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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended September 30, 2012

or

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 November 14, 2012, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest held by the managing general partner, and 397.0172 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)

1. Organization and Basis of Presentation

The condensed financial statements of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first nine months of 2012. 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, 2011 (the “Annual Report”). The results of operations for the three and nine month periods ended September 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

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, as determined by independent petroleum engineers.  Proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

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 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. No gain or loss is recognized upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and nine month periods ended September 30, 2012 and 2011, the Partnership recognized no property impairment expense of proved properties.

At September 30, 2012 and December 31, 2011, unproved properties consist of non-operated, undrilled infill and offset drilling locations associated with certain working interests acquired from Azalea Properties Ltd. on January 19, 2010 by RCWI L.P., an affiliate of Reef, and assigned to the Partnership (the “Azalea Acquired Properties”). Unproved properties are assessed for impairment at least annually as of the balance sheet date by considering drilling activity in the area of the unproved properties and other information.  Any impairment resulting from this assessment is included in the full cost pool in the current period, as appropriate. During the three and nine month periods ended September 30, 2012 and 2011, the Partnership recognized no impairment of unproved properties.

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at September 30, 2012  and December 31, 2011 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 current 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.

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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.

During the quarter ended September 30, 2011, the Partnership began plugging operations on seven wells located in the Slaughter Dean Field. Approximately $14,342 of plugging and abandonment costs were applied against the Partnership’s asset retirement obligation shown on the accompanying balance sheet, and the remaining amount of approximately $62,000 was recorded as current cost and is classified as lease operating expenses on the Partnership’s statement of operations. As a result of these plugging and abandonment operations, the Partnership revised its estimated liability during the quarter for the Slaughter Dean Field (approximately 145 wells) by increasing the basis of the Slaughter Dean wells by $860,878 and recording additional asset retirement obligation of this amount as a change in estimate.

During the quarter ended September 30, 2012, the Partnership plugged and abandoned three wells located in the Slaughter Dean Field. Approximately $27,362 of plugging and abandonment costs related to these three wells were applied against the Partnership’s asset retirement obligation shown on the accompanying balance sheet, and approximately $88,000 was recorded as a current cost and classified as lease operating expense for the three and nine month periods ended September 30, 2012. The Partnership received lower bids for providing plugging services from two other third party vendors; however, those vendors could not schedule the services prior to the regulatory deadlines imposed by the state.  Based upon the bids received from the other two vendors, the Partnership did not revise its estimated asset retirement liability for the other wells in the Slaughter Dean Field.

The following table summarizes the Partnership’s asset retirement obligation for the nine month period ended September 30, 2012 and the year ended December 31, 2011.

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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, accounts receivable, 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 September 30, 2012 and December 31, 2011 and is classified as Level 2 within the fair value hierarchy.

Reclassifications

Certain information provided for prior years has been reclassified to conform to the current year presentation adopted as of March 31, 2012.

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 the acquisition of certain oil and gas properties (“Lett Acquired Properties”) purchased from Lett Oil & Gas, L.P. (“Lett”) by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in Note 2 of the Annual Report.  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%, payable monthly.  At September 30, 2012, the interest rate was 5.00%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2013, 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 the TCB’s customary practices for oil and gas loans.  The Partnership borrowed $5,000,000 from TCB under the Credit Agreement which was paid directly to Lett to satisfy the closing obligations of RCWI under the purchase agreement for the Lett Acquired Properties.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.

Under the terms of the Credit Agreement, on June 30, 2010 the Partnership paid TCB a facility fee of $50,000 (one percent (1.00%) of the initial borrowing base) and is obligated to further pay, upon each determination of an increase in the borrowing base, a facility fee in the amount of one percent (1.00%) of the amount by which the borrowing base is increased over that in effect on the date of determination.  On June 30, 2010, the Partnership also paid TCB an engineering fee in the amount of $5,000, and is obligated to further pay additional engineering fees in the amount of $5,000 if TCB’s internal engineers perform the engineering review of the collateral; or the actual fees and expenses of any third-party engineers retained by TCB to prepare an engineering report, payable at the time of a redetermination of the borrowing base.

The Credit Agreement is guaranteed by RCWI and RCWI GP LLC, each an affiliate of Reef. 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.

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On May 20, 2011, the Partnership entered into the First Amendment to Credit Agreement (“Amendment”) with TCB. Under the Amendment, the borrowing base was reduced to the Partnership’s outstanding balance of $4,100,000 effective May 20, 2011.  In addition, effective June 1, 2011, the borrowing base is reduced by $55,000 per month.  On May 24, 2011, the Partnership paid TCB fees of $43,500 in connection with the Amendment.  These fees were capitalized as other non-current assets and are being amortized over the term of the credit agreement. The unamortized portion of these fees at June 30, 2012 was reclassified from non-current to current assets, as the Credit Agreement expires on June 30, 2013.

During July 2011, the Partnership and TCB executed the Second Amendment to Credit Agreement (“Second Amendment”), which was effective as of June 30, 2011. Under the Second Amendment, the borrowing base was reduced to $1,945,000 as of June 30, 2011 and the Partnership made a principal payment of $2,100,000 to reduce the loan balance to this amount.  In addition, effective August 1, 2011, the borrowing base is reduced by $30,000 per month.  During July 2011, the Partnership paid TCB fees of $6,316 in connection with the Second Amendment.  These fees were capitalized as other non-current assets and are being amortized over the term of the credit agreement.  The unamortized portion of these fees at June 30, 2012 was reclassified from non-current to current assets, as the Credit Agreement expires on June 30, 2013. At September 30, 2012, the borrowing base and outstanding balance due TCB was equal to $1,495,000.  The Partnership has recognized the entire $1,495,000 as a current liability as of September 30, 2012 due to the June 30, 2013 expiration of the Credit Agreement.  There is no additional availability under the borrowing base as of September 30, 2012.

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 commencing September 30, 2010 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 commencing September 30, 2010, 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 September 30, 2012, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into an account with the lender.  A waiver of this requirement through December 31, 2012 has been obtained.

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 (“the Slaughter Dean Project”) and receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership.  RELP also receives

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drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells included in the Azalea Acquired Properties and the Lett Acquired Properties. All of the wells included in these two purchases are non-operated. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point.  In addition, total well costs include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion.  Total well costs do not include costs relating to lease acquisitions.  During the nine month period ended September 30, 2012, RELP received $31,811 in drilling compensation. During the year ended December 31, 2011, RELP received $54,005 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 all documented out-of-pocket expenses incurred on behalf of the Partnership. During the three and nine month periods ended September 30, 2012, Reef and its affiliates received total reimbursements for direct costs of $32,056 and $134,976, respectively, and other documented out-of-pocket expenses of $73 and $415, respectively. During the three and nine month periods ended September 30, 2011, Reef and its affiliates received total reimbursements for direct costs of $72,967 and $284,193, respectively, and other documented out-of-pocket expenses of $700 and $1,429, respectively.

Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12 th of 1% of all capital raised payable monthly, totaling $74,740 per month.  During the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from the fixed monthly amount referenced above to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships.  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. During the three and nine month periods ended September 30, 2012, RELP received administrative fees totaling $153,741 and $457,758, respectively. During the three and nine month periods ended September 30, 2011, RELP received administrative fees totaling $224,220 and $672,660, 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 September 30, 2012 and December 31, 2011, RELP owed the Partnership $768,071and $598,599, 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.

In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The Partnership received $350,000 in cash in exchange for these interests.  In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P.  The Partnership received $2,650,000 in cash in exchange for these additional interests.  These sales transactions reduced the full cost pool of capitalized oil and gas properties.  The Partnership recorded no gain or loss associated with these transactions.

In September 2012, the Partnership sold leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate.  As the estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also had one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three

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new drilled wells.  The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction.  The Partnership collected a portion of the cash related to this sale in October 2012. The purchase and sale agreement calls for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. An initial estimate of approximately $45,522 related to this PV12% value has been recorded as a part of the sales price, but payment will not be received by the Partnership until the exact amount due is known, subsequent to December 31, 2012. The final amount could be less than or more than the current estimate. The Partnership recorded no gain or loss related to this transaction.

5. Commitments and Contingencies

None.

6.  Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three and nine month periods ended September 30, 2012 is detailed below:

For the three months ended September 30, 2012

For the nine months ended September 30, 2012

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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 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.  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 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 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 the partners.  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. Although Reef believes that the expectations reflected in such forward-looking statements are reasonable, Reef can give no assurance that such expectations will prove to have been correct.  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.  There can be no assurance that the projected results will occur, that these judgments or assumptions will prove correct or that unforeseen developments will not occur.

Reef does not intend to update its forward-looking statements.  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.

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.

The Partnership utilized its capital to acquire oil and gas properties in three separate purchase transactions, and for a major waterflood development program. In January 2008, the Partnership purchased an initial 41% working interest in over 100 wells located in the Slaughter Dean Field in Cochran County, Texas, approximately 50 miles southwest of Lubbock, Texas. Under the terms of the acquisition agreement, as described in the Partnership’s Annual Report, each month thereafter additional working interests are purchased based on the amount the Partnership spends developing the field through January 2013. In a separate transaction in May 2008, the Partnership purchased an additional 11% working interest in the Slaughter Dean Field.

During 2010, the Partnership acquired from RCWI, L.P. (“RCWI”), an affiliate of Reef, 61% of the working interests acquired by RCWI in certain oil and gas properties from Azalea Properties Ltd (“Azalea Acquired Properties”). RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Acquired Properties cover 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 include undrilled infill and offset locations.  The Partnership acquired minority working interests in each of these properties, which are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef.

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In addition, during 2010 the Partnership acquired from RCWI all of the working interests acquired by RCWI in the Lett Acquired Properties.  The Lett Acquired Properties are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.  The acquired working interests are all minority non-operated working interests. The Thums Long Beach Unit is operated by a third party operator not affiliated with the Partnership or Reef.

On all properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but does not expect to engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations.  Drilling locations for unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef. During 2010 the Partnership, in two separate transactions, sold its interests in certain of the Azalea Acquired Properties to Reef 2010 Drilling Fund L.P., an affiliate, due to the planned drilling of exploratory wells. The Partnership sales included interests in fourteen existing productive wells, as well as the undeveloped acreage upon which the exploratory wells were to be drilled. The Partnership received a total of $992,755 in connection with these sales. The Partnership recorded no gain or loss associated with these transactions.

In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate.  In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The interests were sold primarily to pay down the Partnership’s debt obligations under its credit agreement. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June.  The Partnership recorded no gain or loss associated with this transaction.

In September 2012, the Partnership sold leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate.  As the estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also had one productive working interest well and — productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three new drilled wells.  The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction.  The Partnership collected a portion of the cash related to this sale in October 2012. The purchase and sale agreement calls for the Partnership to receive an amount equal to the PV12% value of the first drilled well, based upon a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. An initial estimate of approximately $45,522 related to this PV12% value has been recorded as a part of the sales price, but payment will not be received by the Partnership until the exact amount due is known, subsequent to December 31, 2012. The final amount could be less than or more than the current estimate. The Partnership recorded no gain or loss related to this transaction.

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of September 30, 2012.

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The Partnership has expended approximately $57,244,510 (included in the expenditures shown in the table above) on the Slaughter Dean Project as of September 30, 2012.  During the period from 2008 through 2010, the Partnership implemented a waterflood enhancement project on a portion of the Slaughter Dean Field. Well spacing was reduced from 40 to 20 acres per well.  The Partnership drilled 30 new producing wells and 5 new water injection wells, and performed workover operations on several old producing wells. In addition, 22 existing wells were converted to water injection wells and a new water injection pump was installed in order to increase the amount of water being injected back into the producing formation. Although the Slaughter Dean Field experienced periodic small increases in production during 2010, the waterflood enhancement project has not led to increased crude oil production as planned. Based upon observed results during 2010, the Partnership concluded during the fourth quarter of 2010 that although significant crude oil reserves may remain in the reservoir, the project work was deemed unlikely to be effective in materially increasing the recovery of those reserves. Therefore, at December 31, 2010, the Partnership fully impaired its unproved properties associated with the Slaughter Dean Project by recognizing approximately $53,166,873 of property impairment expense.  The Partnership continues to monitor the implementation of waterflood operations and daily production of total fluids (oil and water), which are less than the total water injected each day, to determine the cause of the underperformance of the waterflood operations.  The Partnership may gather additional data in order to determine whether alternate configurations of water injection wells may be more effective in producing a better waterflood response in the future, though such alternative configurations may be cost prohibitive to the Partnership to implement.  The Partnership currently plans to continue waterflood operations as currently configured.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in the Annual Report.

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 general partner units and 397.0172 limited partner units 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 general partner units at a price of $85,000 per unit, which is net of all offering costs. Organization and offering costs totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of September 30, 2012, the Partnership had expended $78,643,330 on property acquisition and development costs, prior to sales of the Partnership’s interests or portions of its interests in certain properties during 2011 and 2012. Expenditures in excess of available capital have been financed through debt or recovered from cash flows by reducing Partnership distributions.

The Partnership had negative working capital of $82,843 at September 30, 2012, primarily as a result of the classification of the Partnership’s note payable balance as a current liability due to the expiration of the Partnership’s credit agreement on June 30, 2013. The Partnership is currently evaluating its options to meet its obligations under its credit agreement, including the sale of producing properties or an extension of its credit agreement.

Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the 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 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.

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It 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.

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The following table provides information about sales volumes and crude oil and natural gas prices for the periods indicated. Equivalent barrels of oil (“EBO”) are computed by converting 6 Mcf of natural gas to 1 barrel of crude oil.

The estimated net proved crude oil and natural gas reserves as of September 30, 2012 and 2011 are summarized below. The quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. 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 September 30, 2012 compared to the three months ended September 30, 2011

The Partnership had net income of $190,888 for the three month period ended September 30, 2012, compared to net income of $1,847 for the three month period ended September 30, 2011. The primary causes of this change were decreases in production taxes, lease operating expenses, and general and administrative costs.

Partnership revenue decreased slightly between comparative periods, totaling $1,345,466 for the three month period ended September 30, 2012 compared to $1,350,349 for the comparable three month period in 2011.  While overall sales volumes increased as a result of production from newer wells offsetting natural declines from existing wells, average prices received for crude oil and natural gas were less in the third quarter of 2012 as compared to the third quarter of 2011. The average sales price for crude oil dropped by 3.1%, to an average price of $85.82  per Bbl for the three month period ended September 30, 2012, compared to an average price of $88.60 for the three month period ended September 30, 2011.  The average sales price for natural gas fell by 39.0% from an average price of $4.03 per Mcf during the three month period ended September 30, 2011 to $2.46 during the three month period ended September 30, 2012.  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. The average price received for the Partnership’s natural gas production during the third quarter of 2012 was at its lowest point for any quarter since the fourth quarter of 2009. The Partnership expects increased gas revenues for the fourth quarter of 2012 as compared to the third quarter of 2012 because it anticipates natural gas prices will improve throughout the quarter. However, the Partnership is impacted more significantly by crude oil prices, as natural gas sales were only 5.9% of total Partnership sales revenues during the third quarter of 2012. If crude oil prices continue to trend downward, it could have a greater impact on overall fourth quarter sales revenues.

Lease operating expenses decreased from $698,023 for the three month period ended September 30, 2011 to $619,270 for the three month period ended September 30, 2012. Operating costs related to the Partnership’s interest in the non-operated Thums Long Beach Unit decreased by approximately $100,000 this quarter compared to the comparative quarter for 2011, primarily due to decreased utility and well services costs, and a reduction in the accrual for monthly operating costs for this unit.  The decrease in expenses related to the Thums Long Beach Unit was partially offset by increased workover costs in the Slaughter Dean Field during the three month period ended September 30, 2012, including plugging and abandonment costs in excess of accreted asset retirement liability for three wells in that field.

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Production tax expense totaled $18,832 for the three month period ended September 30, 2012 compared to $88,618 for the three month period ended September 30, 2011. During the third quarter of 2012, RELP received a production tax refund from the State of Texas of approximately $54,000 related to the waterflood enhancement project performed in the Slaughter Dean Field. RELP had applied for a ten year severance tax reduction (the state severance tax on oil production is reduced by 50%, from 4.6% to 2.3%) after completing the waterflood enhancement project during 2011. The State of Texas approved the severance tax reduction for the ten year period beginning period August 2011 through July 2021, and the overpaid taxes were refunded. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 34.0% of total third quarter 2012 revenues. The tax rate reduction saved the Partnership approximately $10,500 during the third quarter of 2012.

General and administrative costs incurred during the three month periods ended September 30, 2011 and 2012 decreased from $285,454 to $203,211, respectively. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. As described in Note 4 to the unaudited condensed financial statements reported in this Quarterly Report, during the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from a fixed monthly amount as prescribed in the Partnership Agreement to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships.  The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. As a result of this change the administrative overhead charged to the Partnership decreased from $224,220 during the three month period ended September 30, 2011 to $153,741 during the three month period ended September 30, 2012. In addition, salaries and wages for field personnel in the Slaughter Dean Field decreased by $32,775 due to staffing reductions. During the quarter, the Partnership incurred a non-recurring fee of approximately $10,100 with a third party vendor for assistance complying with new SEC regulations.

Nine months ended September 30, 2012 compared to the nine months ended September 30, 2011

The Partnership had net income of $626,752 for the nine month period ended September 30, 2012, compared to a net loss of $2,565 for the nine month period ended September 30, 2011. The primary causes of this change were increased sales volumes and revenues, as well as reductions in general and administrative costs.

Partnership revenues totaled $4,479,342 for the nine month period ended September 30, 2012 compared to $4,278,030 for the comparable period in 2011, an increase of 4.7% due primarily to increased oil sales prices.  Overall, oil and gas sales volumes increased during the nine month period ended September 30, 2012 compared to the nine month period ended September 30, 2011 by approximately 2.6% on an EBO basis, as a result of production from newer wells offsetting natural declines from existing wells.  While oil sales volumes dipped slightly, the average sales price for crude oil rose by 8.1%, to an average price of $88.15 per Bbl for the nine month period ended September 30, 2012 compared to an average price of $81.53 for the nine month period ended September 30, 2011.  Crude oil sales accounted for 92.1% and 89.8% of total sales revenues for the nine month periods ended September 30, 2012 and 2011, respectively.  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. The Partnership expects increased gas revenues from natural gas sales during the fourth quarter of 2012 as compared to the third quarter of 2012, because it anticipates natural gas prices will improve throughout the quarter. However, the Partnership is impacted more significantly by crude oil prices, as natural gas represented only 7.9% of total Partnership sales revenues during the nine month period ended September 30, 2012. If crude oil prices continue to trend downward, it could have a greater impact on overall fourth quarter sales revenues.

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Production tax expense totaled $227,529 for the nine month period ended September 30, 2012 compared to $282,212 for the nine month period ended September 30, 2011. During the third quarter of 2012, RELP received a production tax refund from the State of Texas totaling approximately $54,000 related to the waterflood enhancement project performed in the Slaughter Dean Field. RELP had applied for a ten year severance tax reduction (the state severance tax on oil production is reduced by 50%, from 4.6% to 2.3%) after completing the waterflood enhancement project during 2011. The State of Texas approved the severance tax reduction for the ten year period beginning period August 2011 through July 2021, and the overpaid taxes were refunded. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 33.6% of total third quarter 2012 revenues. The tax rate reduction saved the Partnership approximately $34,600 during the nine months ended September 30, 2012.

General and administrative costs incurred during the nine month periods ended September 30, 2011 and 2012 decreased from $1,087,691 to $642,487, respectively. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. As described in Note 4 to the unaudited condensed financial statements reported in this Quarterly Report, during the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from a fixed monthly amount as prescribed in the Partnership Agreement to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships.  The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. As a result of this change the administrative overhead charged to the Partnership decreased from $672,660 during the nine month period ended September 30, 2011 to $457,758 during the nine month period ended September 30, 2012. In addition, salaries and wages for field personnel in the Slaughter Dean Field decreased by $105,896 due to staffing reductions. During the quarter, the Partnership incurred a non-recurring fee of approximately $10,100 with a third party vendor for assistance complying with new SEC regulations. In addition, direct costs for technical personnel and for third party reserve reports declined by approximately $83,785 for the first nine months of 2012 compared to the same period in 2011, related primarily to time spent examining the Slaughter Dean Field and the waterflood enhancement project in 2011.

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 September 30, 2012 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

*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