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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 March 31, 2016

or

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

For the Transition Period from          to

Commission File Number: 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 ¨

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 ¨

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 ¨  No x

As of May 13, 2016, the registrant had 885.6999 units of limited partner interest outstanding, and 8.9697 units of general partner interest and 1.3000 of limited partner interest held by the managing general partner.

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

Form 10-Q Index

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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)

March 31, 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 three months of 2016. Therefore, please read these unaudited condensed financial statements and notes to unaudited condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “Annual Report”). The results of operations for the three month period ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Going Concern

The accompanying financial statements have been prepared assuming the Partnership is a going concern. Our independent registered public accounting firm’s opinion included in our Annual Report includes an explanatory paragraph regarding the Partnership’s limited life, and management’s plan to sell all remaining assets of the Partnership, wind up and terminate the Partnership during 2016, as specified in the Partnership’s governing documents at its inception. 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 (“Bbl”) of crude oil. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are

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accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves. During the three month period ended March 31, 2016, the Partnership recognized a gain of $100,543 in connection with a sale of oil and gas properties. During the three month period ended March 31, 2015, the Partnership did not have any sales of 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, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

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

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

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

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

Fair Value of Financial Instruments

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

Recent Accounting Developments — Revenue Recognition

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

The Financial Accounting Standards Board (“FASB”) issued 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 Partners and Reef pays no drilling or completion expenses for this interest. In addition, Reef has purchased 1.30 units of Partnership interest from investor partners. Effective September 1, 2015 Reef receives 11.13% and investor partners receive 88.87% of total cash distributions. During the three month periods ended March 31, 2016 and 2015, Reef received $109,088 and $0, respectively, in cash distributions related to its Partnership interest.

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The Partnership has no employees. RELP employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. RELP is entitled to receive drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP served as the operator of the Partnership’s Slaughter Field in Cochran County, Texas and the wells in which the Partnership held an interest thereon (the “Slaughter Dean Wells”) prior to their sale during the second quarter of 2015.  RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for all non-operated wells. Total well costs include all drilling and equipment costs, including intangible development costs, tangible costs during drilling and completion of a well, costs of storage and other surface facilities, and the costs of gathering pipelines necessary to connect the well to the nearest appropriate delivery point.  In addition, total well costs 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 three month period ended March 31, 2016 and the year ended December 31, 2015, RELP received $1,274 and $13,564, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.

Additionally, Reef and its affiliates are reimbursed for direct costs and documented out-of-pocket expenses incurred on behalf of the Partnership. During the three month periods ended March 31, 2016 and 2015, the Partnership paid Reef and its affiliates $32,949 and $24,019, respectively, for direct costs and paid Reef and its affiliates $2,065 and $967, 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 month periods ended March 31, 2016 and 2015, the administrative overhead charged by RELP to the Partnership totaled $26,006 and $92,927, respectively. The administrative overhead charged by RELP is included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or third parties, but excluding direct and operating costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At 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 month periods ended March 31, 2016 and 2015 is detailed below:

For the three months ended March 31, 2016

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For the three months ended March 31, 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;

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

·                                     statements regarding the amounts and timing of distributions;

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

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

·                                     any statements of other than historical fact.

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

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

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Going Concern

Management is currently pursuing the sale of all Partnership assets with the intent to wind up and terminate the Partnership during 2016. As a result, the Partnership is not expected to continue as a going concern. In accordance with generally accepted accounting principles for a limited life entity, the Partnership has not applied the liquidation basis of accounting to these financial statements.

Overview / Outlook

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

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

The Partnership made three major property acquisitions between 2007 and 2010, referred to as the Slaughter Dean acquisition, Azalea acquisition, and Lett acquisition, with the capital raised by the Partnership, and thereby 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 RELP, an affiliate of Reef and the Partnership. RELP served as operator of the Slaughter Dean acquisition properties prior to their sale in 2015. All wells included in the Azalea and Lett acquisitions are operated by third parties not affiliated with the Partnership, Reef, or any other Reef affiliate. The most significant property acquired in the Azalea and Lett acquisitions was a working interest in the Thums Long Beach Unit located underneath the Long Beach Harbor in Southern California.

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

As commodity prices continued to decline, 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.

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As of March 31, 2016, the Partnership continues to own working interests in more than 500 wells acquired in the Azalea acquisition, located in Texas, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Kansas, Montana, and Colorado. The Partnership divested of all of its Alabama and Arkansas properties during the first quarter of 2016.

Liquidity and Capital Resources

The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef.  Non-Reef partners purchased 490.9827 units of general partner interest and 397.0172 units of limited partner interest for $88,648,094, net of adjustments for sales to brokers for their own accounts, who were permitted to buy units at a price net of the commission that they would normally earn on sales of units. Reef contributed $762,425 for the purchase of 8.9697 units of general partner interest at a price of $85,000 per unit, which is net of the 15% management fee paid by non-Reef investors. The 15% management fee used to pay organization and offering costs, including sales commissions, totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of March 31, 2016, the Partnership had expended $81,407,630 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 declined during the first quarter of 2016, from $1,640,865 at December 31, 2015 to $577,490 at March 31, 2016, primarily as a result of distributing proceeds received from property sales made during 2015 to the investor partners during the first quarter of 2016.  The Partnership has maintained a portion of the cash received from property sales to cover any deficits during the divestiture of all remaining properties and the winding up and termination of the Partnership. The Partnership generally maintains nominal working capital, as cash flows are normally utilized to pay monthly cash distributions to investors.  Sources of future funding consist of cash on hand, cash flow from operations, and cash flow from sales of properties.  The Partnership may not be able to sell properties at the values desired in order to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.

Results of Operations

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

The following table provides information about sales volumes and sales prices received for the periods indicated.

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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.

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 estimated net proved crude oil and natural gas reserves at March 31, 2016 and 2015 are summarized below. Reserve estimates are calculated using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and end of period costs. At March 31, 2016, the un-weighted arithmetic average prices were $46.16 per Bbl of crude oil and $2.41 per thousand cubic feet (“Mcf”) of natural gas, compared to $82.72 per Bbl of crude oil and $3.88 per Mcf of natural gas at March 31, 2015.

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

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

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31, 2015 by approximately 65.8% on a BOE basis, primarily as a result of the 2015 and 2016 property sales. Prices also had a significant impact on sales revenues, with the average sales price for crude oil decreasing by 40.5%, to an average price of $26.33 per Bbl for the three month period ended March 31, 2016 compared to an average price of $44.26 per Bbl for the three month period ended March 31, 2015. The 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 31, 2016 compared to an average price of $2.67 per Mcf for the three month period ended March 31, 2015.  At March 31, 2016, approximately 44.6% of the Partnership’s reserves are crude oil reserves and 55.4% of the Partnership’s reserves are natural gas reserves, so the average price of both commodities significantly impacts Partnership results.

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

Lease operating expenses 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.

General and administrative costs decreased from $166,616 for the three month period ended March 31, 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 month period ended March 31, 2015 to $26,006 for the three month period ended March 31, 2016.

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 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

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

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

None.

Item 3.  Default Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

Item 6.  Exhibits

Exhibits

*Filed herewith

**Furnished herewith

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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

Exhibits

*Filed herewith

**Furnished herewith

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