean Properties of $1,673,100, the net loss for the six month period ended June 30, 2015 was $4,152,727.  Other than the sale of the Slaughter Dean Properties, 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 six month period ended June 30, 2015, the Partnership recognized impairment expense of proved property totaling $3,469,416, primarily due to lower commodity prices. During the six month period ended June 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 June 30, 2015, as a result of including the first-day-of-the month commodity prices for the first six months of 2015 in this calculation, estimated reserves were calculated using average prices of $71.73 per Bbl for crude oil and $3.32 per Mcf of natural gas. Because the average price uses the preceding 12 month period, these lower 2015 commodity prices will be included in future ceiling test limitations for each of the next two quarterly computations, and the Partnership expects to incur additional impairment charges in future quarters of 2015. While impairment charges do not impact cash flows from operating activities, continued lower prices for crude oil and natural gas would have a significant impact on revenues and operating cash flow.

Partnership revenues totaled $1,063,942 for the six month period ended June 30, 2015 compared to $2,308,240 for the six month period ended June 30, 2014, a decrease of 53.9% due primarily to decreases in oil and natural gas sales prices. Oil and gas sales volumes decreased during the six month period ended June 30, 2015 compared to the six month period ended June 30, 2014 by approximately 20.4% on a BOE basis as a result of natural declining production from existing wells. However, prices had a greater impact on sales revenues, with the average sales price for crude oil decreasing by 46.7%, to an average price of $46.28 per Bbl for the six month period ended June 30, 2015 compared to an average price of $86.91 per Bbl for the six month period ended June 30, 2014. The average sales price for natural gas decreased by 44.1%, to an average price of $2.48 per Mcf for the six month period ended June 30, 2015 compared to an average price of $4.44 per Mcf for the six month period ended June 30, 2014.  Over

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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 mid-March low of $43.29 per Bbl, NYMEX-WTI crude oil prices rose during most of the second quarter, reaching as high as $61.05 per Bbl in late June. During the latter part of July, price per Bbl dropped below $50.00. These movements show that crude oil prices are likely to remain volatile, and commodity prices 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 decreased from $1,139,732 for the six month period ended June 30, 2014 to $946,779 for the six month period ended June 30, 2015. During the first half of 2014, the Partnership experienced higher operating costs in connection with projects on its non-operated Thums Long Beach Unit (property interest purchased in the Azalea and Lett acquisitions) due to the completion of several projects. In addition, expenses on the Slaughter Dean Properties decreased as the Partnership shut-in wells and delayed workover expenses. In addition, lease operating expenses on the Slaughter Dean Properties ceased as of June 12, 2015, the date of sale of such properties. Production taxes also decreased in conjunction with the decline in oil and gas sales revenues, dropping from $135,571 for the six month period ended June 30, 2014 to $62,963 for the six month period ended June 30, 2015.

General and administrative costs decreased from $347,988 for the six month period ended June 30, 2014 to $314,689 for the six month period ended June 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 $228,817 for the six month period ended June 30, 2014 to $192,209 for the six month period ended June 30, 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.

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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 30, 2015 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 were no material changes in the Risk Factors applicable to the Partnership as set forth in the Annual Report.

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

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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.

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EXHIBIT INDEX

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