UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Fiscal Year Ended December 31, 2012

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

For the Transition period from to

COMMISSION FILE NUMBER 000-53795

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

(Exact name of registrant as specified in its charter)

Texas

26-0805120

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

1901 N. Central Expressway, Suite 300, Richardson, TX 75080-3610

(Address of principal executive offices including zip code)

(972) 437-6792

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

General and Limited Partnership Interests

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o		Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

No market currently exists for the limited and general partnership interests of the registrant.

As of April 12, 2013, 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.

Documents incorporated by reference: None

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PART I

ITEM 1. BUSINESS

Introduction

Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) is a limited partnership formed under the laws of Texas on November 27, 2007. The Partnership was formed to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef Oil & Gas Partners, L.P. (“Reef”) is the managing general partner of the Partnership. Terms used in this Annual Report such as “we,” “us” or “our” refer to Reef.

The Partnership seeks to purchase working interests in oil and gas properties with both proved producing reserves and proved undeveloped reserves. On all 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.

In instances where the percentage ownership of the Partnership in a property is large enough, Reef Exploration, L.P., an affiliate of Reef (“RELP”), serves as the property’s operator. RELP currently serves as operator of the Slaughter Dean Project (as more fully described under “Property Acquisition and Development” below). The relationship among RELP and the third party working interest owners in the Slaughter Dean Project is governed by two operating agreements. One operating agreement (the “Sierra Dean Operating Agreement”) is between the Partnership, RELP, and Sierra Dean Production Company, L.P. (referred to herein as “Sierra Dean” or “Seller”). The other operating agreement (the “Davric Operating Agreement”) is between the Partnership, RELP and Davric Corporation (“Davric”). For further information on each of these operating agreements, see “Summary of Material Contracts - Operating Agreements” below.

Other partnerships managed by Reef also own working interests in some of the properties owned by this Partnership. In all cases where both the Partnership and other Reef-affiliated entities own working interests in an oil and gas property, the combined interest is not large enough for the property to be operated by RELP, and all such properties are operated by unaffiliated third parties.

Property Acquisition, Development, and Divestiture

Slaughter Dean Project

The Partnership initially purchased a working interest in a producing oil property located in the Slaughter Field in Cochran County, Texas (the “Slaughter Dean Project”) in January 2008. The Slaughter Dean Project had existing production and was purchased for purposes of a waterflood development project that was completed during 2010. The Slaughter Dean Project consists of approximately 6,700 acres and produces crude oil and natural gas from the San Andres formation at depths from 5,000 to 5,500 feet. The major portions of the Slaughter Dean Project were previously unitized for waterflood operations. During the period from 2008 through 2010, RELP, on behalf of the Partnership and other working interest owners, performed additional waterflood developmental work within the Slaughter Dean Project in an attempt to increase the ultimate recovery of crude oil and natural gas from the field. The Slaughter Dean Project is divided into two units and one non-unitized lease known as (i) the Dean Unit, (ii) the Dean “B” Unit, and (iii) the Dean “K” lease, respectively. Developmental activity was focused in the Dean “B” Unit. Several existing productive wells were converted into water injection wells, unit spacing was changed from 40 acres per well to 20 acres per well, and new production and injection wells were drilled within the new unit spacing. Some inactive water injection wells and marginal producing wells were also converted to water injection wells. New injection pumps were installed which enabled the unit to approximately triple its water injection capacity to over 6,000 barrels of water per day, in an attempt to pressurize the reservoir via water fillup. The development work was performed during 2008 and 2009, and the additional injection capacity was added during the first quarter of 2010.

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The Partnership purchased a 41% working interest from Sierra-Dean in the Slaughter Dean Project in January 2008. Under the terms of the purchase agreement (the “Slaughter Dean Purchase Agreement”), the Partnership earned additional working interest based upon the amount the Partnership spent developing and operating the Slaughter Dean Project through December 2012. In general, the Slaughter Dean Purchase Agreement required the Partnership to pay 82% of all drilling, development and repair costs (including amounts allocable to the 41% working interest initially retained by the Seller), and the Seller conveyed additional working interest to the Partnership each month as payment of its share of such costs. See “Summary of Material Contracts — Slaughter Dean Purchase Agreement” below for additional information. In a separate transaction in May 2008, the Partnership purchased an 11% working interest in the Slaughter Dean Project from Davric. See “Summary of Material Contracts - Davric Assignment” below for additional information. Davric initially retained a 7% working interest in the Slaughter Dean Project; however, during the second quarter of 2010, the Partnership assumed the 7% working interest of Davric pursuant to the Davric Operating Agreement due to non-payment by Davric of its share of costs in connection with the operations and development of the Slaughter Dean Project. As of December 31, 2012, the Partnership owned approximate working interests of 83.3%, 83.3%, and 79.7% and approximate revenue interests of 65.9%, 65.8%, and 54.0% in the Dean Unit, Dean “B” Unit, and Dean “K” Lease, respectively.

During 2008, the Partnership drilled twenty-five new developmental oil wells and three new water injection wells, and worked over and stimulated four old producing oil wells in the Slaughter Dean Project. During 2009, the Partnership drilled five additional new oil wells and two additional new water injection wells, and converted twenty-two old oil producing wells to water injection wells. The Partnership also repaired, replaced and expanded water pumping and injection facilities and capacity. During 2010, the Partnership installed an additional injection pump to increase water injection volume. Prior to the Partnership’s purchase of the Slaughter Dean Project, only the water produced with the crude oil was being injected back into the oil producing formation. Currently, approximately 5,400 barrels of water are being injected back into the oil producing formation per day. The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil. The actual results to date of the additional developmental work have not produced the desired production of additional oil. The Slaughter Dean Project was producing approximately 100 barrels of crude oil and 4,700 barrels of water per day as of December 31, 2012, compared to approximately 105 barrels of crude oil and 4,600 barrels of water per day as of December 31, 2011.

During the year ended December 31, 2010, the Slaughter Dean Project experienced periodic, small increases in production. The waterflood activities described above reduced the rate of decline in oil production. However, the waterflood activity did not increase crude oil production as desired. Although significant crude oil reserves may remain in the reservoir, the effort to increase the waterflood response was determined to be unlikely to be effective in materially increasing the recovery of those reserves, based upon the results during 2010. The Partnership re-evaluated its unproved reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean Project to determine what quantities of crude oil and natural gas reserves the Partnership could reasonably expect to recover from this reservoir under current economic and operating conditions. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean Project of $53,166,873 as of December 31, 2010.

RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) during 2011 and 2012. No further developmental activities were performed during 2011 or 2012. 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. Alternative configurations may be cost prohibitive for the Partnership to implement. RELP continues to monitor waterflood operations and continues to operate the Slaughter Dean Project without any changes. The Partnership has expended approximately $57,297,798 and $57,132,592 on the Slaughter Dean Project as of December 31, 2012 and December 31, 2011, respectively. Capital expenditures during 2011 and 2012 consist primarily of Sierra Dean’s lease operating expenses that are paid by the Partnership and capitalized as purchase price of the additional working interest earned by the Partnership.

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Azalea Acquired Properties

On January 19, 2010, RCWI, an affiliate of the Partnership, completed the acquisition of certain working interests in oil and gas properties from Azalea Properties Ltd. for a purchase price of $21,610,116 pursuant to a Purchase and Sale Agreement between RCWI and Azalea Properties Ltd. dated December 18, 2009 (the “Azalea Purchase Agreement”). The Azalea Purchase Agreement was subject to three side letter agreements regarding the post-closing acquisition of proven undeveloped properties, the post-closing resolution of properties with title defects, and the post-closing resolution of third-party consents for certain properties (collectively, the “Side Letter Agreements”).

Subsequently, RCWI entered into a purchase and sale agreement with the Partnership (the “RCWI Agreement”) dated January 19, 2010 to sell portions of the working interests acquired from Azalea Properties Ltd. to the Partnership. The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties Ltd. for a purchase price of $13,182,171 in cash subject to post-closing adjustments. 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 acreage. The acquired working interests are all minority non-operated interests. The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef. Approximately $10.7 million of the purchase price was associated with proved developed reserves. For further information on the RCWI Agreement, see “Summary of Material Contracts — RCWI Agreement” below.

On June 15, 2010, Reef Oil & Gas Income and Development Fund IV (“Income Fund IV”) paid $1,252,844 to Azalea Properties Ltd. for the post-closing settlement related to the three Side Letter Agreements. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post-closing settlement amount. The entire post-closing settlement was associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

Lett Acquired Properties

On June 23, 2010, RCWI entered into a Purchase and Sale Agreement (the “Lett Purchase Agreement”) with Lett Oil & Gas, L.P. for working interests in certain proved developed oil and gas properties owned by Lett Oil & Gas, L.P. for a purchase price of $6,000,000. 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 oil and gas property interests included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010. Revenues and expenses related to June 2010 are treated as a purchase price adjustment. The acquired working interests are all minority non-operated interests, and the Thums Long Beach Unit is operated by a third party which is not an affiliate of the Partnership or Reef. For further information on the Lett Purchase Agreement, see “Summary of Material Contracts — Lett Purchase Agreement” below.

Sales of Interests — Granite Wash Formation

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Granite Wash formation located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were initially acquired as part of the Azalea Acquired Properties, and were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved. In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled. The Partnership received a cash payment of $933,300 during December 2010 in exchange for these interests. Approximately $478,981 of the sales price was received in exchange for undeveloped acreage, with the remaining $454,319 attributed to the existing wells. The Partnership recorded no gain or loss associated with this transaction.

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Sale of Interests — Lusk Field

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were initially acquired as part of the Azalea Acquired Properties, and were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved. In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled. The Partnership received $59,455 in exchange for these interests, which was included in accounts receivable from affiliates on the balance sheet as of December 31, 2010. This amount was paid in cash to the Partnership during the first quarter of 2011. Approximately $1,800 of the sales price was received in exchange for undeveloped acreage, with the remaining $57,655 attributed to the existing wells. The Partnership recorded no gain or loss associated with this transaction.

Sales of Interests — Thums Long Beach Unit

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. These interests were initially acquired as part of the Lett Acquired Properties, and were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s 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 these transactions.

Sales of Interests — Covington Prospect

In September 2012, the Partnership sold leasehold interests related to a three well drilling program in the Covington Prospect in Ward County, Texas proposed by a third party operator, to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate. The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and 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 included 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 proposed 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.

Major Customers

The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, 2012, one marketer and one operator accounted for 34.6% and 26.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2011, one marketer and one operator accounted for 34.9% and 29.4% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2010, one marketer and one operator accounted for 39.5% and 20.8% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

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Insurance

The Partnership is a named insured under blowout, pollution, public liability and workmen’s compensation insurance policies obtained by RELP. Such insurance, however, may not be sufficient to cover all liabilities of the Partnership. Each unit held by general partners represents a joint and several liability for unforeseen events including, without limitation, blowouts, lost circulation, and stuck drill pipe that may result in unanticipated additional liability materially in excess of a general partner’s initial investment in the Partnership.

RELP has obtained various insurance policies, as described below, and intends to maintain such policies subject to its analysis of their premium costs, coverage and other factors. In the exercise of its fiduciary duty as managing general partner, Reef has obtained insurance on behalf of the Partnership to provide the Partnership with such coverage as Reef believes is sufficient to protect the investor partners against the foreseeable risks of drilling and production. Reef reviews the Partnership’s insurance coverage prior to commencing drilling operations and periodically evaluates the sufficiency of insurance. Reef has obtained and maintained, and will continue to maintain, umbrella liability insurance coverage for the Partnership equal to the lesser of at least $50,000,000 or twice the capitalization of the Partnership, and in no event will the Partnership maintain public liability insurance of less than $10,000,000. Subject to the foregoing, Reef may, in its sole discretion, increase or decrease the policy limits and types of insurance from time to time as it deems appropriate under the circumstances, which may vary materially.

Reef and RELP are the beneficiaries under each policy and pay the premiums for each policy. The Partnership is a named insured under all insurance policies carried by RELP. Insurance premiums are broken down on a well-by-well basis and billed through an inter-company charge to the Partnership, as well as other Reef-sponsored partnerships, based upon the premiums charged by the insurance carrier for the specific wells in which the Partnership owns a working interest. Should a claim arise related to a property owned by the Partnership, the Partnership will be reimbursed for any amounts payable under such insurance coverage through a credit to the inter-company account balance. The inter-company balance between RELP and the Partnership is settled on at least a quarterly basis. However, in the event of a large insurance reimbursement being payable to the Partnership, the inter-company balance would be settled earlier, within a reasonable time after receipt of the insurance proceeds.

The Partnership reimburses RELP for its share of the insurance premium. The following types and amounts of insurance have been maintained:

· Workmen’s compensation insurance in full compliance with the laws of the State of Texas, and which will be obtained for any other jurisdictions where the Partnership may conduct its business in the future;

· General liability insurance, including bodily injury liability and property damage liability insurance, with a combined single limit of $1,000,000;

· Employer’s liability insurance with a limit of not less than $1,000,000;

· Automobile public liability insurance with a limit of not less than $1,000,000 per occurrence, covering all automobile equipment;

· Energy exploration and development liability (including well control, environmental and pollution liability) insurance coverage with limits of not less than $5,000,000 for land wells and $10,000,000 for wet wells; and

· Umbrella liability insurance (excess of the General liability, Employer’s liability and Automobile liability insurance) with a limit of not less than $50,000,000.

Reef will notify all non-Reef general partners of the Partnership at least 30 days prior to any material change in the amount of the Partnership’s insurance coverage. Within this 30-day period, non-Reef general partners have the right to convert their units into units of limited partnership interest by giving Reef written notice. Non-Reef general partners will have limited liability as a limited partner for any Partnership operations conducted after their conversion date, effective upon the filing of an amendment to the Certificate of Limited Partnership of the

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Partnership. At any time during this 30-day period, upon receipt of the required written notice from the non-Reef general partner of his intent to convert, Reef will amend the partnership agreement and will file the amendment with the State of Texas prior to the effective date of the change in insurance coverage. This amendment to the partnership agreement will effectuate the conversion of the interest of the former non-Reef general partner to that of a limited partner. Effecting conversion is subject to the express requirement that the conversion will not cause a termination of the partnership for federal income tax purposes. However, even after an election of conversion, a non-Reef general partner will continue to have unlimited liability regarding partnership activities while he was a non-Reef general partner.

Competition

There are thousands of oil and natural gas companies in the United States. Competition is strong among persons and entities involved in the acquisition of producing oil and gas properties, as well as the exploration for and production of crude oil and natural gas. Reef expects the Partnership to encounter strong competition at every phase of business. The Partnership competes with entities having financial resources and staffs substantially larger than those available to it.

The national supply of natural gas is widely diversified, with no one entity controlling over 5% of supply. As a result of deregulation of the natural gas industry enacted by Congress and the Federal Energy Regulatory Commission (“FERC”), natural gas prices are generally determined by competitive market forces. Prices of crude oil, condensate and natural gas liquids are not currently regulated and are generally determined by competitive market forces.

Markets

The marketing of crude oil and natural gas produced by the Partnership is affected by a number of factors that are beyond the Partnership’s control and whose exact effect cannot be accurately predicted. These factors include:

· the amount of crude oil and natural gas imports;

· the availability, proximity and cost of adequate pipeline and other transportation facilities;

· the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind and solar power;

· the effect of United States and state regulation of production, refining, transportation and sales;

· other matters affecting the availability of a ready market, such as fluctuating supply and demand; and

· general economic conditions in the United States and around the world.

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated trade and investment barriers between the United States, Canada, and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before, FERC, as well as nondiscriminatory access requirements could further substantially increase the availability of gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from Partnership wells.

Members of the Organization of Petroleum Exporting Countries (“OPEC”) establish prices and production quotas for petroleum products from time to time with the intent of affecting the global supply of crude oil and reducing, increasing or maintaining certain price levels. Reef is unable to predict what effect, if any, such actions will have on the amount of or the prices received for crude oil produced and sold from the Partnership’s wells.

In several initiatives, FERC has required pipelines to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated to expand natural gas markets and to improve their reliability.

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Governmental Regulation

The Partnership’s operations will be affected from time to time in varying degrees by domestic and foreign political developments, and by federal and state laws and regulations.

Regulation of Oil & Gas Activities. In most areas of operations within the United States the production of crude oil and natural gas is regulated by state agencies that set allowable rates of production and otherwise control the conduct of oil and gas operations. Operators of oil and gas properties are required to have a number of permits to operate such properties, including operator permits and permits to dispose of salt water. RELP possesses all material requisite permits required by the states and other local authorities in areas where it operates properties. States also control production through regulations that establish the spacing of wells or limit the number of days in a given month a well can produce. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits such as hazardous materials certificates, which RELP has obtained.

Environmental Matters. The Partnership’s drilling and production operations are also subject to environmental protection regulations established by federal, state, and local agencies that may necessitate significant capital outlays that, in turn, would materially affect the financial position and business operations of the Partnership. These regulations, enacted to protect against waste, conserve natural resources and prevent pollution, could necessitate spending funds on environmental protection measures, rather than on drilling operations. If any penalties or prohibitions were imposed on the Partnership for violating such regulations, the Partnership’s operations could be adversely affected.

Climate Change Legislation and Greenhouse Gas Regulation. Studies in recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. Many nations have agreed to limit emissions of greenhouse gases (“GHGs”) pursuant to the United Nations Framework Convention on Climate Change, and the Kyoto Protocol. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of crude oil, natural gas, and refined petroleum products, are considered GHGs regulated by the Kyoto Protocol. Although the United States is currently not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of GHGs. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for crude oil and natural gas. On December 7, 2009, the Environmental Protection Agency (“EPA”) issued a finding that serves as the foundation under the Clean Air Act to issue rules that would result in federal GHGs regulations and emissions limits under the Clean Air Act, even without Congressional action. On September 29, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect the oil and gas exploration and production industry and the pipeline industry. The EPA’s finding, the GHG reporting rule, and the proposed rules to regulate the emissions of GHGs would result in federal regulation of carbon dioxide emissions and other GHGs, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to the oil and gas industry.

Natural Gas Transportation and Pricing. FERC regulates the rates for interstate transportation of natural gas as well as the terms for access to natural gas pipeline capacity. Pursuant to the Wellhead Decontrol Act of 1989, however, FERC may not regulate the price of natural gas. Such deregulated natural gas production may be sold at market prices determined by supply and demand, Btu content, pressure, location of wells, and other factors. Reef anticipates that all of the natural gas produced by the Partnership’s wells will be considered price-decontrolled natural gas and that the Partnership’s natural gas will be sold at fair market value. However, while sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

Proposed Regulation. Various legislative proposals are being considered in Congress and in the legislatures of various states, which, if enacted, may significantly and adversely affect the petroleum and natural gas industries. Such proposals involve, among other things, the imposition of price controls on all categories of natural gas production, the imposition of land use controls, such as prohibiting drilling activities on certain federal and state

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lands in protected areas, as well as other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals will have on the Partnership’s operations.

Employees

The Partnership has no employees, and is managed by the managing general partner, Reef. RELP employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. The Partnership reimburses RELP for technical and administrative services at cost. See “Item 11. Executive Compensation.”

Summary of Material Contracts

Operating Agreements.

The operation of the Slaughter Dean Project is governed by two operating agreements. One operating agreement, the Sierra-Dean Operating Agreement, is between RELP as operator and the Partnership and Sierra-Dean as non-operators. The other operating agreement, the Davric Operating Agreement, is between RELP as operator and the Partnership and Davric Corporation as non-operators.

The Sierra-Dean Operating Agreement and the Davric Operating Agreement are model form operating agreements based upon the American Association of Petroleum Landmen Form 610 — 1989 and contain modifications that are customary and usual for the geographic area in which the Partnership conducts operations. Additionally, the Sierra-Dean Operating Agreement and the Davric Operating Agreement both provide that RELP shall serve as operator of the Dean Unit and the Dean “B” Unit and include the accounting procedure for joint operations issued by the Council of Petroleum Accountants Societies of North America. The Sierra-Dean Operating Agreement also provides that RELP shall serves as operator of the Dean “K” Lease. Davric does not own any interest in the Dean “K” Lease.

Slaughter Dean Purchase Agreement.

The Slaughter Dean Purchase Agreement provides that the Partnership purchase from the Seller an initial 41% working interest in two waterflood units (the Dean Unit and the Dean “B” Unit) and an initial 50% working interest in the Dean “K” Lease. These properties all produce crude oil and natural gas and are located in the Slaughter Dean Field. The initial purchase price for these properties was $11,500,000, subject to certain adjustments, with a commitment and obligation of the Partnership to purchase additional working interests in the Slaughter Dean Project through its expenditures on the waterflood development of the Slaughter Dean Project. The Seller initially retained a 41% working interest in the Dean Unit and the Dean “B” Unit, and a 50% working interest in the Dean “K” Lease.

The Dean Unit, the Dean “B” Unit and the Dean “K” Lease collectively are referred to as the Slaughter Dean Project. The Slaughter Dean Project contains approximately 6,700 acres. The Partnership had an initial 41.0% working interest in each of the Dean Unit and the Dean “B” Unit and had an initial net revenue interest of 35.5% and 32.5 % in these two units, respectively. In other words, the Dean Unit and the Dean “B” Unit are subject to royalty interests and overriding royalty interests of approximately 13.5% and 20.8%, respectively. The Partnership initially owned a 50.0% working interest (with a 33.9% net revenue interest) in the Dean “K” Lease. The Dean “K” Lease accounts for approximately 5.3% of the combined value of the Slaughter Dean Project.

The Partnership has since acquired substantial additional interests in the Project pursuant to the Slaughter Dean Purchase Agreement by advancing the funds necessary to pay the Seller’s share of certain development and operating costs associated with the Slaughter Dean Project. The Partnership pays these costs on behalf of the Seller, and the Seller conveys additional working interests in the Slaughter Dean Project to the Partnership through December 2012. The acquisition of additional working interests in the Dean Unit and the Dean “B” unit is based upon the following formula:

82%		x		$11,500,000 + Partnership’s Capital Expended on Development
				$23,000,000 + Seller’s and Partnership’s Capital Expended on Development

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The above written formula gives the total amount of working interest held by the Partnership in the two largest units comprising the Slaughter Dean Project, the Dean Unit and the Dean “B” Unit. It is recalculated each month based on the Partnership’s expenditures, and the Partnership’s working interest is accordingly adjusted monthly. Thus, the Partnership’s working interest is subject to increases and the Seller’s working interest is subject to decreases through December 2012. To determine the additional working interest acquired by the Partnership in the Dean “K” Lease, the fraction is multiplied by 100%, instead of 82%. Substantially all development activity that would lead to adjustments in the working interests of the Partnership and the Seller was complete as of December 31, 2010.

Davric Assignment.

In addition to the working interests acquired from the Seller, the Partnership purchased an 11% working interest (8.7175% revenue interest) in the Dean Unit and the Dean “B” Unit from Davric for $2,963,000, effective May 1, 2008. Additionally, Davric assigned its interests in certain oil and gas leases and certain other contracts and agreements related to the Dean Unit and the Dean “B” Unit, as set forth in the exhibits to the Davric Assignment.

RCWI Agreement

On January 19, 2010, RCWI completed the acquisition of certain working interests in oil and gas properties from Azalea Properties Ltd. for a purchase price of $21,610,116 pursuant to the Azalea Purchase Agreement. The Azalea Purchase Agreement is subject to three Side Letter Agreements.

Subsequently, RCWI entered into the RCWI Agreement, dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties Ltd. to the Partnership. The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties Ltd. for a purchase price of $13,182,171 in cash subject to post-closing adjustments. 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 acreage. The acquired working interests are all minority non-operated interests. The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef. Approximately $10.7 million of the purchase price was associated with proved developed reserves.

On June 15, 2010, Income Fund IV, an affiliate of Reef, paid $1,252,844 to Azalea Properties Ltd. for the post-closing settlement related to the Side Letter Agreements. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post-closing settlement amount. The entire post-closing settlement was associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

Lett Purchase Agreement

On June 23, 2010, RCWI entered into the Lett Purchase Agreement for working interests in certain proved developed oil and gas properties owned by Lett Oil & Gas, L.P. for a purchase price of $6,000,000. The Lett Acquired Properties are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells. The entire $6,000,000 purchase price was associated with proved developed reserves. 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 oil and gas property interests included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010. Revenues and expenses related to June 2010 were treated as a purchase price adjustment.

Other Contracts

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exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnerships working interest in the Slaughter Dean Field only.

FORWARD LOOKING STATEMENTS

This Annual 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 Annual Report. Specifically, the following statements are forward-looking:

· statements regarding the Partnership’s overall strategy for acquiring additional properties;

· statements regarding the Partnership’s plans to develop the Slaughter Dean Project, including the enhancement of production of existing wells through waterflood operations;

· 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 expect 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 non-Reef general and limited investor partners (“Investor 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 factors listed in ITEM 1A. of this Annual Report captioned, “RISK FACTORS.” 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.

ITEM 1A. RISK FACTORS

Our business activities are subject to certain risks and hazards, including the risks discussed below. If any of these events should occur, it could materially and adversely affect our business, financial condition, cash flow, or results of operations. The risks below are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flow, and results of operations. Consequently, you should not consider this list to be a complete statement of all of our potential risks or uncertainties.

The waterflood development operations in the Slaughter Dean Project may fail.

Although the Slaughter Dean Project included approximately 70 wells producing or capable of producing crude oil

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at the time of the Partnership’s acquisition, the estimated plan for the development of the Slaughter Dean Project (which was adjusted from time to time depending on information learned during the implementation of the work plan) was to (i) drill approximately 30 new oil wells, (ii) convert approximately 23 of the already-producing oil wells to water injection wells to support the new, denser waterflood pattern, (iii) drill approximately 5 new water injection wells, (iv) workover or clean out approximately 5 of the already-producing wells to improve their operation, and (v) repair and enhance the pumps and water injection system to increase its capacity and resume water injection operations. During 2008, the Partnership (a) drilled 25 new oil wells, (b) drilled 3 new water injection wells, and (c) worked over 4 already-producing oil wells. During 2009, the Partnership (1) drilled 5 new oil wells, (2) converted 22 previously productive oil wells to water injection wells, (3) drilled 2 new water injection wells, and (4) worked over 1 already-producing well. During 2010, the Partnership installed an additional injection pump to increase injection volume. The Partnership also repaired, replaced, and expanded water pumping and injection facilities and capacity.

Any increase in crude oil production obtained as a result of the waterflood operations may not be sufficient to justify the costs of such operations. Indeed, it is impossible to predict with any certainty whether the waterflood operations will result in any increase in production from the existing and new wells. Although key Reef personnel have participated in large waterflood projects, Reef as an entity has never previously participated in waterflood operations on the scale of the Slaughter Dean Project. Reef has selected an experienced field management team to run the waterflood operations. This team has studied and analyzed other areas of the Slaughter Dean Field in which other field operators have successfully implemented enhanced waterflooding by reducing well spacing from 40 acres to 20 acres, drilling new producing and injection wells, and redesigning the injection pattern through conversion of previously producing wells. Based upon their study, they believed the Slaughter Dean Project could be successfully developed with the program implemented by Reef on behalf of the Partnership. However, the efforts of the field management team may not be successful, and the waterflood operations may not result in increased production. The actual results to date of the Partnership’s waterflood operations have not produced the desired production of additional oil. During 2012, Reef performed tests to determine if an alternative waterflood configuration would improve the performance of the operations. The results of this testing were inconclusive.

Oil and gas well drilling is a speculative activity involving numerous risks and substantial and uncertain costs which could adversely affect the Partnership.

Drilling oil and gas wells involves numerous risks, including the risk that no commercially productive crude oil and/or natural gas reserves will be discovered. There can be no assurance that wells drilled by the Partnership will be productive or recover all or any portion of the investment in such wells. Drilling and completion costs are substantial and uncertain, and drilling operations may be curtailed, delayed, or cancelled due to a variety of factors beyond our control, including shortages or delays in the availability of drilling rigs and crews, unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, and compliance with environmental and other governmental regulations. Our drilling activities may not be successful and, if unsuccessful, will have an adverse effect on the Partnership’s results of operations and cash flow available for distribution to the partners.

Oil and natural gas investments are risky.

Although the Partnership will not engage in any exploratory drilling, the acquisition, development and operation of oil and gas properties is not an exact science and involves a high degree of risk. The risks of acquiring and operating producing properties are generally less than those associated with the drilling of wells. Developmental drilling may result in dry holes or wells that do not produce crude oil or natural gas in sufficient quantities to make them commercially profitable to complete. The producing properties acquired by the Partnership may not produce sufficient quantities of crude oil or natural gas to enable a partner to obtain any certain projected rate of return on his or her investment, and it is possible that partners may lose money.

Furthermore, the Partnership may be subject to liability for pollution and other damages and will be subject to statutes and regulations relating to environmental matters. Although Reef will maintain, on behalf of the Partnership, insurance coverage which is normal and customary for the industry in the area and which Reef feels is adequate under the circumstances, including worker’s compensation, operating, liability, and umbrella protection, the Partnership may suffer losses due to hazards against which it cannot insure or against which Reef may elect not

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to insure. Any such uninsured losses will reduce Partnership capital and/or cash otherwise available for distributions.

Crude oil and natural gas prices are volatile, and fluctuate due to a number of factors outside of our control.

The financial condition, results of operations, and the carrying value of our oil and gas properties depend primarily upon the prices received for our crude oil and natural gas production. Crude oil and natural gas prices historically have been volatile and likely will continue to be volatile given current geopolitical conditions. Cash flow from operations is highly dependent upon the sales prices received from crude oil and natural gas production. The prices for crude oil and natural gas are subject to a variety of factors beyond our control. These factors include:

· the domestic and foreign supply of crude oil and natural gas; consumer demand for crude oil and natural gas, and market expectations regarding supply and demand;

· the ability of the members of OPEC to agree to and maintain crude oil price and production controls;

· domestic government regulations and taxes;

· the price and availability of foreign exports and alternative fuel sources;

· weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;

· political conditions in crude oil and natural gas producing regions, including the Middle East, Nigeria, and Venezuela; and

· domestic and worldwide economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, crude oil and natural gas prices do not necessarily move in tandem. Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the amount of crude oil and natural gas that can be economically produced from successful wells drilled by the Partnership, and, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas reserves, and the carrying value of the Partnership’s oil and gas properties. Approximately 82.6% of the Partnership’s estimated proved reserves at December 31, 2012 were crude oil reserves, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.

The Partnership, while not prohibited from engaging in commodity trading or hedging activities in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at December 31, 2012. Accordingly, the Partnership is at risk for the volatility in crude oil and natural gas prices, and the level of commodity prices has a significant impact upon the Partnership’s results of operations.

A global economic downturn could have a material adverse impact on our financial position, results of operations and cash flows.

The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries around the world experienced an economic downturn in 2008 and 2009 which had an adverse impact on demand and pricing for crude oil and natural gas. Another downturn similar to that experienced in 2008 and 2009 could lead to a similar negative impact on crude oil and natural gas prices or reduced demand for crude oil and natural gas that could have a significant impact on the Partnership’s operating cash flows and profitability. Declines in crude oil and natural gas prices may also impact the value of our crude oil and natural gas reserves, which could result in future impairment charges to reduce the carrying value of the Partnership’s oil and gas properties.

We cannot control activities on non-operated properties.

The Partnership has limited ability to exercise influence over and control the risks associated with operations on properties not operated by RELP. The Azalea Acquired Properties and the Lett Acquired Properties are all operated by third party operators. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements, or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. The success and timing of drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s

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· timing and amount of capital expenditures;

· expertise and financial resources;

· inclusion of other participants in drilling wells; and

· use of technology.

In addition, the Partnership could be held liable for the joint interest obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. Full development of prospects may be jeopardized in the event other working interest owners cannot pay their share of drilling and completion costs.

The Partnership may become liable for joint activities of other working interest owners.

The Partnership holds title to its interests in oil and gas properties in its own name, and it is anticipated that the Partnership will hold any additional interests in properties it may purchase in the future in its own name. Additionally, the Partnership is and will continue to be a joint working interest owner with other parties. It has not been clearly established whether joint working interest owners have several liability or joint and several liability with respect to obligations relating to the working interest. Although the operating agreements relating to properties ordinarily specify that the liabilities of joint working interest owners will be several, if the Partnership and other working interest owners are determined to have joint and several liability, the Partnership could be responsible for the obligations of these other parties relating to the entire working interest. The Partnership was advised that Davric, who is unrelated to Reef and owns a 7% working interest in the Dean Unit and the Dean “B” unit in the Slaughter Dean Project, was unable to pay $538,443 of its share of costs incurred subsequent to February 28, 2009. Pursuant to the Davric Operating Agreement, the Partnership assumed the 7% working interest of Davric and Davric is now a non-consenting working interest owner. The unpaid costs have been recorded as property additions and operating costs on the books of the Partnership, and the Partnership will retain the Davric 7% working interest until the net revenues related to this interest exceed the unpaid costs, plus penalties ranging from 300% to 450% of the amount in default.

Crude oil and natural gas reserve data are estimates based upon assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.

Securities and Exchange Commission (SEC) rules require the Partnership to present annual estimates of reserves. Reservoir engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be precisely measured, and is based upon assumptions that may vary considerably from actual results. Accordingly, reserve estimates may be subject to upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material.

You should not assume the present value of future net cash flows referred to in this Annual Report to be the current market value of our estimated crude oil and natural gas reserves. The estimated discounted future net cash flows from our proved reserves as of December 31, 2012 are based upon the 12-month un-weighted arithmetic average of the first-day-of-the-month prices and costs in effect when the estimate is made. Actual current prices, as well as future prices and costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.

The Partnership Agreement limits Reef’s liability to each partner and the Partnership and requires the Partnership to indemnify Reef against certain losses.

Reef will have no liability to the Partnership or to any partner for any loss suffered by the Partnership, and will be indemnified by the Partnership against loss sustained by it in connection with the Partnership if:

1. Reef determines in good faith that its action was in the best interest of the Partnership;

2. Reef was acting on behalf of or performing services for the Partnership; and

3. Reef’s action did not constitute negligence or misconduct by Reef.

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The production and producing life of Partnership wells is uncertain.

Production from wells will decline. It is not possible to predict the life and production of any well. The actual lives could differ from that which is anticipated. Sufficient crude oil or natural gas may not be produced for a partner to receive a profit or even to recover his initial investment. In addition, production from the Partnership’s oil and gas wells, if any, will decline over time, and does not indicate any consistent level of future production. This production decline may be rapid and irregular when compared to a property’s initial production.

Extreme weather conditions may adversely affect production operations and partner distributions.

Some oil and gas wells acquired in the Azalea acquisition are located in coastal regions of Louisiana and Texas. This area is susceptible to extreme weather conditions, especially those associated with hurricanes. In the event of a hurricane and related storm activity, such as windstorms, storm surges, floods and tornados, Partnership operations in the region may be adversely affected. The occurrence of a hurricane or other extreme weather may harm or delay the Partnership’s operations or distribution of revenues, if any.

Our dependence on third parties for the processing and transportation of crude oil and natural gas may adversely affect the Partnership’s revenues and, consequently, the distribution of net cash flows to investor partners.

We rely on third parties to process and transport crude oil and natural gas produced by the Partnership’s successful wells. In the event a third party upon whom we rely is unable to provide transportation or processing services, and another third party is unavailable to provide such services, then the Partnership may have to temporarily shut-in successful wells, and revenues to the Partnership and distributions to investor partners may be delayed.

We face strong competition within the energy industry.

The oil and gas industry is highly competitive. Competition is encountered in all aspects of Partnership operations, including the requisition of drilling and service contractors. Many of our competitors are larger, well-established companies with substantially larger operating staffs and greater capital resources than those of the Partnership, Reef and its affiliates. We may not be able to conduct our operations successfully, obtain drilling and service contractors, consummate transactions, and obtain technical, managerial and other professional personnel in this highly competitive environment. Specifically, larger competitors may be able to pay more for competent personnel than the Partnership, Reef and its affiliates. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that will be increasingly important to success. Such competitors may also be in a better position to secure drilling and oilfield services, as well as equipment, more timely or on more favorable terms. Finally, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future.

The Partnership may incur liability for liens against its subcontractors.

Although Reef will try to determine the financial condition of nonaffiliated subcontractors, if subcontractors fail to timely pay for materials and services, the properties of the Partnership could be subject to materialmen’s and workmen’s liens. In that event, the Partnership could incur excess costs in discharging the liens.

The effect of borrowing and other financing may negatively impact partnership distributions.

Net proceeds from the sale of units in the Partnership were used to acquire interests in the Slaughter Dean Project and execute the waterflood operations work plan, including drilling new oil wells within the Slaughter Dean Project and providing necessary production equipment and facilities to service such oil and gas wells. Net proceeds from the sale of units in the Partnership were also used in connection with the acquisition of the Azalea Acquired Properties in January 2010. However, the Partnership borrowed $5,000,000 from a bank in connection with the acquisition of the Lett Acquired Properties in June 2010. As of December 31, 2012, the outstanding balance of these borrowings was $1,315,000. Although there are no plans at this time to do so, certain costs of operations may also be financed through partnership borrowings and through utilization of partnership revenues obtained from

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production, the sale of producing or non-producing reserves, the sale of net profits interests or other operating or non-operating interests in properties, or other methods of financing. If these methods of financing should prove to be unavailable or insufficient to maintain the desired level of operations for the Partnership, operations could be continued through farmout arrangements with third parties (including affiliated partnerships) or the sale of net profits interests or other operated or non-operating interests in properties. This could result in the Partnership giving up a substantial interest in crude oil and natural gas reserves. If the Partnership sells net profits interests in properties, the Partnership will incur costs that it cannot recover from the holders of the net profits interests, except from future revenues, if any, relating to such properties. The effect of borrowing or other financing could be to increase funds available to the Partnership, but also could be to reduce cash available for distributions to the extent cash is used to repay borrowings, or to reduce reserves if properties are farmed out or interests in the properties are sold.

The Partnership’s insurance coverage may be inadequate.

There are numerous hazards involved in the drilling and operation of oil and gas wells, including blowouts involving possible damages to property and third parties, bodily injuries, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressure, pollution, releases of toxic gas and other environmental hazards and risks. There are also hazards involved in the transportation of crude oil and natural gas from our wells to market. Such hazards include pipeline leakage and risks associated with the spilling of crude oil transported via barge instead of pipeline, both of which could result in liabilities associated with environmental cleanup. The Partnership could suffer substantial losses as a result of any of these risks. Although the Partnership Agreement provides for the securing of such insurance as Reef deems necessary and appropriate, certain risks are uninsurable and others may be either uninsured or only partially insured because of high premium costs or other reasons. In the event the Partnership incurs uninsured losses or liabilities, the Partnership’s funds available for Partnership purposes may be substantially reduced or lost completely, and non-Reef general partners may be jointly and severally liable for such amounts.

Government regulation may adversely impact the Partnership’s profitability.

The oil and gas business is subject to extensive governmental regulation under which, among other things, rates of production from partnership wells may be fixed and the prices for natural gas produced from the Partnership wells may be limited. Governmental regulation also may limit or otherwise affect the market for the Partnership’s crude oil and natural gas production, if any, and the price that may be paid for that production. Governmental regulations relating to environmental matters could also affect the Partnership’s operations by increasing the costs of operations or by requiring the modification of operations in certain areas. State and federal governmental regulation of the oil and gas industry is in a potentially fluid situation and could change dramatically as a result of many outside factors, including a shift in the philosophy of the governmental environmental policies, continued increases in the price of crude oil and national security concerns. The nature and extent of various regulations, the nature of other political developments, and their overall effect upon the Partnership are not predictable. Investment in the Partnership involves a high degree of risk and is suitable only for investors of substantial financial means who have no need for liquidity in their investments.

Fluctuations in drilling costs over recent periods may impact the profitability of each Partnership well and the number of wells the Partnership may drill.

There has been significant volatility in recent periods in the costs associated with the drilling of oil and gas wells. Specifically, the costs of the use of drilling rigs and their personnel, steel for pipelines, mud and fuel have risen and fallen in recent periods. Future increases could result in limiting the number of wells the Partnership may drill as well as the profitability of each well once completed.

Delays in the transfer of title to the Partnership could place the Partnership at risk.

Titles to the Partnership’s interest in the leases for the Slaughter Dean Project and the Thums Long Beach Unit are held in the name of the Partnership. Under the RCWI Agreement, title to the Azalea Acquired Properties is held temporarily in the name of RCWI. When the Partnership acquires additional properties, title to those properties may be held temporarily in Reef’s name or in the name of one or more of Reef’s affiliates as nominee for the Partnership

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in order to facilitate the acquisition of properties by the Partnership and for other valid purposes. When this is the case, the Partnership runs the risk that the transfer of title could be set aside in the event of the bankruptcy of the party holding title. In this event, title to the leases and the wells would revert to the creditors or trustee, and the Partnership would either recover nothing or only the amount paid for the leases and the cost of drilling the wells. Assigning the leases to the Partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the Partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. See “ITEM 2. PROPERTIES — Title to Properties.”

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Drilling, Waterflood Development Activities and Productive Wells

The Slaughter Dean Project included approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. The initial plan for the development and expansion of the waterflood on the Slaughter Dean Project (which was adjusted from time to time depending on information learned during the implementation of the work plan) was to (i) drill approximately 30 new oil wells, (ii) convert approximately 23 of the already-producing oil wells to water injection wells to support the new, denser waterflood pattern, (iii) drill approximately 5 new water injection wells, (iv) workover or clean out approximately 5 of the already-producing wells to improve their operation, and (v) repair and enhance the pumps and water injection system to increase its capacity and resume water injection operations. During 2008, the Partnership (a) drilled 25 new oil wells, (b) drilled 3 new water injector wells, and (c) worked over four already-producing oil wells. During 2009, the Partnership (1) drilled five new oil wells, (2) converted 22 previously productive oil wells to water injection wells, (3) drilled 2 new water injection wells, and (4) worked over 1 already-producing well. During 2010, the Partnership installed an additional injection pump to increase injection volume. The Partnership has also repaired, replaced, and expanded water pumping and injection facilities and capacity.

The drilling of new water injection wells and the conversion of a number of old already-producing oil wells to water injection wells was intended to increase the productivity of the Project as a whole. The Partnership is currently injecting approximately 5,400 barrels of water per day back into the oil producing formation. The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil, thereby increasing the ultimate recovery of crude oil and natural gas in the Slaughter Dean project.

During the year ended December 31, 2010, the Slaughter Dean Project experienced periodic, small increases in production. The waterflood activities described above reduced the rate of decline in oil production. However, the waterflood activity has not increased crude oil production as desired. Although significant crude oil reserves may remain in the reservoir, the efforts to increase the waterflood response was determined to be unlikely to be effective in materially increasing the recovery of those reserves, based upon the results during 2010. The Partnership re-evaluated its unproved reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean Project to determine what quantities of crude oil and natural gas reserves the Partnership could reasonably expect to recover from this reservoir under current economic and operating conditions. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean Project of $53,166,873 as of December 31, 2010.

RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) during 2011 and 2012. No further developmental activities were performed during 2011 or 2012. 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. Alternative configurations may be cost prohibitive for the Partnership to implement. RELP continues to monitor waterflood operations and continues to operate the Slaughter Dean Project without any changes. The Partnership

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has expended approximately $57,297,798 and $57,132,592 on the Slaughter Dean Project as of December 31, 2012 and December 31, 2011, respectively. Capital expenditures during 2011 and 2012 consist primarily of Sierra Dean’s lease operating expenses that are paid by the Partnership and capitalized as purchase price of the additional working interest earned by the Partnership.

The Partnership also owns non-operated minority working interests in the Azalea Acquired Properties and the Lett Acquired Properties, which consist of over 400 properties and more than 1,400 wells located in twelve states, which were acquired in two separate purchases completed during 2010. The largest property purchased in the Azalea Acquired Properties is an interest in the Thums Long Beach Unit, which is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. Thums Long Beach has produced more than 930 million barrels of oil equivalent (natural gas production is converted to equivalent barrels of oil at a rate of 6 MCF to 1 barrel of oil) from the Wilmington Field, and it is estimated it has in excess of 200 million barrels of oil equivalent remaining to be produced using current costs and pricing as of December 31, 2012. Thums Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell. The only property acquired in the Lett Acquired Properties was an additional interest in the Thums Long Beach Unit.

The Azalea Acquired Properties included interests in undrilled infill and offset acreage. During 2010, the Partnership, in two separate transactions, sold its interests in certain oil and gas properties located in Wheeler County, Texas, in Roger Mills County, Oklahoma, and in Lea County, New Mexico to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were sold primarily due to the intended drilling of new wells on the acreage involved that were considered to be exploratory wells. The Partnership Agreement states that the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in fourteen existing wells, as well as the undeveloped acreage on which the exploratory wells were to be drilled. The Partnership received $992,755 in exchange for these interests. Approximately $480,781 of the sales price was received in exchange for undeveloped acreage, with the remaining $511,974 attributed to the existing wells. At December 31, 2010, $59,455 of this amount was included in accounts receivable from affiliates on the balance sheet. This amount was received by the Partnership during the first quarter of 2011. 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. These interests were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s 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 in the Covington Prospect in Ward County, Texas proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate. The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and 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 included 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 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.

The Partnership does not expect to purchase interests in any additional properties. 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 the Azalea Acquired Properties, and agrees to participate or declines to participate in such

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additional drilling based upon its evaluations of such proposals. Should the Partnership receive proposals for new wells that are classified as exploratory wells, the Partnership may sell the acreage, along with any currently productive wells on the lease, to other Partnerships affiliated with Reef and RELP.

Proved Crude Oil and Natural Gas Reserves

Estimates of the Partnership’s proved reserves 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. All of the Partnership’s reserves are located in the United States.

Proved reserves do not include any additional reserves associated with the Slaughter Dean Project. The costs associated with the developmental project and estimated additional reserves associated with the Slaughter Dean Project are classified as unproved prior to achieving an initial response to the developmental work. At December 31, 2010, based upon the lack of response to the developmental work, the Partnership recognized impairment of unproved properties totaling $53,166,873 related to the Slaughter Dean Project. Proved reserves do include the estimated reserves expected to be produced from the Slaughter Dean Field using current prices and costs.

The estimated net proved crude oil and natural gas reserves at December 31, 2012, 2011, and 2010 are summarized below. The estimated 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.

	Oil (BBL)	Gas (MCF)
Net proved reserves as of December 31, 2010	838,200	1,217,840
Net proved reserves as of December 31, 2011	679,860	1,172,750
Net proved reserves as of December 31, 2012	765,790	970,760

The standardized measure of discounted future net cash flows as of December 31, 2012, 2011, and 2010 is computed by applying the 12-month average beginning-of-month price for the year, costs, and legislated tax rates and a discount factor of 10% to net proved reserves. The standardized measure of discounted future net cash flows does not purport to present the fair value of our crude oil and natural gas reserves.

Standardized measure of discounted future net cash flows as of December 31, 2010	$	14,318,440
Standardized measure of discounted future net cash flows as of December 31, 2011	$	16,035,470
Standardized measure of discounted future net cash flows as of December 31, 2012	$	16,721,530

During the years ended December 31, 2012 and 2011, the Partnership recorded no property impairment costs of proved properties. During the year ended December 31, 2010, the Partnership recorded property impairment costs of proved properties of $4,777,151 as a result of the net capitalized costs of proved oil and gas properties exceeding the sum of estimated future net revenues from proved reserves, using the methodologies described above, as well as property impairment expense of unproved properties totaling $53,166,873 based on its evaluation of the data obtained from the waterflood operations of the Slaughter Dean Project.

Qualifications of Technical Persons and Internal Controls Over the Reserves Estimation Process

The Partnership used an independent petroleum consulting company, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2012, 2011, and 2010 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2012, 2011 and 2010. The technical personnel responsible for preparing the reserve estimates at FGA meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. FGA is an independent firm

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of petroleum engineers and geologists. They do not own an interest in any of our properties, and are not employed on a contingent fee basis. FGA’s report was developed utilizing state reporting records and published production data purchased from third parties, and data provided by Reef. Their reserve summary, which contains further discussions of the reserve estimates and evaluations, as well as the qualifications of FGA’s technical personnel responsible for overseeing their estimates and evaluations, is included as Exhibit 99.1 to this Annual Report.

Reef’s policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate oil and gas reserve quantities and present values in compliance with SEC regulations and US Generally Accepted Accounting Principles (“GAAP”).

Reef maintains a staff of technical personnel who are well versed in the engineering evaluation computer programs and technology used and who provide well and production data to our independent petroleum engineering firm, FGA. Our accounting department accumulates historical production and pricing data and lease operating expenses for our wells, as well as the percentage interest owned by the Partnership, which is reviewed by our technical staff. Reserve estimates are prepared by FGA. Our technical staff and members of our accounting department meet regularly with FGA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. Jerald Sluder, Senior Reservoir Engineer for RELP, is primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Sluder has a B.S. in Petroleum Engineering, is a Registered Professional Engineer in the State of Texas and has over eighteen years of industry experience in oil and gas operations. Mr. Sluder is an active member of the Society of Petroleum Engineers and of the Petroleum Engineers Club of Dallas. Any significant reserve changes are approved by Mr. Daniel C. Sibley, Chief Financial Officer and General Counsel of RELP, and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

Title to Properties

Title to the Partnership’s interest in the leases for the Slaughter Dean Project, the Thums Long Beach Unit, and certain Azalea Acquired Properties is held in the name of the Partnership. Under the RCWI Agreement, title to properties is temporarily held in the name of RCWI. Upon acquiring properties, title to properties may be held temporarily in Reef’s name or in the name of one or more of Reef’s affiliates as nominee for the Partnership in order to facilitate the acquisition of properties by the Partnership and for other valid purposes. Otherwise, record title to the Partnership properties will be held in the name of the Partnership.

The Partnership believes that the title to its oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to exceptions which, in the opinion of the Partnership, will not be so material as to detract substantially from the use or value of such properties. The Partnership’s properties are subject, in one degree or another, to one or more of the following: royalties and other burdens created by the Partnership or its predecessors in title; a variety of contractual obligations arising under operating agreements, production sales contracts and other agreements that may affect the properties or their titles; liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and commoditization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect the Partnership’s rights to production revenues, they will be taken into account in calculating the Partnership’s new revenue interests and in estimating the quantity and value of the Partnership’s reserves. The Partnership believes that the burdens and obligations affecting its properties will be conventional in the industry for properties of their kind.

ITEM 3. LEGAL PROCEEDINGS

There are no material legal proceedings pending, on appeal or concluded to which the Partnership is a party, or to which any of its assets is subject.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2012, the Partnership had one managing general partner, 811 non-Reef general partners, and 665 non-Reef limited partners. Reef holds a total of 8.9697 general partner units, and the non-Reef partners hold 490.9827 general partner units and 397.0172 limited partner units. No established trading market exists for the units.

Cash which, in the sole judgment of the managing general partner, is not required to meet the Partnership’s obligations is available for distribution to the partners at least quarterly in accordance with the Partnership Agreement. The Partnership has made cash distributions to the partners of interest income and crude oil and natural gas sales revenues, less operating and general and administrative costs since January 2008. The Partnership’s credit agreement contains certain restrictions on distributions, including the absence of default as defined by the credit agreement, the maintenance of a minimum cash balance, and a maximum amount to be distributed based on certain other calculations described in the credit agreement. Cash distributions paid during 2012, 2011, and 2010 were $655,321, $867,371, and $1,028,526, respectively.

Investor limited partner interests are transferable, subject to certain restrictions contained in the Partnership Agreement; however, no assignee of a unit in the Partnership can become a substituted partner without the written consent of both the transferor and Reef.

Use of Proceeds

Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, with a maximum offering amount of $90,000,000 (900 units). Reef Securities, Inc., an affiliate of Reef, served as the dealer manager for the private placement. An amount equal to 15% of the proceeds realized from the sale of interests to investors was paid to Reef as a management fee. A percentage of the management fee (8.5% of the total amount raised by the Partnership) was then used by Reef to pay sales commissions and marketing fees. The remaining 85% of the proceeds has been expended on the purchase of the Slaughter Dean Project, the Azalea Acquired Properties, the Lett Acquired Properties, the waterflood development project at Slaughter Dean and drilling of developmental wells upon acreage purchased in connection with the Azalea Acquired Properties, and payment of additional fees owed to Reef as a result of such activities. On June 12, 2008, the offering of general and limited partnership interests was closed. A total of $88,648,094 was raised by the Partnership, 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, of which $48,984,933 were sold to accredited investors as general partner interests and $39,663,161 were sold to accredited investors as limited partnership interests. As managing general partner, Reef contributed $762,425 (approximately one percent (1%) of the total contributions of the non-Reef general partners and limited partners) to the Partnership in exchange for 8.9697 units of general partner interest, resulting in a total capitalization of the Partnership of $89,410,519 before organization and offering costs.

All units except those purchased by Reef paid a 15% ($13,320,000, less $151,906 of unpaid net asset values) management fee to Reef to pay for Partnership organization and offering costs, including sales commissions. These costs totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership oil and gas operations. As of December 31, 2012, the Partnership had expended $57,297,798 on acquisition and development of the Slaughter Dean Project, $15,135,254 the acquisition and development of the Azalea Acquired Properties, and $6,573,131 on the acquisition and development of the Lett Acquired Properties, prior to sales of the Partnership’s interests or portions of its interests in certain properties during 2011 and 2012. The Partnership has no current plans to purchase additional oil and gas properties.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data. The selected financial data presented below has been derived from the audited financial statements of the Partnership.

	As of and For the Years Ended December 31,
	2012			2011			2010			2009			2008

Revenue	$	5,830,997		$	6,048,932		$	5,599,090		$	1,655,812		$	2,012,489
Interest income	—			—			3,490			140,471			706,243
Miscellaneous income	69			—			—			—			—
Costs and expenses	(5,045,066		)	(5,786,568		)	(65,305,926		)	(3,343,360		)	(1,781,499		)
Net income (loss)	786,000			88,107			(59,839,904		)	(1,547,077		)	937,233

Allocation of net income (loss):
Managing general partner	208,709			112,569			(588,353		)	(70,841		)	128,050
General partner	319,189			(13,525		)	(32,760,687		)	(816,223		)	447,404
Limited partner	258,102			(10,937		)	(26,490,864		)	(660,013		)	361,779
Net income (loss) per managing partner unit	23,268.23			12,549.94			(65,593.41		)	(7,897.79		)	14,275.84
Net income (loss) per general partner unit	650.10			(27.55		)	(66,724.73		)	(1,662.43		)	911.25
Net income (loss) per limited partner unit	650.10			(27.55		)	(66,724.73		)	(1,662.43		)	911.25

Total assets	15,737,217			15,522,756			18,362,120			74,855,409			79,860,893
Long-term liabilities	2,366,899			3,240,115			5,653,946			248,912			230,472
Distributions to managing general partner	72,085			107,464			101,085			49,050			195,938
Distributions to general and limited partners	583,236			759,907			927,441			362,131			1,595,357
Distributions per general partner unit	656.80			855.75			1,044.42			407.81			1,796.57
Distributions per limited partner unit	656.80			855.75			1,044.42			407.81			1,796.57
Distributions per managing general partner unit	8,036.50			11,980.78			11,269.61			5,468.41			21,844.43

Operating Data
Annual sales volume:
Gas (MCF)	138,956			127,039			190,208			7,204			21,466
Oil (BBL)	61,718			62,255			66,352			33,235			23,060

Average sales price:
Gas (per MCF)	$	3.40		$	4.70		$	4.66		$	1.49		$	2.94
Oil (per BBL)	$	86.82		$	87.58		$	71.04		$	49.50		$	84.53

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion will assist you in understanding the Partnership’s financial position, liquidity, and results of operations. The information should be read in conjunction with the audited financial statements and notes to financial statements contained herein. The discussion contains historical and forward-looking information.

For a discussion of risk factors that could impact the Partnership’s financial results, please see Item 1A of this Annual Report.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that can affect the reporting of assets, liabilities, equity, revenues, and expenses. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We are also required to select among alternative acceptable accounting policies. See Note 3 to the financial statements for a complete list of significant accounting policies.

Oil and Gas Properties

The Partnership follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method, we perform 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 statement 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 years ended December 31, 2012 and 2011, the Partnership recognized no property impairment expense of proved properties. During the year ended December 31, 2010, the Partnership recognized property impairment expense of proved properties totaling $4,777,151.

Unproved property consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea Acquired Properties. 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 by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the year ended December 31, 2010, the Partnership recognized property impairment expense of unproved properties totaling $53,166,873 related to the Slaughter Dean Project. During the years ended December 31, 2012 and 2011, the Partnership recognized no property impairment expense of unproved properties.

The estimate of proved crude oil and natural gas reserves used to determine property impairment expense, and also utilized in the Partnership’s disclosures of supplemental information regarding oil and gas producing activities, including the standardized measure of discounted cash flows, was prepared by an independent petroleum engineer at December 31, 2012, 2011 and 2010, utilizing prices and costs as promulgated by the SEC. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and is based upon assumptions that may vary considerably from actual results.

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Accordingly, reserve estimates may be subject to upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material.

Asset retirement costs and liabilities associated with future site restoration and abandonment of long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the net asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

During the year ended December 31, 2010, the Partnership recognized $668,800 of asset retirement obligations and additional capitalized cost in connection with properties acquired by the Partnership and successful wells drilled by the Partnership.

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 a lease operating expense on the accompanying statement of operations. As a result of these plugging and abandonment operations, the Partnership determined during the quarter that its estimated liability for the Slaughter Dean Field (approximately 145 wells) was understated, and, in that regard, the Partnership increased the basis of the Slaughter Dean Field wells by $860,878 and recorded additional asset retirement obligation of this amount as a change in estimate. During the year ended December 31, 2011, the Partnership also recognized an additional $13,008 of asset retirement obligations and additional capitalized cost in connection with successful wells drilled by the Partnership.

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 on the accompanying statement of operations. 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. During the year ended December 31, 2012, the Partnership also recognized an additional $446,189 of asset retirement obligations and additional capitalized cost in connection with successful wells drilled by the Partnership and revisions related to existing wells.

Recognition of Revenue

The Partnership has entered into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenue is recognized based upon the metered volumes delivered to those purchasers each month. Any significant over or under balanced gas positions are disclosed in the financial statements. As of December 31, 2012, 2011 and 2010, the Partnership had no material gas imbalance positions.

Overview

Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership. The primary objectives of the Partnership are to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef 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.

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The Partnership owns interests in over 1,500 wells located in twelve states, including the Slaughter Dean Project, the Azalea Acquired Properties, and the Lett Acquired Properties. 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 Project. This relationship with the Partnership is governed by two operating agreements. One operating agreement (the “Sierra-Dean Operating Agreement” is between the Partnership, RELP and Sierra Dean. The other operating agreement is between the Partnership, RELP, and Davric (the “Davric Operating Agreement”). All of the Azalea Acquired Properties and Lett Acquired Properties are operated by third party operators not affiliated with Reef or any of Reef’s affiliates.

During the second quarter of 2010, the Partnership was advised that Davric, who is unrelated to Reef and owns a 7% working interest in the Dean Unit and the Dean “B” unit, was unable to pay $538,443 of its share of costs incurred subsequent to February 28, 2009. Pursuant to the Davric Operating Agreement, the Partnership assumed the 7% working interest of Davric and Davric is now a non-consenting working interest owner. The unpaid costs were recorded as property additions and operating costs on the books of the Partnership, and the Partnership will retain the Davric 7% working interest until the net revenues related to this interest exceed the unpaid costs, plus penalties ranging from 300% to 450% of the amount in default.

The Partnership has borrowed funds from a bank in connection with the purchase of the Lett Acquired Properties, and is subject to the interest rate risk inherent in borrowing activities. The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. See “Item 7A — Quantitative and Qualitative Disclosure About Market Risk.”

Liquidity and Capital Resources

Capital Contributions

The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef, 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. 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 December 31, 2012, the Partnership had expended $57,297,798 on acquisition and development of the Slaughter Dean Project, $15,135,254 on the acquisition and development of the Azalea Acquired Properties, and $6,573,131 on the acquisition and development of the Lett Acquired Properties, 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.

Credit Agreement

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 oil and gas properties purchased from Lett by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described above. 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 December 31, 2012, the interest rate was 5.0% per annum. 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 Lett Purchase Agreement described in the overview above. 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.

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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. 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.

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 on the accompanying balance sheet 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”), 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, beginning August 1, 2011, the borrowing base was reduced by $30,000 per month. These reductions will continue through the end of the term of the Credit Agreement. As such, the Partnership has recognized $360,000 of the outstanding note payable as a current liability as of December 31, 2011 on its balance sheet. 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 on the balance sheet 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 December 31, 2012, the outstanding balance due TCB was equal to $1,315,000. The Partnership has recognized the entire $1,315,000 as a current liability as of December 31, 2012 due to the June 30, 2013 expiration of the Credit Agreement. There is additional availability of $90,000 under the borrowing base as of December 31, 2012. 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.

The Credit Agreement contains various covenants, including among others restrictions on distributions and liens, incurring other indebtedness, and the maintenance of a certain current ratio and interest coverage ratio. At December 31, 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 has been obtained.

Please see Item 1A of this Annual Report for a list of risk factors that could impact the Partnership.

Capital Expenditures

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of wells as of December 31, 2012:

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	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs

Purchase Existing Wells	$	35,471,836	$	—	$	—	$	35,471,836

New Wells
Producing Wells	33,682		29,479,230		—		29,512,912
Waterflood Injector Wells	—		5,149,620		—		5,149,620
Facilities	—		1,795,397		—		1,795,397

Existing Wells	—		—		7,076,418		7,076,418

	$	35,505,518	$	36,424,247	$	7,076,418	$	79,006,183

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of December 31, 2011:

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs

Purchase Existing Wells	$	35,366,028	$	—	$	—	$	35,366,028

New Wells
Producing Wells	29,233		28,651,610		—		28,680,843
Waterflood Injector Wells	—		5,149,620		—		5,149,620
Facilities	—		1,795,397		—		1,795,397

Existing Wells	—		—		6,920,278		6,920,278

	$	35,395,261	$	35,596,627	$	6,920,278	$	77,912,166

The Partnership has expended approximately $57,297,798 (included in the expenditures shown in the table above) on the Slaughter Dean Project as of December 31, 2012. 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.

At December 31, 2012 and 2011, unproved property on the Partnership balance sheet consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea Acquired Properties. The Partnership acquired $2,486,463 of unproved properties during the year ended December 31, 2010 related to the Azalea Acquired Properties. The Partnership sold portions of this unproved property in December 2010 due to intended or in-process exploratory drilling activities, and sold portions of this unproved property in September 2012 because drilling costs of the proposed wells would have necessitated the Partnership foregoing distributions to partners for several months in order to fund the proposed drilling project. In addition, the Partnership transfers portions of unproved properties to proved properties as the related wells from the unproved properties are drilled by the various operators of the Azalea Acquired Properties.

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2012:

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	Slaughter Dean Project		Azalea Acquired Properties			Total Costs
Beginning balance	$	—	$	1,708,425		$	1,708,425
Transfers to proved properties	—		(1,172,792		)	(1,172,792		)
Sales of unproved properties	—		(11,276		)	(11,276		)
Ending balance	$	—	524,357			524,357

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2011:

	Slaughter Dean Project		Azalea Acquired Properties			Total Costs
Beginning balance	$	—	$	1,969,433		$	1,969,433
Transfers to proved properties	—		(261,008		)	(261,008		)
Ending balance	$	—	$	1,708,425		$	1,708,425

The Partnership had negative working capital of $131,644 at December 31, 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, which have been 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

Year Ended December 31, 2012 compared to Year Ended December 31, 2011

During the year ended December 31, 2012, the Partnership earned net income totaling $786,000 compared to net income of $88,107 for the year ended December 31, 2011. Decreased general and administrative costs and interest expense were the primary causes of this change.

Partnership revenues totaled $5,830,997 for the year ended December 31, 2012 compared to $6,048,932 for the comparable period in 2011, a decrease of 3.6% due primarily to decreases in oil and gas sales prices. Overall, oil and gas sales volumes increased during the year ended December 31, 2012 compared to the year ended December 31, 2011 by approximately 1.7% on an equivalent barrel of oil (“EBO”) basis, as a result of production from newer wells offsetting natural declines from existing wells. The average sales price for crude oil decreased by 0.9%, to an average price of $86.82 per Bbl for the year ended December 31, 2012 compared to an average price of $87.58 for the year ended December 31, 2011, and the average sales price for natural gas decreased by 27.7%, to an average price of $3.40 per MCF for the year ended December 31, 2012 compared to an average price of $4.70 for the year ended December 31, 2011. 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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Production tax expense totaled $314,377 for the year ended December 31, 2012 compared to $394,160 for the year ended December 31, 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 32.9% of total 2012 revenues. The tax rate reduction saved the Partnership approximately $43,260 during the year ended December 31, 2012.

General and administrative costs incurred during the years ended December 31, 2011 and 2012 decreased from $1,382,040 to $776,523, respectively. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. As described in Note 5 to the audited financial statements reported in this Annual 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 $896,880 during the year ended December 31, 2011 to $567,424 during the year ended December 31, 2012. In addition, salaries and wages for field personnel in the Slaughter Dean Field decreased by $124,000 due to staffing reductions. Finally, direct costs for technical personnel and for third party reserve reports declined by approximately $99,000 for the year ended December 31, 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.

Total other income and expense for the years ended December 31, 2012 and 2011 decreased from expense of $174,257 in 2011 to expense of $105,339 in 2012. Interest expense decreased from $160,720 during the year ended December 31, 2011 to $80,632 during the year ended December 31, 2012 due to the Partnership’s payment of principal on its note payable.

Year Ended December 31, 2011 compared to Year Ended December 31, 2010

The Partnership had net income of $88,107 for the year ended December 31, 2011, compared to a net loss of $59,839,904 for the year ended December 31, 2010. The primary causes of this change were reductions in property impairment, depreciation, depletion and amortization, and in general and administrative costs as discussed below.

The Partnership recognized property impairment expense of $57,944,024 during the year ended December 31, 2010 compared to no impairment expense during the year ended December 31, 2011. The Partnership recorded impairment expense of proved properties totaling $4,777,151 during 2010, primarily related to the Azalea Acquired Properties and the Lett Acquired Properties, for which the quarterly ceiling test is calculated 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% for the entire life of these very long-lived properties, as opposed to using the prices in effect at the time of the transactions. No additional impairment related to the Azalea Acquired Properties and the Lett Acquired Properties was necessary during 2011, as higher oil prices caused an increase in the discounted present value of the Partnership’s estimated future net cash flows from its reserves.

The Partnership also recorded impairment expense of unproved properties totaling $53,166,873 related to the Slaughter Dean Project during 2010. Although significant crude oil and natural gas reserves may remain in the reservoir, the effort to increase the waterflood response was determined to be unlikely to be effective in materially increasing the recovery of those reserves, based upon results during 2010 subsequent to the completion of the development project. The Partnership re-evaluated its unproved reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean Project to determine what quantities of crude oil and natural gas reserves the Partnership could reasonably expect to recover

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from this reservoir under current economic and operating conditions. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean Project of $53,166,873 as of December 31, 2010.

Depreciation, depletion and amortization decreased from $1,933,948 for the year ended December 31, 2010 to $1,128,514 for the year ended December 31, 2011. This decrease resulted from the lower proved property depletable basis between the two periods resulting from the proved property impairment taken during 2010, from selling a portion of the Thums Long beach Unit to Reef Oil & Gas 2010-A Income Fund during the first and second quarters of 2011, and from rising oil prices. In periods of rising prices, the reserves that can be economically produced from a given well generally increase, which results in a lower depletion rate.

General and administrative costs incurred during the years ended December 31, 2011 and 2010 decreased from $2,610,680 in 2010 to $1,382,040 in 2011. This decrease is primarily due to the expensing of acquisition costs totaling approximately $791,100 related to the Azalea Acquired Properties and the Lett Acquired Properties that were incurred during 2010. These two acquisitions also resulted in higher legal, audit, and professional fees during the year ended December 31, 2010.

Partnership revenues totaled $6,048,932 for the year ended December 31, 2011 compared to $5,599,090 for the comparable period in 2010. Sales volumes decreased by approximately 15.5% during the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily due to natural declines in production from the Partnership’s Slaughter Dean Project and Azalea Acquired Properties, and declines resulting from the sale of a portion of the Thums Long Beach Unit. Because the sales prices for crude oil and natural gas rose by 24.4%, and 0.9%, respectively during the year ended December 31, 2011 compared to the year ended December 31, 2010, sales revenues increased overall by $449,838, or 8.0% on a comparative basis. 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 increased from $2,369,144 for the year ended December 31, 2010 to $2,803,824 for the year ended December 31, 2011. The increase relates to higher, workover, overhead, and labor expenses on the Slaughter Dean Field during 2011, as well as increased expenses on the Lett Acquired Properties which were not purchased by the Partnership until June 2010.

Total other income and expense for the years ended December 31, 2011 and 2010 increased from expense of $133,068 in 2010 to expense of $174,257 in 2011. On June 30, 2010, the Partnership borrowed $5,000,000 in connection with the purchase of the Lett Acquired Properties. During 2011, the Partnership incurred interest expense of $160,720 related to its borrowings described in Note 4 to the financial statements, compared to $128,472 of interest expense during 2010.

Off-Balance Sheet Arrangements

The Partnership does not participate in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structure finance or special purpose entities (SPEs), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2012, 2011 and 2010, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.

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Contractual Obligations Table

	Payment due by period
Contractual obligations	Total		Less than 1 Year		1-3 Years	3-5 years	More than 5 Years
Consulting agreement *	—		—		—	—	—
Credit Agreement	$	1,315,000	$	1,315,000	—	—	—
Interest related to Credit Agreement**	$	31,000	$	31,000	—	—	—

* In September 2006, the Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN Associates whereby the Partnership agreed to assign a one percent (1%) overriding royalty interest, proportionately reduced to the Partnership’s working interest, to William R. Dixon in exchange for Dixon’s agreement to “review and evaluate exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnership’s working interest in the Slaughter Dean Field only. The amounts payable to William R. Dixon under the aforementioned agreement are not fixed and determinable amounts, and will vary based upon sales revenues from the Slaughter Dean Project. During the years ended December 31, 2012, 2011, and 2010, William R. Dixon received $23,819, $21,914, and $18,828, respectively, related to this overriding royalty interest.

** Interest expense assumes the balance of the Credit Agreement at the end of the period and the rate in effect as of December 31, 2012.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk

The Partnership Agreement allows borrowings from banks or other financial sources of up to 30% of the aggregate capital contributions to the Partnership with the consent of the Investor Partners. At December 31, 2012, the Partnership had $1,315,000 of outstanding debt under the Credit Agreement. Interest is calculated under the terms of the agreement based on 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. A 1.0% increase in interest rates during the year ended December 31, 2012 would have increased interest expense by approximately $15,100. The Partnership does not currently intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.

Commodity Price Risk

As of December 31, 2012, the Partnership does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes. 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.

Assuming the production levels the Partnership attained during the year ended December 31, 2012, a 10% change in the price received for crude oil would have had an approximate $536,100 impact on the Partnership’s oil revenues, and a 10% change in the price received for the natural gas would have had an approximate $46,800 impact on the Partnership’s natural gas revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The report of our independent registered public accounting firm, and the Partnership’s financial statements, related notes, and supplementary data are presented beginning on page F-1.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. 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 Annual 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 and accounting officer of the Partnership’s managing general partner, Reef Oil & Gas Partners, L.P., evaluated the effectiveness of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report. As described below, a material weakness was identified in the Partnership’s internal control over financial reporting relating to calculating and reviewing the accuracy of the asset retirement obligation accretion. As a result of that material weakness, the principal executive officer and principal financial and accounting officer of our managing general partner have concluded that the Partnership’s disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2012.

In light of the material weakness described below, which was identified in early 2013 while working on the asset retirement obligation accretion calculation for the year ended December 31, 2012, the managing general partner of the Partnership implemented revised procedures to ensure that the Partnership’s financial statements for the year ended December 31, 2012 were prepared in accordance with GAAP. As a result of the implementation of such revised procedures, the Partnership’s management has concluded that the Partnership’s financial statements included in this Form 10-K present fairly, in all material respects, the Partnership’s financial position, results of operations and cash flows for the periods presented are in conformity with accounting principles generally accepted in the United States.

Management Report on Internal Control Over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation under the framework in Internal Control — Integrated Framework, management of the Partnership concluded, based upon the material weakness described below, that the Partnership’s internal control over financial reporting was not effective as of December 31, 2012.

A material weakness in internal control over financial reporting is a deficiency or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a partnership’s annual or interim financial statements will not be prevented or detected on a timely basis. We have concluded that the Partnership did not maintain effective controls over calculating and reviewing the accuracy of the asset retirement obligation accretion calculation. This material weakness resulted in a material misstatement which overstated the accretion of asset retirement obligation, a non-cash adjustment. This material misstatement was detected and corrected prior to the issuance of the Partnership’s financial statements for the year ended December 31, 2012, and the net income (loss) as reported in this annual report on Form 10-K reflects these corrections. To address this material weakness, the Partnership has revised its procedures related to the calculation of accretion to ensure the correct methodology, as identified through management’s evaluation, is applied.

This annual report does not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this annual report.

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The Partnership has no directors or executive officers. Its managing general partner is Reef Oil & Gas Partners, L.P.

Reef Oil & Gas Partners, L.P. and Reef Exploration, L.P.

The Manager, officers and key personnel of the managing general partner, their ages, current positions with the managing general partner and/or RELP, and certain additional information are set forth below.

Name	Age	Positions and Offices Held
Michael J. Mauceli	56	Manager of Reef Oil & Gas Partners GP, LLC; Chief Executive Officer of RELP
Daniel C. Sibley	61	Chief Financial Officer and General Counsel of RELP
David M. Tierney	60	Chief Financial Reporting Officer and Treasurer of RELP

Michael J. Mauceli is the Manager and a member of Reef Oil & Gas Partners, GP, LLC, which is the general partner of Reef, as well as the Chief Executive Officer of RELP. Mr. Mauceli has been the principal executive officer of Reef since its formation in February 1999. He has served in this position with RELP since January 2006 and has served in this position with its predecessor entity, OREI, Inc. (“OREI”) since 1987. Mr. Mauceli attended the University of Mississippi where he majored in business management and marketing as well as the University of Houston where he received his Commercial Real Estate License. He entered the oil and natural gas business in 1976 when he joined Tenneco Oil & Gas Company. Mr. Mauceli moved to Dallas in 1979, where he was independently employed by several exploration and development firms in planning exploration and marketing feasibility of privately sponsored drilling programs.

Daniel C. Sibley became Chief Financial Officer of RELP in March 2010 and General Counsel of RELP in January 2009. He previously served as Chief Financial Officer of Reef from December 1999 until his appointment to General Counsel of RELP. He also served as Chief Financial Officer for RELP from January 2006 until his appointment to General Counsel of RELP, and had served in this same position with RELP’s predecessor entity, OREI, since 1998. Mr. Sibley was employed as a Certified Public Accountant with Grant Thornton from 1977 to 1980. From 1980 to 1994, he was involved in the private practice of law. He received a B.B.A. in accounting from the University of North Texas in 1973, a law degree (J.D.) from the University of Texas in 1977, and a Master of Laws-Taxation degree (Ll.M) from Southern Methodist University in 1984. Mr. Sibley became a certified public accountant in 1977, but no longer maintains that license. He is an active member of the Texas Bar Association.

David M. Tierney, the Chief Financial Reporting Officer and Treasurer of RELP, has been employed by RELP since January 2006 and was previously with its predecessor entity, OREI, Inc., since March 2001. Mr. Tierney became Chief Financial Reporting Officer of RELP in March 2010 and Treasurer of RELP in May 2009. Prior to that, Mr. Tierney served as Chief Accounting Officer — Public Partnerships of RELP starting in July 2008. From 2001 to 2008, Mr. Tierney was the Controller of the Reef Global Energy Ventures and Reef Global Energy Ventures II partnerships. Mr. Tierney received a Bachelor’s degree from Davidson College in 1974, a Masters of Business Administration from Tulane University in 1976, and is a Texas Certified Public Accountant. Mr. Tierney has worked in public accounting, and has worked in the oil and gas industry since 1979. From 1992 through 2000 he served as controller/treasurer of an independent oil and gas exploration company.

Audit Committee and Nominating Committee

Because the Partnership has no directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

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Code of Ethics

Because the Partnership has no employees, it does not have a code of ethics. Employees of the Partnership’s managing general partner, Reef, must comply with Reef’s Code of Ethics, a copy of which will be provided to Investor Partners, without charge, upon request made to Reef Oil & Gas Partners, L.P., 1901 N. Central Expressway, Suite 300, Richardson, Texas 75080, Attention: Daniel C. Sibley.

ITEM 11. EXECUTIVE COMPENSATION

The following table summarizes the items of compensation to be received by Reef and its affiliates from the Partnership:

Recipient	Form of Compensation	Amount

Managing General Partner	Partnership interest	10% carried interest in the Partnership, out of which the economic equivalent of a 3% carried interest is allowed to the broker/dealers who were involved in the offering of units.

Managing General Partner	Management fee	15% of subscriptions, less organization and offering costs to be paid by Reef (non-recurring). For the year ended December 31, 2008, the Partnership paid a management fee of $13,320,000.

Managing General Partner and its Affiliates	Monthly administrative fee	1/12th of 1% of all capital raised ($89,410,518), payable monthly until the Partnership is dissolved. For the years ended December 31, 2012 and 2011, the Partnership paid administrative fees of $567,424 and $896,880 respectively.

Managing General Partner or its Affiliates	Drilling compensation	When Reef or an affiliate of Reef serves as operator of a Partnership property, then Reef or such affiliate, as the case may be, will receive drilling compensation equal to 15% of the total well costs, excluding lease acquisition costs. Total well costs include the costs associated with all developmental activities on a well, such as drilling, completing, reworking, working over, deepening, sidetracking, or fracturing a well. Because RELP will serve as operator of the Slaughter Dean Project, such drilling compensation payable to RELP may amount to approximately 9% total partnership subscriptions, depending on the level of developmental operations conducted by Reef or RELP. If neither Reef nor an affiliate of Reef serves as operator of a Partnership well, then Reef will receive drilling compensation equal to 5% of the total well

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Recipient	Form of Compensation	Amount

		costs, excluding lease acquisition costs, for our services as managing general partner. As a result, such drilling compensation payable to Reef may amount to approximately 1% to 3% of total partnership subscriptions, depending on the level of developmental operations conducted by operators not affiliated with Reef. For the years ended December 31, 2012 and 2011, the Partnership paid a drilling compensation fee of $39,856 and $54,005 respectively.

Managing General Partner and its Affiliates	Direct costs	Reimbursement at cost. For the years ended December 31, 2012 and 2011, the Partnership paid direct costs of $173,102 and $345,089 respectively.

Managing General Partner and its Affiliates	Payment for equipment, supplies, marketing, and other services	Competitive prices. For the years ended December 31, 2012 and 2011, the Partnership paid no payments for equipment, supplies, marketing and other services.

Managing General Partner and its Affiliates	Acquisition and Development Costs	Reimbursement at cost. For the years ended December 31, 2012 and 2011, the Partnership did not reimburse the Managing General Partners and its affiliates for any acquisition and development costs.

Reef received a payment equal to 15% ($13,320,000, less $151,906 of the unpaid net asset values) of the Partnership’s subscriptions, as adjusted for sale of Units 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. From this payment, Reef paid organization and offering costs of the Partnership, including commissions. Because the organization and offering costs were less than 15% of the aggregate subscriptions to the Partnership, Reef kept the difference ($5,688,668) as a one-time management fee.

Reef also receives an 11% interest in the Partnership in regard to which it bought 1% of all Units issued by the Partnership; the additional 10% is “carried” by the Investor Partners and for which Reef will pay no drilling or completion expenses. Cash distributions to partners of the net cash flow from interest income and crude oil and natural gas sales revenues, less operating, general and administrative, and other costs are distributed 11% to the managing general partner and 89% to investor partners. During the years ended December 31, 2012, 2011 and 2010, Reef has received $72,085, $107,464, and $101,085, respectively, in distributions related to such 11% interest.

In addition, when Reef, or an affiliate of Reef, such as RELP, serves as operator of a Partnership well, then Reef or such affiliate of Reef, as the case may be, will receive drilling compensation in an amount equal to 15% of the total well costs paid from the funds of the Partnership. RELP currently serves as the operator of the Slaughter Dean

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Project. As a result, such drilling compensation payable to us or RELP may amount to approximately 9% of total partnership subscriptions, depending on the level of developmental operations conducted by Reef or RELP. Total well costs include all drilling and equipment costs, including intangible well costs, tangible costs of drilling and completing the well, costs of storage and other surface facilities, and the tangible costs of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point. In addition, total well costs also 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 for purposes of calculating drilling compensation. During the years ended December 31, 2012, 2011, and 2010, RELP received $39,856, $54,005 and $232,775 in drilling compensation, respectively. If neither Reef nor an affiliate of Reef serves as operator of a Partnership well, then Reef will receive drilling compensation equal to 5% of the total well costs, excluding lease acquisition costs, for Reef’s services as managing general partner. Drilling compensation is 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 year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively. During the year ended December 31, 2011, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $342,271 and $2,818, respectively. During the year ended December 31, 2010, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $441,881 and $10,192, respectively.

Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th 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 years ended December 31, 2012 and 2011, RELP received administrative fees totaling $567,424 and $896,880, respectively. Administrative fees are included in general and administrative expense in the financial statements. 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 revenues on behalf of the Partnership. At December 31, 2012 and 2011, RELP owed the Partnership $633,900 and $598,599, respectively, for net revenues processed in excess of net joint interest and technical and administrative service 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.

Compensation Committee

Because the Partnership has no directors, it does not have a compensation committee.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information as of December 31, 2012 concerning all persons known by Reef to own beneficially more than 5% of the interests in the Partnership. Unless expressly indicated otherwise, each partner exercises sole voting and investment power with respect to the units beneficially owned.

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Person or Group		Number of Units Beneficially Owned		Percent of Total Partnership Units Outstanding		Percentage of Total Partnership Interests Beneficially Owned
Reef Oil & Gas Partners, L.P. (1)		8.969696		1.00	%	10.90	%

(1) Reef Oil & Gas Partners, L.P.’s address is 1901 N. Central Expressway, Suite 300, Richardson, Texas 75080.

Reef, the managing general partner received a 10% carried interest in the Partnership, and also holds a 1% interest in the Partnership as a result of purchasing 1% of the total outstanding units. Michael J. Mauceli has voting and investment powers over Reef. There are no arrangements whereby Reef has the right to acquire additional units within sixty days from options, warrants, rights, conversion privileges, or similar obligations.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The Partnership is managed by a managing general partner and does not have directors. Reef is the managing general partner of the Partnership. Along with its affiliates, Reef has entered into agreements with, and received compensation from, the Partnership for services it performs for the Partnership. See “Item 11 - Executive Compensation.”

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 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 in the Covington Prospect in Ward County, Texas 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 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.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The Partnership incurred professional audit and tax fees from its principal accountant BDO USA, LLP, as disclosed in the table below:

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	2012		2011
Audit fees	$	81,300	$	85,700
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—

As indicated in Item 10 above, the Partnership does not have any directors or an audit committee.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	1. Financial Statements

	Report of Independent Registered Public Accounting Firm	F-1
	Balance Sheets	F-2
	Statements of Operations	F-3
	Statements of Partnership Equity	F-4
	Statements of Cash Flows	F-5
	Notes to Financial Statements	F-6


	2. Financial Statement Schedules	None

	3. Exhibits

A list of the exhibits filed or furnished with this Annual Report (or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Exhibit Index in this Annual Report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the exhibits are filed herewith.

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EXHIBIT INDEX

The following documents are incorporated by reference in response to Item 15 (b).

Exhibit Number		Description

3.1		Certificate of Formation of Reef Oil & Gas Income and Development Fund III, L.P. dated November 27, 2007(incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

4.1		Second Amendment and Restated Agreement of Limited Partnership of Reef Oil & Gas Income and Development Fund III, L.P., dated June 4, 2008 (incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.1		Operating Agreement dated January 7, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.2		Operating Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 10.2 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.3		Purchase and Sale Agreement dated January 7, 2008 by and among Sierra-Dean Production Company L.P., Reef Oil & Gas Income and Development Fund III, L.P., Reef Exploration L.P. and SPI Operations LLC, as amended on January 8, 2008 (incorporated by reference to Exhibit 10.3 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.4		Assignment, dated May 1, 2008, by and between Davric Corporation and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.4 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.5		Crude Oil Contract, dated March 13, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc., as amended by Amendment No. 1, dated June 24, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc. (incorporated by reference to Exhibit 10.5 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.6		Consulting Agreement, dated September 1, 2006, by between Reef Exploration, L.P. and William R. Dixon (incorporated by reference to Exhibit 10.6 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.7		Casinghead Gas Sales Contract, dated January 1, 1978, by and between Amoco Production Company and Amoco Production Company (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.8		Purchase and Sale Agreement, dated January 19, 2010, by and between Azalea Properties Ltd. And RCWI, LP. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

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10.9		Purchase and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P., and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.10		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing PUDs (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.11		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing Properties/Title Defect Notice (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.12		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Third Party Consents (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.13		Purchase and Sale Agreement by and between Lett Oil & Gas, L.P., as seller and RCWI, L.P., as buyer dated as of June 23, 2010 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.14		Assignment, Conveyance and Bill of Sale between Lett Oil & Gas, L.P. (“Assignor”) and Reef Oil & Gas Income and Development Fund III, L.P. (“Assignee”) executed June 30, 2010 and dated effective June 1, 2010 (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.15		$50,000,000 Credit Agreement dated June 30, 2010 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.16		Form of Security Agreement (General) dated June 30, 2010 by Reef Oil & Gas Income and Development Fund III, L.P., in favor of Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.17		Promissory Note in the principal amount of up to $50,000,000 dated June 30, 2010 payable to Texas Capital Bank, N.A. (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.18		Purchase and Sale Agreement, effective June 1, 2011, between the Partnership and Reef 2010 -A Income Fund, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).

10.19		First Amendment to the Credit Agreement dated May 20, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated May 20, 2011).

10.20		Second Amendment to the Credit Agreement dated June 30, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K dated June 24, 2011).

23.2	*	Consent of Forrest A. Garb. & Associates, Inc.

31.1	*	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) under the

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

Balance Sheets

December 31,	2012		2011

Assets
Current assets:
Cash and cash equivalents	$	495,244	$	513,410
Accounts receivable	1,986		1,800
Accounts receivable from affiliates	679,422		598,599
Deferred financing fees, net	12,299		—
Total current assets	1,188,951		1,113,809

Oil and gas properties, full cost method of accounting:
Accounting:
Proved properties, net of accumulated depletion of $62,728,480 and $62,218,962	14,023,909		12,664,259
Unproved properties	524,357		1,708,425
Net oil and gas properties	14,548,266		14,372,684

Deferred financing fees, net	—		36,263

Total assets	$	15,737,217	$	15,522,756


Liabilities and partnership equity

Current liabilities:
Accounts payable	$	5,595	$	3,597
Current portion of long-term note payable	1,315,000		360,000
Total current liabilities	1,320,595		363,597

Long term liabilities:
Note payable	—		1,405,000
Asset retirement obligation	2,366,899		1,835,115
Total long term liabilities	2,366,899		3,240,115

Commitments and contingencies (Note 7)

Partnership equity
General partners	6,899,244		6,902,531
Limited partners	4,995,071		4,997,729
Managing general partner	155,408		18,784
Total partnership equity	12,049,723		11,919,044

Total liabilities and partnership equity	$	15,737,217	$	15,522,756

See accompanying notes to financial statements.

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

Statements of Operations

	For the Years Ended December 31,
	2012			2011			2010

Oil, gas and NGL sales	$	5,830,997		$	6,048,932		$	5,599,090

Costs and expenses:
Lease operating expenses	2,506,677			2,803,824			2,369,144
Production taxes	314,377			394,160			385,740
Depreciation, depletion and amortization	1,222,493			1,128,514			1,933,948
Accretion of asset retirement obligation	119,588			78,030			62,390
Property impairment	—			—			57,944,024
General and administrative	776,523			1,382,040			2,610,680
Total costs and expenses	4,939,658			5,786,568			65,305,926

Income (loss) from operations	891,339			262,364			(59,706,836		)

Other income (expense)
Miscellaneous income (expense)	69			16			(8,086		)
Interest income	—			—			3,490
Interest expense	(80,632		)	(160,720		)	(128,472		)
Amortization of deferred financing fees	(24,776		)	(13,553		)	—
Total other income (expense)	(105,339		)	(174,257		)	(133,068		)

Net income (loss)	$	786,000		$	88,107		$	(59,839,904	)

Net income (loss) per general partner unit	$	650.10		$	(27.55	)	$	(66,724.73	)
Net income (loss) per limited partner unit	$	650.10		$	(27.55	)	$	(66,724.73	)
Net income (loss) per managing general partner unit	$	23,268.23		$	12,549.94		$	(65,593.41	)

See accompanying notes to financial statements.

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

Statements of Partnership Equity

	General Partners				Limited Partners				Managing General Partner				Total
	Units	Amount			Units	Amount			Units	Amount			Units	Amount

Balance at December 31, 2009	490.9827	$	40,609,693		397.0172	$	32,253,928		8.9697	$	703,117		896.9696	$	73,566,738
Partner distributions	—	(512,791		)	—	(414,650		)	—	(101,085		)	—	(1,028,526		)
Net loss	—	(32,760,687		)	—	(26,490,864		)	—	(588,353		)	—	(59,839,904		)
Balance at December 31, 2010	490.9827	$	7,336,215		397.0172	$	5,348,414		8.9697	$	13,679		896.9696	$	12,698,308

Distribution amount per partnership unit		$	1,044.42			$	1,044.42			$	11,269.61

Balance at December 31, 2010	490.9827	$	7,336,215		397.0172	$	5,348,414		8.9697	$	13,679		896.9696	$	12,698,308
Partner distributions	—	(420,159		)	—	(339,748		)	—	(107,464		)	—	(867,371		)
Net income (loss)	—	(13,525		)	—	(10,937		)	—	112,569			—	88,107
Balance at December 31, 2011	490.9827	$	6,902,531		397.0172	$	4,997,729		8.9697	$	18,784		896.9696	$	11,919,044

Distribution amount per partnership unit		$	855.75			$	855.75			$	11,980.78

Balance at December 31, 2011	490.9827	$	6,902,531		397.0172	$	4,997,729		8.9697	$	18,784		896.9696	$	11,919,044
Partner distributions	—	(322,476		)	—	(260,760		)	—	(72,085		)	—	(655,321		)
Net income	—	319,189			—	258,102			—	208,709			—	786,000
Balance at December 31, 2012	490.9827	$	6,899,244		397.0172	$	4,995,071		8.9697	$	155,408		896.9696	$	12,049,723

Distribution amount per partnership unit		$	656.80			$	656.80			$	8,036.50

See accompanying notes to financial statements.

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

Statements of Cash Flows

	For the Years Ended December 31,
	2012			2011			2010

Cash flows from operating activities
Net income (loss)	$	786,000		$	88,107		$	(59,839,904	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Plugging and abandonment costs paid from ARO	(30,835		)	(15,230		)	—
*Adjustments for non-cash transactions:*
Depletion, depreciation and amortization	1,222,493			1,128,514			1,933,948
Accretion of asset retirement obligation	119,588			78,030			62,390
Property impairment	—			—			57,944,024
Amortization of deferred financing fees	24,776			13,553			—
*Changes in operating assets and liabilities*
Accounts receivable	(186		)	—			(531,700		)
Accounts receivable from affiliates	(35,301		)	277,711			1,454,361
Accounts payable	1,998			3,550			(429,928		)
Accounts payable to affiliates	—			—			(154,790		)
Accrued liabilities	—			(9,819		)	(49,618		)

Net cash provided by operating activities	2,088,533			1,564,416			388,783

Cash flows from investing activities:
Proceeds from sale of oil & gas properties	93,451			3,059,455			933,300
Purchase of oil & gas properties	—			—			(18,547,948		)
Property development	(1,094,017		)	(1,344,956		)	(3,602,775		)

Net cash provided by (used in) investing activities	(1,000,566		)	1,714,499			(21,217,423		)

Cash flows from financing activities:
Proceeds from note payable	—			—			5,000,000
Payment of note payable	(450,000		)	(2,985,000		)	(250,000		)
Payment of debt issuance costs	(812		)	(49,816		)	—
Distributions to partners	(655,321		)	(867,371		)	(1,028,526		)

Net cash provided by (used in) financing activities	(1,106,133		)	(3,902,187		)	3,721,474

Net decrease in cash and cash equivalents	(18,166		)	(623,272		)	(17,107,166		)
Cash and cash equivalents, beginning of year	513,410			1,136,682			18,243,848

Cash and cash equivalents, end of year	$	495,244		$	513,410		$	1,136,682

Supplemental cash flow disclosure
Cash paid for interest expense on note payable	$	80,592		$	160,663		$	128,472
Supplemental disclosure of non-cash investing transactions
Property sales included in accounts receivable from affiliates	$	45,522		$	—		$	59,455
Additions to property and asset retirement obligation	$	(446,189	)	$	(873,886	)	$	(668,800	)
Adjustment to property and asset retirement obligation	$	—		$	5,517		$	76,156
Property additions related to Davric default	$	—		$	—		$	(435,390	)

See accompanying notes to financial statements.

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

Notes to Financial Statements (continued)

1. Organization and Basis of Presentation

Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000 each) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated there under, with a maximum offering amount of $90,000,000 (900 units). On June 12, 2008, the offering of units of limited and general partner interests in the Partnership was closed, with interests aggregating to $88,648,094 being sold to accredited investors, of which $48,984,933 were sold to accredited investors as units of general partner interest and $39,663,161 were sold to accredited investors as units of limited partner interest. As managing general partner, Reef contributed $762,425 (approximately one percent (1%) of the total contributions of the non-Reef general partners and limited partners) to the Partnership in exchange for 8.9697 units of general partner interest, resulting in a total capitalization of the Partnership of $89,410,519 before organization and offering costs and unpaid net asset values.

The Partnership engages in oil and gas development and production in a producing oil property located in the Slaughter Field in Cochran County, Texas, approximately 50 miles southwest of Lubbock, Texas (the “Slaughter Dean Project”). During 2010, the Partnership also acquired working interests in certain oil and gas properties as described in detail in Note 2 “Acquisitions” below. The Partnership produces existing proved reserves and participates in developmental drilling for proved undeveloped reserves, but does not engage in exploratory drilling for unproved reserves. Acreage the Partnership acquires containing unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef.

The management of the operations and other business of the Partnership are the responsibility of Reef. Reef Exploration, L.P. (“RELP”), an affiliate of Reef, serves as the operator of the Slaughter Dean Project. This relationship with the Partnership is governed by two operating agreements. One operating agreement (the “Sierra-Dean Operating Agreement” is between the Partnership, RELP and Sierra-Dean Production Company, LP. The other operating agreement is between the Partnership, RELP, and Davric Corporation (the “Davric Operating Agreement”).

In January 2008, the Partnership purchased an initial 41% working interest from Sierra-Dean Production Company LP, (“Sierra Dean”) in the Slaughter Dean Project, and under the terms of the Slaughter Dean Purchase Agreement, each month thereafter earns additional working interests based on the amount the Partnership spends developing and operating the project through December 2012. In general, the Slaughter Dean Purchase Agreement required the Partnership to pay 82% of all drilling, development and repair costs (including amounts allocable to the 41% working interest initially retained by Sierra Dean), and Sierra Dean conveyed additional working interest to the Partnership each month as payment of its share of such costs. In a separate transaction in May 2008, the Partnership purchased an 11% working interest in the Slaughter Dean Project from Davric Corporation.

2. Property Acquisitions

On January 19, 2010, RCWI, L.P. (“RCWI”), an affiliate of the Partnership, completed the acquisition of certain working interests in oil and gas properties from Azalea Properties Ltd. (“Azalea Properties”) for a purchase price of $21,610,116 pursuant to a Purchase and Sale Agreement between RCWI and Azalea Properties dated December 18, 2009 (the “Azalea Purchase Agreement”). The Azalea Purchase Agreement was subject to three side letter agreements regarding the post-closing acquisition of proven undeveloped properties, the post-closing resolution of properties with title defects, and the post-closing resolution of third-party consents for certain properties (collectively, the “Side Letter Agreements”).

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

Notes to Financial Statements (continued)

Subsequently, RCWI entered into a purchase and sale agreement with the Partnership (the “RCWI Agreement”), dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties to the Partnership. The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties for a purchase price of $13,182,171 in cash subject to post-closing adjustments. RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The acquired working interests (“Azalea Acquired Properties”) include properties located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset acreage. Approximately $10.7 million of the purchase price is associated with proved developed reserves.

The transactions described above were effective as of December 1, 2009 and were recorded under acquisition accounting rules. The Partnership allocated $10,705,500 as proved properties and $2,486,463 as unproved properties based upon the fair value of the assets acquired at the acquisition date. Revenues and expenses related to December 2009 were treated as a purchase price adjustment. Revenues and expenses subsequent to December 2009 related to the Azalea Acquired Properties are included in the statements of operations for the year ended December 31, 2010. Revenues related to the Azalea Acquired Properties were $2,470,294 for the year ended December 31, 2010. The Partnership recorded impairment expense of $2,573,225 related to the Azalea Acquired Properties during the year ended December 31, 2010. The Partnership also recorded $730,063 of acquisition related costs during the year ended December 31, 2010, as general and administrative expenses on its statements of operations.

On June 15, 2010, Reef Oil & Gas Income and Development Fund IV (“Income Fund IV”) paid $1,252,844 to Azalea Properties for the post-closing settlement related to the Side Letter Agreements. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post-closing settlement amount. The entire post-closing settlement was associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

On June 23, 2010, RCWI entered into a Purchase and Sale Agreement (the “Lett Purchase Agreement”) with Lett Oil & Gas, L.P. (“Lett”) for working interests in certain proved developed oil and gas properties owned by Lett for a purchase price of $6,000,000. The properties (“Lett Acquired Properties”) are located in the Thums Long Beach Unit. The entire $6,000,000 purchase price was associated with proved developed reserves. 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 Lett Purchase Agreement acknowledged two $500,000 deposits which were refundable to RCWI only upon certain terms set forth in the agreement and which were credited towards the purchase price at closing. The Partnership advanced the two $500,000 deposits as well as the remaining $5,000,000 of the purchase price payable at closing by RCWI under the Lett Purchase Agreement. The oil and gas property interests included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010.

The transaction described above was recorded under acquisition accounting rules. The Partnership allocated the entire $6,000,000 as proved properties based on the fair value of the assets acquired at the acquisition date. Revenues and expenses related to June 2010 were treated as a purchase price adjustment. Revenues and expenses subsequent to June 2010 related to the Lett Acquired Properties are included in the statements of operations for the year ended December 31, 2010. Revenues related to the Lett Acquired Properties were $559,452 for the year ended December 31, 2010. The Partnership recorded impairment expense of $2,203,926 related to the Lett Acquired Properties during the year ended December 31, 2010. The Partnership also recorded $61,037 of acquisition related costs during the year ended December 31, 2010, as general and administrative expenses on its statements of operations.

The following unaudited pro forma condensed statements of revenue and earnings for the year ended December 31, 2010 are presented as if the acquisition of the Lett Acquired Properties had occurred at the beginning of the period presented. The unaudited pro forma condensed consolidated financial information is not indicative of our financial position or the results of our operations that might have actually occurred if the acquisition of the Lett Acquired Properties had occurred at the dates presented or of our future financial position or results of operations. The information presented for the year ended December 31, 2010 includes pro forma information for the Lett Acquired Properties only, as the Azalea Acquired Properties are included in the statements of operations of the Partnership beginning January 2010.

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Notes to Financial Statements (continued)

Unaudited Pro Forma Condensed Statements of Revenues and Earnings

For the Year Ended December 31,	2010

Revenues	$	6,019,282
Net loss	$	(58,883,524	)

Net loss per general partner unit	$	(65,676.03	)
Net loss per limited partner unit	$	(65,676.03	)
Net income (loss) per managing general partner unit	$	(62,791.11	)

3. Summary of Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from these estimates.

Cash and Cash Equivalents

The Partnership considers all highly liquid investments with maturity dates of no more than three months from the purchase date to be cash equivalents. Cash and cash equivalents consist of demand deposits and money market investments invested with a major national bank, which at times may exceed federally insured limits. The Partnership has not experienced any losses in such accounts, and does not expect any loss from this exposure. The carrying value of the Partnership’s cash equivalents approximates fair value.

Risks and Uncertainties

Historically, the oil and gas market has experienced significant price fluctuations. Prices are impacted by local weather, supply in the area, availability and price of competitive fuels, seasonal variations in local demand, limited transportation capacity to other regions, and the worldwide supply and demand for crude oil.

The Partnership has not engaged in commodity futures trading or hedging activities and has not entered into derivative financial instrument transactions for trading or other speculative purposes. 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.

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. For these purposes, 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 crude oil and natural gas properties, unless such a sale would significantly

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Notes to Financial Statements (continued)

alter the rate of depletion and amortization. During the years ended December 31, 2012 and 2011, the Partnership recognized no property impairment expense of proved properties. During the year ended December 31, 2010, the Partnership recognized property impairment expense of proved properties of $4,777,151.

The Partnership excludes from amortization the cost of unproved properties. The Partnership expects that substantially all of its unproved property costs will be reclassified to proved properties within 10 years of their acquisition. Oil and gas property and equipment not being amortized as of December 31, 2012 are as follows by the year in which such costs were incurred:

	Total		2012		2011		2010
Acquisition costs	$	524,357	$	—	$	—	$	524,357

Total costs withheld from amortization	$	524,357	$	—	$	—	$	524,357

Proved Crude Oil and Natural Gas Reserves

Estimates of the Partnership’s proved reserves at December 31, 2012, 2011, and 2010 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and 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. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by independent petroleum engineers.

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.

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Notes to Financial Statements (continued)

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 a lease operating expense on the accompanying statement of operations. As a result of these plugging and abandonment operations, the Partnership revised its estimated liability during the quarter ended September 30, 2011 for the Slaughter Dean Field by increasing the basis of the Slaughter Dean Field wells by $860,878 and recording additional asset retirement obligation of this amount as a change in estimate.

During the year ended December 31, 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 year ended December 31, 2012. During the year ended December 31, 2012, the Partnership also recognized an additional $446,189 of asset retirement obligations and additional capitalized cost in connection with successful wells drilled by the Partnership and revisions related to existing wells.

The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2012 and 2011.

	2012			2011
Beginning asset retirement obligation	$	1,835,115		$	903,946
Additions related to new properties	7,579			13,008
Revisions related to existing properties	438,610			860,878
Retirement related to property sales	(1,605		)	(5,517		)
Retirement related to property abandonment and restoration	(32,388		)	(15,230		)
Accretion expense	119,588			78,030
Ending asset retirement obligation	$	2,366,899		$	1,835,115

Recognition of Revenue

The Partnership has entered into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenue is recognized based upon the Partnership’s share of metered volumes delivered to its purchasers each month. The Partnership had no material gas imbalances at December 31, 2012, 2011, and 2010.

Income Taxes

The Partnership’s net income or loss flows directly through to its partners, who are responsible for the payment of Federal taxes on their respective share of any income or loss. Therefore, there is no provision for federal income taxes in the accompanying financial statements.

As of December 31, 2012, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $23.4 million, primarily due to the difference between property impairment costs deducted for financial reporting purposes and intangible drilling costs deducted for income tax purposes.

Accounting for Uncertainty in Income Taxes

The Financial Accounting Standards Board (‘FASB”) provides guidance on accounting for uncertainty in income taxes. This guidance is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s

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Notes to Financial Statements (continued)

financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.

Under this guidance, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.

Based on the Partnership’s assessment, there are no material uncertain tax positions as of December 31, 2012 and 2011. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2012 and 2011. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.

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 December 31, 2012 and 2011, as it is subject to short-term floating interest rates that approximate the rates available to us 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.

4. 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 oil and gas properties purchased from Lett by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in Note 2 above. 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 December 31, 2012, the interest rate was 5.0%. 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. At June 30, 2010, the borrowing base was equal to $5,000,000. 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 Lett Purchase Agreement described in Note 2 above. 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.

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Notes to Financial Statements (continued)

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.

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 December 31, 2012, the outstanding balance due TCB was equal to $1,315,000. The Partnership has recognized the entire $1,315,000 as a current liability as of December 31, 2012 due to the June 30, 2013 expiration of the Credit Agreement. There is additional availability of $90,000 under the borrowing base as of December 31, 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).

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Notes to Financial Statements (continued)

At December 31, 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 has been obtained.

5. Transactions with Affiliates

Reef received an 11% interest in the Partnership for which it pays 1% of all costs related to the Partnership as incurred; the additional 10% is “carried” by the Investor Partners and for which Reef will pay no drilling or completion expenses. Cash distributions to partners of the net cash flow from interest income and crude oil and natural gas sales revenues, less operating and general and administrative costs are distributed 11% to the managing general partner and 89% to investor partners. During the years ended December 31, 2012, 2011 and 2010, Reef received $72,085, $107,464, and $101,085, respectively, in distributions related to the 11% interest. From funds generated by its carried interest and management fee, Reef paid to specific FINRA-licensed broker-dealers a monthly fee in the amount equal to the maximum of the economic equivalent of a 3% carried interest in the Partnership as additional compensation for the sale of units. This was recorded as a commission expense by Reef.

RELP, an affiliate of Reef, the managing general partner of the Partnership, currently serves as the operator of 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 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 also 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 years ended December 31, 2012, 2011 and 2010, RELP received $39,856, $54,005 and $232,775, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.

Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th 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 year ended December 31, 2012, RELP received administrative fees totaling $567,424. During the years ended December 31, 2011 and 2010, RELP received administrative fees totaling $896,880 and $896,880, 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.

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Notes to Financial Statements (continued)

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. The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and 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 included 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 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.

6. Major Customers

The Partnership may sell crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues can be received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, 2012, one marketer and one operator accounted for 34.6% and 26.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2011, one marketer and one operator accounted for 34.9% and 29.4% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2010, one marketer and one operator accounted for 39.5% and 20.8% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

7. Commitments and Contingencies

The Partnership is not currently involved in any legal proceedings.

The Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN Associates whereby the Partnership agreed to assign a one percent (1%) overriding royalty interest, proportionately reduced to the Partnership’s working interest, to William R. Dixon in exchange for Dixon’s agreement to “review and evaluate exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnership’s working interest in the Slaughter Dean Field. During the years ended December 31, 2012, 2011, and 2010, William R. Dixon received $23,819, $21,914, and $18,828, respectively, related to this overriding royalty interest.

8. Partnership Equity

Information regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the years ended December 31, 2012, 2011 and 2010 is detailed below:

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Notes to Financial Statements (continued)

For the year ended December 31, 2012

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	208,709	$	23,268.23
General partner	490.9827	319,189		$	650.10
Limited partner	397.0172	258,102		$	650.10
Total	896.9696	$	786,000

For the year ended December 31, 2011

Type of Unit	Number of Units	Net income (loss)			Net income (loss) per unit
Managing general partner	8.9697	$	112,569		$	12,549.94
General partner	490.9827	(13,525		)	$	(27.55	)
Limited partner	397.0172	(10,937		)	$	(27.55	)
Total	896.9696	$	88,107

For the year ended December 31, 2010

Type of Unit	Number of Units	Net loss			Net loss per unit
Managing general partner	8.9697	$	(588,353	)	$	(65,593.41	)
General partner	490.9827	(32,760,687		)	$	(66,724.73	)
Limited partner	397.0172	(26,490,864		)	$	(66,724.73	)
Total	896.9696	$	(59,839,904	)

9. Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)

Capitalized Costs

The following table presents the Partnership’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated:

	December 31, 2012			December 31, 2011			December 31, 2010

Oil and natural gas properties:
Unproved properties	$	53,691,229		$	54,875,297		$	55,136,307
Proved properties	21,461,203			20,036,869			21,430,901
Capitalized asset retirement obligation	2,124,314			1,679,480			810,574
	77,276,746			76,591,646			77,377,782
Less:
Accumulated depreciation, depletion and amortization	(4,116,026		)	(3,606,508		)	(2,477,455		)
Property impairment	(58,612,454		)	(58,612,454		)	(58,612,454		)
	(62,728,480		)	(62,218,962		)	(61,089,909		)

Total	$	14,548,266		$	14,372,684		$	16,287,873

Costs Incurred

The following table sets forth the costs incurred in oil and gas exploration and development activities during the

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Notes to Financial Statements (continued)

years ended December 31, 2012, 2011, and 2010.

	2012		2011		2010

Oil and natural gas properties:
Exploration	$	—	$	—	$	—
Development	1,540,206		2,213,864		21,795,010
Total	$	1,540,206	$	2,213,864	$	21,795,010

Results of Operations

The following table sets forth the other results of operations from oil and gas producing activities for the years ended December 31, 2012, 2011 and 2010

	2012			2011			2010

Oil and gas producing activities:
Oil sales	$	5,358,144		$	5,452,219		$	4,713,431
Natural gas sales	472,853			596,713			885,659
Production expenses	(2,821,054		)	(3,197,984		)	(2,754,884		)
Accretion of asset retirement obligation	(119,588		)	(78,030		)	(62,390		)
Depreciation, depletion and amortization	(1,222,493		)	(1,128,514		)	(1,933,948		)
Property impairment	—			—			(57,944,024		)
Results of operations from producing activities	$	1,667,862		$	1,644,404		$	(57,096,156	)

Depletion rate per BOE	$	14.40		$	13.53		$	19.72

BOE = Barrels of Oil Equivalent (6 MCF equals 1 BOE)

Crude Oil and Natural Gas Reserves

Net Proved Developed Reserve Summary

The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2012, 2011 and 2010. Proved crude oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. At December 31, 2012, all of the Partnership’s reserves are classified as proved developed reserves. All of the Partnership’s reserves are located in the United States.

The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010.

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Notes to Financial Statements (continued)

	Oil (BBL) (1)		Gas (mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2009	114,400		66,060		125,410
Purchases of reserves in place	566,505		1,607,592		834,437
Revisions of previous estimates	223,647		(265,604	)	179,380
Production	(66,352	)	(190,208	)	(98,053	)
Reserves at December 31, 2010	838,200		1,217,840		1,041,174

Reserves sold	(115,154	)	(39,980	)	(121,817	)
Revisions of previous estimates	19,069		121,929		39,389
Production	(62,255	)	(127,039	)	(83,428	)
Reserves at December 31, 2011	679,860		1,172,750		875,318

Reserves sold	(5,117	)	(5,873	)	(6,096	)
Revisions of previous estimates	152,765		(57,161	)	143,238
Production	(61,718	)	(138,956	)	(84,878	)
Reserves at December 31, 2012	765,970		970,760		927,582

(1) Oil includes both oil and natural gas liquids

(2) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Partnership believes such information is essential for a proper understanding and assessment of the data presented.

For the years ended December 31, 2012, 2011, and 2010, calculations were made using average prices of $94.68, $95.84, and $79.79 per barrel of crude oil, respectively, and $2.76, $4.15, and $4.39 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.

These assumptions used to compute estimated future cash inflows do not necessarily reflect Reef’s expectations of the Partnership’s actual revenues or costs, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.

F-17

Table of Contents

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

Notes to Financial Statements (continued)

The standardized measure of discounted future net cash flows as of December 31, 2012, 2011 and 2010 were as follows:

	December 31, 2012			December 31, 2011			December 31, 2010
Future cash inflows	$	77,852,350		$	67,687,020		$	68,288,340
Future production costs	(34,800,440		)	(31,201,620		)	(34,643,170		)
Future net cash flows	43,051,910			36,485,400			33,645,170
Effect of discounting net cash flows at 10%	(26,330,380		)	(20,449,930		)	(19,326,730		)
Discounted future net cash flows	$	16,721,530		$	16,035,470		$	14,318,440

Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Natural Gas Reserves were as follows for the years indicated:

	December 31, 2012			December 31, 2011			December 31, 2010
Standardized measure at beginning of period	$	16,035,470		$	14,318,440		$	2,372,800
Purchases of minerals in place	—			—			11,899,186
Net change in sales price, net of production costs	1,645,080			4,185,204			868,538
Revisions of quantity estimates	2,318,973			559,448			1,995,861
Changes in production timing rates	(1,688,197		)	254,755			(273,409		)
Accretion of discount	1,603,547			1,431,844			237,280
Sales net of production costs	(2,890,355		)	(2,769,918		)	(2,781,816		)
Sales of minerals in place	(302,988		)	(1,944,303		)	—
Net increase (decrease)	686,060			1,717,030			11,945,640
Standardized measure at end of year	$	16,721,530		$	16,035,470		$	14,318,440

F-18

Part I		2

Item 1.	Business	2
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	17
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	20

PART II		21

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Selected Financial Data	22
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	31
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	32
Item 9A.	Controls and Procedures	32
Item 9B.	Other Information	32

PART III		33

Item 10.	Directors, Executive Officers and Corporate Governance	33
Item 11.	Executive Compensation	34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	36
Item 13.	Certain Relationships and Related Transactions, and Director Independence	37
Item 14.	Principal Accountant Fees and Services	37

PART IV		38

Item 15.	Exhibits and Financial Statement Schedules	38
	Signatures	39

Date: April 12, 2013

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


	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner


	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner


	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)

Signature	Title	Date

/s/ Michael J. Mauceli	Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the Partnership (Principal Executive Officer)	April 12, 2013
Michael J. Mauceli


/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of Reef Exploration, L.P. (Principal Financial and Accounting Officer)	April 12, 2013
Daniel C. Sibley		April 12, 2013

		Securities Exchange Act of 1934.

31.2	*	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1	*	Certification of Principal Executive Officer pursuant to 18 U.S.C. §1350.

32.2	*	Certification of Principal Financial Officer pursuant to 18 U.S.C. §1350.

99.1	*	Summary Reserve Report of Forrest A. Garb & Associates, Inc.

101	*	The following materials from this report, formatted in XBRL (eXtensible Business Reporting Language): (i) Balance Sheets as of December 31, 2011 and 2010, (ii) the Statements of Operations for the years ended December 31, 2011, 2010, and 2009, (iii) the Statements of Changes in Stockholders’ Equity for the years ended December 31, 2011, 2010 and 2009, (iv) the Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009, and (v) Notes to Financial Statements.

Report of Independent Registered Public Accounting Firm	F-1

Audited Financial Statements

Balance sheets	F-2
Statements of operations	F-3
Statements of partnership equity	F-4
Statements of cash flows	F-5
Notes to financial statements	F-6