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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, 2014

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)

(972)-437-6792

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 14, 2014, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest and 0.6000 units of limited partner interest held by the managing general partner, and 396.4172 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, 2014

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 2014. 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, 2013 (the “Annual Report”). The results of operations for the three and six month periods ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

2. Summary of Accounting Policies

Oil and Gas Properties

The Partnership follows the full cost method of accounting for its oil and gas activities. 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.

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 sum of the estimated future net revenues from 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, 2014 and 2013, the Partnership recognized no property impairment expense of proved properties.

At June 30, 2014 and December 31, 2013, unproved property consists of non-operated, undrilled infill and offset acreage acquired in connection with an acquisition of oil and gas properties during 2010. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date. The assessment includes consideration of the following factors, among others: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property; and geological and geophysical evaluation.  To the extent that the assessment indicates a property is impaired, the amount of impairment is added to the capitalized costs of oil and gas properties which are subject to the quarterly ceiling test. During the three and six month periods ended June 30, 2014 and 2013, the Partnership recognized no impairment of unproved properties.

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Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at June 30, 2014 and December 31, 2013 are 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.

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 net income. A decline in estimated proved reserves and future cash flows 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, 2014 and the year ended December 31, 2013.

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 and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at June 30, 2014 and December 31, 2013 as it is subject to short-term floating interest rates that approximate the rates available to the Partnership for those periods, and is classified as Level 2 within the fair value hierarchy.

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.

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3. Long-Term Debt

On June 30, 2010, the Partnership and Texas Capital Bank, N.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding a property acquisition. The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5.0%, payable monthly.  At June 30, 2014, the interest rate was 5.0%. The obligation of TCB to the Partnership under the Credit Agreement expires on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with TCB’s customary practices for oil and gas loans.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time without premium or penalty.

The borrowing base reduces at a rate of $30,000 per month. In addition to the required monthly principal payment of $30,000, the Partnership made a principal prepayment of $150,000 to TCB during June 2014. At June 30, 2014, the borrowing base is $510,000, and the current outstanding loan balance is $360,000.  The Partnership has no plans to request any additional borrowing or changes to the borrowing base, and does not expect to extend the term of the loan beyond its current expiration date of June 30, 2015.

The Credit Agreement is guaranteed by two Reef affiliated entities. Borrowings under the Credit Agreement are secured by a first priority lien on no less than 90% of the oil and gas properties utilized in determining the borrowing base, based on the net present value of the crude oil and natural gas to be produced from the oil and gas properties calculated using a discount rate of nine percent (9.00%) per annum.

The Credit Agreement contains various covenants, including among others:

·                  restrictions on liens;

·                  restrictions on incurring other indebtedness without the lenders’ consent;

·                  restrictions on distributions and other restricted payments;

·                  maintenance of a current ratio as of the end of each fiscal quarter of not less than 1.0 to 1.0, as adjusted; and

·                  maintenance of an interest coverage ratio of cash flow to fixed charges as of the end of each fiscal quarter, to be at least 3.0 to 1.0.

All outstanding amounts owed under the Credit Agreement become due and payable upon the occurrence of certain usual and customary events of default, including among others:

·                  failure to make payments under the Credit Agreement;

·                  non-performance of covenants and obligations continuing beyond any applicable grace period; and

·                  the occurrence of a “Change in Control” (as defined in the Credit Agreement).

At June 30, 2014, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into a Partnership bank account maintained at the lender.  A waiver of this requirement through December 31, 2014 has been obtained.

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4. Transactions with Affiliates

The Partnership has no employees. Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. RELP currently serves as the operator of the Slaughter Field in Cochran County, Texas and the wells in which the Partnership holds an interest thereon (the “Slaughter Dean wells”) and receives 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, 2014 and the year ended December 31, 2013, RELP received $2,808 and $25,602 in drilling compensation, respectively. 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 all out-of-pocket expenses incurred on behalf of the Partnership. During the three and six month periods ended June 30, 2014, Reef and its affiliates received total reimbursements for direct costs of $34,830 and $50,472, respectively, and other out-of-pocket expenses of $402 and $598, respectively. During the three and six month periods ended June 30, 2013, Reef and its affiliates received total reimbursements for direct costs of $30,161 and $65,803, respectively, and other out-of-pocket expenses of $627 and $910, respectively.

RELP also receives an administrative fee to cover all general and administrative costs.  During the three and six month periods ended June 30, 2014, RELP received administrative fees totaling $105,583 and $228,817, respectively. During the three and six month periods ended June 30, 2013, RELP received administrative fees totaling $117,260 and $241,169, respectively. Administrative fees are 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 by third parties, but excluding direct costs and operating costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At June 30, 2014 and December 31, 2013, RELP owed the Partnership $554,394 and $509,271, respectively, for net revenues processed in excess of joint interest, drilling compensation, and technical and administrative services charges.  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.

5.  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, 2014 is detailed below:

For the three months ended June 30, 2014

For the six months ended June 30, 2014

6.  Subsequent Event

On July 1, 2014, the Partnership made a principal prepayment of $180,000 to TCB in accordance with the terms of the Credit Agreement. This principal prepayment reduced the outstanding loan balance to $180,000. Also, on July 1, 2014, the Partnership requested that TCB reduce the borrowing base to $180,000. The borrowing base continues to reduce at a rate of $30,000 per month.

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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.

Reef does not intend to update its forward-looking statements, except as otherwise required by applicable law.  All subsequent written and oral forward-looking statements attributable to Reef or persons acting on its behalf are expressly qualified in their entirety by the applicable cautionary statements.

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Overview

Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership formed in November 2007. 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 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 formed 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 certain working interests in oil and gas properties (“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, and Arkansas, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership decide to participate in such developmental drilling, funds to drill are taken from current net cash flows available for distributions to investors. The Partnership does not expect to purchase interests in any additional properties.

The Partnership owns 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.  RELP, an affiliate of Reef, serves as the operator of the Slaughter Dean wells, which are located in Cochran County, Texas. All other properties that have been acquired by the Partnership are operated by third party operators not affiliated with Reef or any of Reef’s affiliates. The Partnership does not operate in any other industry segment.

At December 31, 2010, the Partnership fully impaired its unproved properties associated with the Slaughter Dean waterflood enhancement project by recognizing approximately $53,166,873 of property impairment expense.  The Partnership continues to monitor the waterflood operations and daily production of total fluids (oil and water). Although the total water injection on a daily basis exceeds the fluids being removed from the reservoir, no noticeable increase in pressure or fluid production has been observed. During 2012, RELP ran injection profile logs on five of the current water injection wells hoping they might aid in determining if there is any work that might be performed on the injection wells to try and improve the waterflood pattern performance; however, the results of this work were inconclusive. While alternative configurations may improve waterflood results, the Partnership does not possess the capital required to implement a re-configuration of the waterflood operations. As a result, RELP continues to operate the Slaughter Dean waterflood project as currently configured.

During the three months ended June 30, 2014, the Partnership sold its interest in several oil and gas wells located in Crane County, Texas for $134,798. The operator of the properties notified the Partnership of their intent to form a waterflood unit to be implemented in three phases. The cost of the initial phase, net to the Partnership’s interest, was approximately $351,500, and would require the Partnership to utilize its existing cash flows to pay the capital costs associated with the implementation of the waterflood unit, instead of distributing such cash flows to investors. The Partnership utilized the sales proceeds, as well as current operating cash flows, to make a $150,000 prepayment of loan principal to TCB during June 2014. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to the sale of the wells.

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, 2014, the Partnership had expended $81,262,859 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.

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The Partnership had working capital of $800,982 at June 30, 2014. 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 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, as it did during the three and six months ended June 30, 2014.

The Partnership’s Credit Agreement contains various covenants.  At June 30, 2014 and December 31, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into a Partnership bank account maintained at the lender.  Since the inception of the Credit Agreement in 2010, the lender has provided the Partnership with a waiver of this requirement each December 31, with such waiver covering the succeeding calendar year. The Partnership currently has obtained a waiver of this requirement from the lender through December 31, 2014. As a result of principal prepayments on the loan made during June and July 2014, and the reduction of the borrowing base to $180,000 effective July 1, 2014, the loan borrowing base will reduce to $0 as of December 31, 2014, and the Partnership expects that the loan will be paid in its entirety as of December 31, 2014.

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 estimated net proved crude oil and natural gas reserves at June 30, 2014 and 2013 are summarized below. 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.

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Three months ended June 30, 2014 compared to the three months ended June 30, 2013

The Partnership had net income of $122,083 for the three month period ended June 30, 2014, compared to net income of $102,871 for the three month period ended June 30, 2013. Decreases in oil and gas sales revenues as a result of decreased production volumes were more than offset by decreases in lease operating expenses and general and administrative costs.

Partnership revenue decreased by approximately 12.6% to $1,172,696 for the three month period ended June 30, 2014 from $1,342,186 for the comparable three month period ended June 30, 2013, primarily as a result of decreased volumes. Overall sales volumes decreased by 20.0% on a BOE basis as a result of natural declining oil and gas production from wells in which the Partnership owns an interest. Volumes declined primarily in the Azalea properties. Average sales prices received for crude oil increased by 5.9% from $87.51 per barrel received during the three month period ended June 30, 2013 to $92.65 per barrel received for the three month period ended June 30, 2014. Natural gas sales prices received increased by 16.21%, from $4.01 per Mcf during the three month period ended June 30, 2013 to $4.66 per Mcf for the three month period ended June 30, 2014. 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 a vast majority 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 gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

Lease operating expenses decreased from $604,372 for the three month period ended June 30, 2013 to $481,534 for the three month period ended June 30, 2014. Lease operating expenses for the non-RELP operated Thums unit, which has over 1,400 wells, increased from an average of 26% of revenues during 2013 to 29% of revenues during the second quarter of 2014. This increase is due to the completion of several projects, and expenses are expected to return to more normal levels in future quarters. This increase was offset by decreased lease operating expenses on the Slaughter Dean wells caused by decreased workover costs and ad valorem taxes, partially offset by general increases in operating costs.

General and administrative costs incurred during the three month periods ended June 30, 2014 and 2013 decreased to $165,753 from $205,600. 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 various 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. The administrative overhead charged by RELP to the Partnership decreased slightly, from $117,260 during the three month period ended June 30, 2013 to $105,583 during the three month period ended June 30, 2014. Professional service fees related to processing SEC filings also contributed to the decrease in general and administrative costs.

Six months ended June 30, 2014 compared to the six months ended June 30, 2013

The Partnership had a net loss of $36,057 for the six month period ended June 30, 2014, compared to net income of $149,300 for the six month period ended June 30, 2013. The primary cause of this change was a decrease in revenue as a result of decreased production volumes.

Partnership revenue decreased by approximately 8.2% to $2,308,240 for the six month period ended June 30, 2014 from $2,515,170 for the comparable six month period ended June 30, 2013, primarily as a result of decreased volumes. Overall sales volumes decreased by 6.4% on a BOE basis as a result of natural declining oil and gas production from wells in which the Partnership owns an interest. Volumes declined primarily in the Azalea properties. Average sales prices received for crude oil increased by 0.4%; from $86.59 per barrel received during the six month period ended June 30, 2013 to $86.91 per barrel received for the six month period ended June 30, 2014. Natural gas sales prices received increased by 7.5%, from $4.13 per Mcf during the six month period ended June 30, 2013 to $4.44 per Mcf for the six month period ended June 30, 2014.  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 a vast majority 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 gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

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Lease operating expenses decreased from $1,165,328 for the six month period ended June 30, 2013 to $1,139,732 for the six month period ended June 30, 2014. Lease operating expenses for the non-RELP operated Thums unit, which has over 1,400 wells, increased from an average of 28% of revenues during the six month period ended June 30, 2013 to 31% of revenues during the six month period ended June 30, 2014. This increase is due to the completion of several projects, and expenses are expected to return to more normal levels in future quarters. These increases were offset by decreased lease operating expenses on the Slaughter Dean wells, caused by decreased workover costs and ad valorem taxes, partially offset by general increases in operating costs which are expected to increase overall operating costs for 2014.

Depreciation, depletion and amortization costs increased from $525,642 for the six months ended June 30, 2013 to $622,303 for the six months ended June 30, 2014. The increase in depletion can be expected to continue during the remainder of 2014.

General and administrative costs incurred during the six month periods ended June 30, 2014 and 2013 decreased to $347,988 from $405,975. 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 various 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. The administrative overhead charged by RELP to the Partnership decreased slightly, from $241,169 during the six month period ended June 30, 2013 to $228,817 during the six month period ended June 30, 2014. Professional service fees related to processing SEC filings also contributed to the decrease in general and administrative costs.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

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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

*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

  *Filed herewith

**Furnished herewith

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