Reef Oil & Gas Income & Development Fund III LP - FORM 10-K

Attached files

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EX-31.1 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex31-1.htm
EX-31.2 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex31-2.htm
EX-32.1 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex32-1.htm
EX-23.2 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex23-2.htm
EX-32.2 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex32-2.htm
EX-99.1 - Reef Oil & Gas Income & Development Fund III LP	v179474_ex99-1.htm

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, 2009

¨	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)

Nevada	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 ¨ 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 ¨ 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 ¨

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 ¨ No ¨

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 ¨ Accelerated filer ¨ Non-accelerated filer ¨ 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 ¨ No x

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

As of March 31, 2010, 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

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

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS

Part I

Item 1.	Business	3
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	19
Item 4.	Reserved	19

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	27
Item 8.	Financial Statements and Supplementary Data	28
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	28
Item 9A(T).	Controls and Procedures	28
Item 9B.	Other Information	29

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	29
Item 11.	Executive Compensation	31
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34
Item 13.	Certain Relationships and Related Transactions, and Director Independence	34
Item 14.	Principal Accountant Fees and Services	35

PART IV

Item 15.	Exhibits and Financial Statement Schedules	35
	Signatures	36

PART I

ITEM 1.

BUSINESS

Introduction

Reef Oil & Gas Income and Development Fund III, L.P. (the "Partnership") is a limited partnership that was formed under the laws of Texas on November 27, 2007. The primary objectives of the Partnership are to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef 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 purchased a working interest 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"), in January 2008. The Partnership is developing the Slaughter Dean Project as detailed in the section below entitled “Property Acquisition and Development”. On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but does not expect to engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations. Drilling locations for unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef.

The management of the operations and other business of the Partnership is the responsibility of Reef. Reef Exploration, L.P., an affiliate of Reef ("RELP"), serves as the operator of the Partnership’s interests in the Slaughter Dean Project (as more fully described under “Property Acquisition and Development” below). 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 (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.

In January 2010, the Partnership entered into a Purchase and Sale Agreement (the “RCWI Agreement”) with RCWI, L.P. (“RCWI”), an affiliate of Reef, to purchase certain working interests in oil and gas properties represented by leases, covering more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas. The acquired working interests represent a minority interest in each of the properties and are operated by more than 100 different operators, none of which are affiliates of Reef. For further information on the RCWI Agreement, see “Summary of Material Contracts – RCWI Agreement” below.

Property Acquisition and Development

The Slaughter Dean Project consists of approximately 6,700 acres and produces 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. The Partnership has utilized waterflood operations in an attempt to increase production from existing wells and optimize production from new wells drilled by the Partnership. 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. The Partnership has focused most of its development activities in the Dean "B" Unit. The Partnership is developing its properties in the Slaughter Dean Project by drilling and completing new production wells, and by increasing waterflood injection activity through the drilling and completing of new waterflood injection wells, restoring inactive waterflood injection wells and converting marginal producing wells to waterflood injection wells.

In January 2008, the Partnership purchased an initial 41% working interest from Sierra-Dean in the Slaughter Dean Project. Under the terms of the purchase agreement (the "Slaughter Dean Purchase Agreement"), each month the Partnership purchases additional working interest based on the amount the Partnership spends developing the Slaughter Dean Project through January 2013. In general, the Slaughter Dean Purchase Agreement requires 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 conveys 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 another working interest owner. See "Summary of Material Contracts - Davric Assignment" below for additional information.

During 2008 and 2009, the Partnership has developed the Slaughter Dean Project by infill drilling in order to convert part of the property from the current 40 acre spacing of wells to 20 acre spacing in an effort to increase the expected ultimate recovery of crude oil and natural gas in the Slaughter Dean Project. The Partnership has sought to enhance recovery through waterflood operations. The initial development phase of the project was completed during the fourth quarter of 2009, and additional water injection capacity was added during the first quarter of 2010. When the anticipated waterflood response begins, the Partnership will review the Slaughter Dean Project’s response to the waterflood and determine whether any additional development is necessary or desirable.

During 2008, the Partnership drilled twenty-five new developmental oil wells and three new waterflood injection wells, and worked over and stimulated four old producing oil wells in the Slaughter Dean Project. During the year ended December 31, 2009, the Partnership drilled five additional new oil wells and two additional new waterflood injection wells, and converted twenty-two old oil producing wells to waterflood injection wells. The Partnership has also repaired, replaced and expanded water pumping and injection facilities and capacity. 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 2,000 to 2,500 barrels of water in excess of the produced water are being injected back into the oil producing formation. An additional injection pump installed during March 2010 is expected to increase injection volume by another 1,000 to 1,500 barrels of water. The gradual filling of the productive formation via this enhancement of waterflooding is expected to loosen and force out additional oil. A final part of the developmental phase of operations was the conversion during 2009 of twenty-two productive wells into water injection wells. Following this conversion, the rate of production dropped during the third quarter of 2009. The Slaughter Dean Project currently produces approximately 110 barrels of crude oil and 3,700 barrels of water per day. The project is currently in the final developmental stage, the reservoir fill-up stage, and no initial response to the developmental work has been seen as of the date of this report.

The Partnership has expended approximately $41.9 million and $55.4 million on the Slaughter Dean Project as of December 31, 2008 and December 31, 2009, respectively, and, with the exception of the installation of additional injection capacity during March 2010, completed its initial development of the project during the fourth quarter of 2009, subject to evaluation for possible further operations. Once the waterflood response begins, the Partnership expects that the value of the Slaughter Dean Project properties will begin to increase from the level at which it was purchased. Traditionally, proved developed producing reserves command the highest value in the marketplace. By investing in programs that develop the proved undeveloped reserves of Partnership properties, the Partnership expects to grow property values. If successful, the Partnership intends to capture this increased value at re-sale and distribute it to the partners of the Partnership.

The Partnership sells the crude oil and natural gas production from its Slaughter Dean Project wells to Occidental Energy Marketing, Inc. and Occidental Permian Ltd 04, respectively, pursuant to contracts with provisions allowing for termination by either party on 30 days notice.

As of December 31, 2009 the Partnership had expended $55,369,408 on the acquisition and development of the Slaughter Dean Project and held an approximate 75.3% working interest in both the Dean Unit and the Dean "B" Unit, with a corresponding net revenue interest of approximately 64.3% and 59.6% in each, respectively. Additionally, as of December 31, 2009, the Partnership held an approximate 78.5% working interest in the Dean "K" Lease, with a corresponding net revenue interest of 53.2%.

As of December 31, 2009 the Partnership had remaining capital in the amount of $17,873,017, which is available for the acquisition and development of oil and gas properties outside of the Slaughter Dean Project. Subsequent to December 31, 2009, certain properties were acquired by the Partnership from RCWI for approximately $13,182,171 in cash, subject to post closing adjustments. For further information, see “Summary of Material Contracts – RCWI Agreement” below.

Area of Geographic Concentration: The Slaughter Field and the San Andres Formation

The Partnership’s oil and gas development and production operations are concentrated in the Slaughter Dean Project, which is the sole oil and gas property owned by the Partnership as of December 31, 2009. The Slaughter Dean Project is a small part of the Slaughter Field. The Slaughter Field as a whole consists of approximately 100,000 acres and covers portions of Cochran, Hockley, and Terry counties on the geological feature known as the North Basin platform. The Partnership holds no working interests in any Slaughter Field properties other than the Slaughter Dean Project.

The Slaughter Field is located south of the Levelland Field, and joins the Levelland Field on the west and east. The two fields are separated in the center by an approximate twenty-five-mile-wide strip on either side of the Hockley-Cochran county line. During its early years in the late 1930s, what is now the Slaughter Field was regarded as two separate fields called the Duggan Field (on the west, discovered in 1936) and the Slaughter Field (on the east, discovered in 1937). After evidence proved that both fields produced from the same formation, the Texas Railroad Commission combined them under one field regulation and called both areas the Slaughter Field. Secondary waterflood operations were first instituted in Slaughter Field in 1957.

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. Prior to December 31, 2007, the Partnership had no crude oil and natural gas production and, therefore, had no customers. During the years ended December 31, 2009 and 2008, one marketer accounted for all of the Partnership’s crude oil revenues, and one marketer accounted for all of the Partnership’s natural gas revenues. During 2008 and 2009, the Partnership’s only oil and gas property was the Slaughter Dean Project located in Cochran County, Texas. Reef has chosen to sell the Partnership’s crude oil and natural gas to two subsidiaries of a large international oil and gas company because of the amount of payment, the promptness of payment, and their credit worthiness indicated by their publicly filed financial statements. There are other large companies (or subsidiaries thereof) active in purchasing crude oil and natural gas in the area of the Slaughter Dean Project, including Exxon, Royal Dutch Shell, Plains All American Pipeline, Conoco-Phillips, Genesis Energy, and Holly Energy. There are also several smaller companies that purchase and re-sell crude oil. 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 the current purchaser would have a material adverse impact on the Partnership.

The Partnership does not use long-term contracts to sell oil or natural gas produced on the Slaughter Dean Property. Prices received for our oil production are based upon “posted” prices for West Texas Intermediate grade crude oil. The Partnership's contracts generally provide for a 30-day or 60-day termination notice by either party. As a result, there should be limited cost, delay or inconvenience in the event the Partnership replaces an oil and gas purchaser.

Insurance

Reef maintains various types of insurance coverage in amounts it deems appropriate. Additionally, Reef, on behalf of the Partnership, maintains insurance coverage intended to protect the Partnership from losses in amounts it deems adequate. These include blowout, pollution, public liability and workmen's compensation insurance, but such insurance may not be sufficient to cover all liabilities of the Partnership. Each unit held by the non-Reef general partners represents an open-ended liability for unforeseen events such as blowouts, lost circulation, stuck drillpipe, etc. that may result in unanticipated additional liability materially in excess of the per unit subscription amount.

Reef 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 coverage 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 any additional 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 customarily settled on 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 Reef 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 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 for the exploration for 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 market forces.

While there is currently no shortage of drilling equipment, goods or drilling crews, there are times when strong competition arises among operators for such items. Such competition may affect the ability and cost of the Partnership to develop oil and gas properties suitable for development by the Partnership once they are acquired.

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:

General economic conditions in the United States and around the world.

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; and

Other matters affecting the availability of a ready market, such as fluctuating supply and demand.

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.

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. However, pursuant to the Wellhead Decontrol Act of 1989, 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. On December 19, 2007, the Energy Independence and Security Act ("EISA"), a law targeted at reducing national demand for crude oil and increasing the supply of alternative fuel sources, was signed into law. While EISA does not appear to directly impact the Partnership’s operations or cost of doing business, its impact on the oil and gas industry in general is uncertain. No prediction can be made as to what additional legislation may be proposed, if any, affecting the competitive status of an oil and gas producer, restricting the prices at which a producer may sell its crude oil and/or natural gas, or the market demand for crude oil and/or natural gas, nor can it be predicted which proposals, including those presently under consideration, if any, might be enacted, nor when any such proposals, if enacted, might become effective.

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 development of the Slaughter Dean Project. The Seller initially retained a 41% working interest in two of the largest units comprising the Slaughter Dean Project, the Dean Unit and the Dean "B" Unit, as explained below 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 has an initial 41.0% working interest in each of the Dean Unit and the Dean "B" Unit and has a net revenue interest of 35.5% and 32.5 % in each respectively. In other words, the Dean Unit and the Dean "B" Unit are subject to royalty interests and overriding royalty interests of 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 very little of the combined value of the Slaughter Dean Project.

Subsequent to its initial purchase of working interests in the Slaughter Dean Project, the Partnership has 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 costs. In effect, 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. 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

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. As the Partnership develops the Slaughter Dean Project, its working interest increases and the Seller's working interest decreases. To determine the additional working interest acquired by the Partnership in the Dean "K" Lease, the fraction is multiplied by 100%, instead of 82%.

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.

As a result of the Slaughter Dean Purchase Agreement and the Davric Assignment and the additional interests acquired from the Seller as a result of expenditures paid by the Partnership regarding the Seller’s interest pursuant to the Slaughter Dean Purchase Agreement, as of December 31, 2009, the Partnership owned the approximate interests shown as follows:

	Working			Revenue
	Interest			Interest

Dean Unit		75.3	%		64.3	%
Dean "B" Unit		75.3	%		59.6	%
Dean "K" Lease		78.5	%		53.2	%

As of December 30, 2008, the Partnership owned the approximate interests shown as follows:

	Working			Revenue
	Interest			Interest

Dean Unit		71.9	%		60.7	%
Dean "B" Unit		71.9	%		56.3	%
Dean "K" Lease		74.2	%		49.7	%

RCWI Agreement

On January 19, 2010, RCWI 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 is 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.

RCWI entered into the RCWI Agreement, dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties to the Partnership. The Partnership acquired approximately 61.00% of the working interests initially acquired by RCWI from the Seller for a purchase price of approximately $13,182,171 in cash subject to post-closing adjustments. RCWI is also assigning portions of the acquired working interests to other Reef affiliates on the same terms.

Other Contracts

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 Partnerships working interest in the Slaughter Dean Field.

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 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 operations to be used in the Slaughter Dean Project may fail.

Although the Slaughter Dean Project included approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition, the estimated plan for the development of the Slaughter Dean Project (which has been adjusted from time to time depending on information learned during the implementation of the work plan) was to (i) drill a total of approximately 30 new oil wells, (ii) convert approximately 23 of the already-producing oil wells to waterflood injection wells to support the new, denser waterflood pattern, (iii) drill approximately 5 new waterflood 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 injectors, and (c) worked over 4 already-producing oil wells. During 2009, the Partnership (1) drilled 5 new oil wells, (2) converted 22 oil wells to waterflood injection wells, (3) drilled 2 new waterflood injection wells, and (4) worked over 1 already-producing well. As planned, the work program has been revised from time to time, and based upon the information learned through December 31, 2009, RELP and the Partnership have paused in the drilling of new oil wells while the waterflood operations are completed and implemented. As is common with waterflood operations, it can take many months to determine the effectiveness and results from the implementation or expansion of a waterflood.

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 believe the Slaughter Dean Project can 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.

Developing prospects in one area may increase the Partnership's risk.

At December 31, 2009, the Partnership had acquired only the Slaughter Dean Project, which may increase the Partnership's risk of loss. For example, if multiple wells in one area of the project are drilled at approximately the same time, then there is a greater risk of loss if the wells are marginal or nonproductive since Reef will not be using the drilling results of one or more of those wells to decide whether or not to continue drilling prospects in that area or to substitute other prospects in other areas. However, this risk is offset to some degree by the fact that there are currently producing wells on the Slaughter Dean Project. Also, the overall results of the work being performed on the Slaughter Dean Project cannot be evaluated immediately, since a response to the increased levels of water injection will not occur immediately.

Lack of drilling rig availability may result in delays in drilling on partnership prospects.

There may be shortages of drilling rigs and equipment available to conduct developmental drilling on properties the Partnership acquires. Such shortages could result in delays in the drilling of wells on such properties and delay a partner’s ability to deduct intangible drilling costs beyond the year of his or her investment.

The Partnership Agreement limits Reef’s liability to partners 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 Reef in connection with the Partnership if:

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

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

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

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

The Partnership holds title to its interests in the Slaughter Dean Project 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, was unable to pay immediately $851,129 of its share of the development costs already incurred as of June 30, 2009. Davric agreed to pay $100,000 per week toward these costs and has completed payment of the $851,129; however, as of December 31, 2009, Davric is currently in default for $538,443 of costs incurred subsequent to June 30, 2009. If Davric is unable to pay all of these costs, then pursuant to the Davric Operating Agreement, the Partnership will be entitled to recover these costs from Davric’s share of future revenues, plus penalties ranging from 300% to 450% of the amount in default. Sierra-Dean, at its option, may pay a pro rata share of the costs in default and share in the reimbursement and collection of applicable penalties from future revenues of the Slaughter Dean Project.

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

Reef estimates that the net proceeds from the sale of units in the Partnership will be sufficient to finance the Partnership's share of the costs of acquiring interests in the Slaughter Dean Project, operating existing wells and executing the revised work plan to conduct waterflood operations, including drilling new oil wells within the Slaughter Dean Project and providing necessary production equipment and facilities to service such oil and gas wells. Subsequent to December 31, 2009, certain properties were acquired by the Partnership from RCWI using approximately $13,182,171 out of the net proceeds remaining. For further information, see “Summary of Material Contracts – RCWI Agreement” below. 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 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.

The Partnership's operations will be subject to all of the operating risks normally associated with producing crude oil and natural gas, such as blow-outs and pollution, which could result in the Partnership incurring substantial liabilities or losses, although the chance of incurring a blow-out while drilling new oil wells within a mature waterflood project are believed by Reef to be small. 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.

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, including the Slaughter Dean Project, is not an exact science and involves a high degree of risk. The risks of acquiring and operating producing properties, such as the Slaughter Dean Project, 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 acquired producing portions of the Slaughter Dean Project, or other properties that may be 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. Also, Reef may receive information regarding the Slaughter Dean Project that may indicate that less crude oil and natural gas reserves exist than thought at the time of the acquisition of the Slaughter Dean Project. Oil and gas wells sometimes experience production decline that is rapid and irregular. Initial production from the wells of the Slaughter Dean Project does not accurately indicate any consistent level of production to be derived therefrom.

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

Prices of crude oil and natural gas are volatile.

Global economic conditions, political conditions, and energy conservation have created volatile prices for oil and natural gas. Crude oil and natural gas prices may fluctuate significantly in response to minor changes in supply, demand, market uncertainty, political conditions in oil-producing countries, activities of oil-producing countries to limit production, national and global economic conditions, weather conditions and other factors that are beyond the control of either the Partnership or Reef. The prices for domestic oil and natural gas production have varied substantially over time, especially during the past 24 months, and may decline in the future, which would adversely affect the Partnership and the partners. Prices for crude oil and natural gas have been and are likely to remain volatile. Approximately 91.2% of the Partnership’s estimated proved reserves at December 31, 2009 are crude oil reserves, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.

The recent 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 have experienced an economic downturn which could impact the industry in 2010 and beyond. The economic downturn has had an adverse impact on demand and pricing for crude oil and natural gas. A continuation of the economic downturn could have a further negative impact on crude oil and natural gas prices. The Partnership’s operating cash flows and profitability will be significantly affected by declining crude oil and natural gas prices. Further 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.

Competition and market conditions may adversely affect the Partnership.

The Partnership will compete with a number of other potential purchasers of properties, many of which have greater financial resources. This may result in the Partnership not being able to acquire certain properties otherwise desired for acquisition. From time-to-time, a surplus of crude oil and natural gas occurs in areas of the United States. The effect of a surplus may be to reduce the price the Partnership may receive for its crude oil or natural gas production, or to reduce the amount of crude oil or natural gas that the Partnership may economically produce and sell.

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.

The production and producing life of Partnership properties is uncertain. Production will decline.

It is not possible to predict the life and production of any property. The actual lives could differ from those anticipated. Sufficient crude oil or natural gas may not be produced for a partner to receive a profit or even to recover the partner’s initial investment. In addition, production from the Partnership's oil and gas properties, 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.

Variability’s 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.

Environmental hazards and liabilities may adversely affect the Partnership and result in liability for the non-Reef general partners.

There are numerous natural hazards involved in the drilling and operation of oil and gas wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, bodily injuries, damage to and loss of equipment, reservoir damage and loss of reserves. 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. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for non-Reef general partners. Although the Partnership will maintain insurance coverage in amounts Reef deems appropriate, it is possible that insurance coverage may be insufficient. In that event, Partnership assets would be utilized to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for additional drilling and development activities.

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.

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

Title to the Partnership’s interest in the leases for the Slaughter Dean Project is held in the name of the Partnership. Under certain circumstances, title to Partnership properties could be held by Reef on the Partnership's behalf. In other instances, title may not be transferred to Reef or the Partnership until after a well has been completed. 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."

Reef’s dependence on third parties for the processing and transportation of oil and gas may adversely affect the Partnership’s revenues and distributions.

Reef relies on third parties to process and transport crude oil and natural gas produced by wells in which the Partnership owns a working interest. In the event a third party upon which Reef relies is unable to provide transportation or processing services and another third party is unavailable to provide such services, then the Partnership will be unable to transport or process the crude oil and natural gas produced by the affected wells. In such an event, revenues to the Partnership and distributions to the partners may be delayed.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

The Partnership received a comment letter related to the Partnership’s Form 10 filing from the Securities and Exchange Commission (the “SEC”) dated December 16, 2009 in which the SEC requested, among other matters, audited financial statements of Sierra-Dean. The Partnership requested a waiver of such requirement in its response to the SEC, but such waiver was denied. However, in a letter dated February 16, 2010, the SEC stated that it may reconsider the waiver request once the Partnership’s annual report had been filed. The Partnership plans to again request such waiver following the filing of this Annual Report. All other comments related to the Partnership’s Form 10 have been resolved.

ITEM 2.

PROPERTIES

Drilling, Waterflood Development Activities and Productive Wells

The Partnership purchased a working interest in, and currently operates, the Slaughter Dean Project, located in the Slaughter Field in Cochran County, Texas, approximately 50 miles southwest of Lubbock, Texas. The Slaughter Dean Project consists of approximately 6,700 acres and produces from the San Andres formation at a depth of 5,000 to 5,500 feet. The major portions of the Slaughter Dean Project were previously unitized for waterflood operations. The Partnership intends to further develop the Project and utilize waterflood operations to increase production from both existing and new wells being drilled by the Partnership. The Partnership has redeveloped a portion of the Dean B Unit through infill drilling in order to convert a portion of the Project from the current 40 acre spacing of wells to 20 acre spacing. The Partnership has also reworked wells, converted some existing productive wells into water injection wells, and repaired, replaced, and expanded water pumping and injection facilities as detailed below in an effort to increase the expected ultimate recovery of the Slaughter Dean Project.

The Slaughter Dean Project is divided into three units, the Dean Unit, the Dean "B" Unit and the Dean "K" Lease. The Partnership has focused most of its development activities in the Dean "B" Unit. As of December 31, 2009, the Partnership has expended $55,369,408 on the acquisition and development of the Slaughter Dean Project. As a result, as of December 31, 2009, the Partnership holds an approximate 75.3% working interest in both the Dean Unit and the Dean "B" Unit and holds a net revenue interest of approximately 64.3% and 59.6% in each respectively. Additionally, as of December 31, 2009, the Partnership holds an approximate 78.5% working interest in the Dean “K” Lease and holds a net revenue interest of approximately 53.2%.

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 has been 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 waterflood injection wells to support the new, denser waterflood pattern, (iii) drill approximately 5 new waterflood 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 injectors, 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 waterflood injection wells, (3) drilled 2 new waterflood injection wells, and (4) worked over 1 already-producing well. The Partnership has also repaired, replaced, and expanded water pumping and injection facilities and capacity during 2008 and 2009, and such work is continuing into 2010 with the addition of a new injection pump during March 2010. As planned, the work program has been revised from time to time, and based upon the information learned through December 31, 2009, RELP and the Partnership have paused in the drilling of new oil wells while the enhancements to the waterflood operations are completed and implemented.

The drilling of new waterflood injection wells and the conversion of a number of old already-producing oil wells to waterflood injection wells is intended to increase the productivity of the Project as a whole. The Partnership is currently injecting approximately 2,000-2,500 barrels of water per day in excess of the produced water back into the oil producing formation. The additional pump installed during March 2010 is expected to increase injection volume by an additional 1,000-1,500 barrels of water per day. The gradual filling of the productive formation via this enhancement of waterflooding is expected to loosen and force out additional oil, thereby increasing the ultimate recovery of crude oil and natural gas in the Slaughter Dean project. As of the date of this report, no initial response to the development work performed has yet been seen. As is common with waterflood operations, it can take many months to determine the effectiveness and results from the implementation or expansion of a waterflood.

A significant portion of remaining capital at December 31, 2009 was committed to the purchase of additional properties in January 2010 – see below. The Partnership seeks properties which have producing reserves, proved undeveloped reserves, or both. The Partnership will not participate in exploratory drilling for any unproved reserves deemed to exist on either the Slaughter Dean Project or other properties purchased by the Partnership. To the extent acreage acquired by the Partnership is deemed to contain unproved reserves, such acreage may be farmed out or sold to third parties or other partnerships formed by Reef for exploratory drilling.

In January 2010, the Partnership entered into the RCWI Agreement with RCWI to purchase certain working interests in oil and gas properties, represented by leases, covering more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas. The largest property (THUMS Long Beach) in the package, is a long life water-flood 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 an estimated 100 million barrels of oil equivalent remains to be produced. THUMS Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell. THUMS Long Beach has been an agent of Occidental Long Beach, a subsidiary of Occidental Petroleum, since it was acquired in 2000.

Proved Oil and Gas Reserves

In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule requires disclosure of crude oil and natural gas proved reserves by significant geographic area, using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period prices, and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for 2009 is presented consistent with the requirements of the new rule. The new rule does not allow prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with prior SEC rules for the estimation of proved reserves. The effect of applying the new definition of reliable technology and other non-price related aspects of the updated rules did not significantly impact 2009 net proved reserve volumes. All of the Partnership’s reserves are located in the United States.

As of December 31, 2009 and 2008, proved reserves do not include any reserves associated with the redevelopment and enhancement of the waterflood. There is not yet sufficient reservoir response to permit performance based estimates of the amount and timing of additional reserves. Costs associated with the implementation of the waterflood development process have been capitalized and categorized as unproved prior to the time at which a reservoir response to the development work is noticed. The quantities of proved oil and 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, without the enhanced production, if any, from waterflood operations. 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. The Partnership had no proved reserves at December 31, 2007. The estimated net proved crude oil and natural gas reserves at December 31, 2009 and 2008 are summarized below.

	Oil (BBL)		Gas (MCF)
Net proved reserves as of December 31, 2008		308,302		220,109

Net proved reserves as of December 31, 2009		114,400		66,060

The standardized measure of discounted future net cash flows as of December 31, 2009 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 as of December 31, 2008 is computed by applying year-end prices, 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, 2008		$	4,483,742
Standardized measure of discounted future net cash flows as of December 31, 2009		$	2,372,800

During the years ended December 31, 2009 and 2008, the Partnership recorded property impairment costs of proved properties totaling $668,430 and $0 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.

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

The Partnership used an independent petroleum consulting company, William M. Cobb & Associates (“WCA”) of Dallas, Texas, to prepare its December 31, 2009 and 2008 reserve estimates of net proved crude oil and natural gas reserves. WCA estimated reserves for all of our properties as of December 31, 2009 and 2008. The technical personnel responsible for preparing the reserve estimates at WCA 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. WCA is an independent firm 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. WCA’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 WCA’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 GAAP.

Reef maintains a staff of petroleum engineers who work with WCA. 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 engineering personnel. Reserve estimates are prepared by WCA. Our engineering personnel meet regularly with WCA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. Byron H. (Howard) Dean, Manager – Acquisitions and Divestitures of RELP, is the petroleum engineer primarily responsible for overseeing the preparation of reserve estimates by WCA. Mr. Dean is a registered petroleum engineer with over thirty years of industry experience in oil and gas operations and reservoir engineering. He is an active member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. Any significant reserve changes are approved by Mr. Dean and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

Title to Properties

Title to the Slaughter Dean Project properties is held in the name of the Partnership. Under the RCWI Agreement, title to the properties is held in the name of RCWI. Currently RCWI holds record title to 84.76% of the properties, based on their value. RCWI is currently in the process of having the remaining titles transferred to itself from the seller. 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 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.

Reserved

PART II

ITEM 5.

MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2009, the Partnership had one managing general partner, 779 non-Reef general partners, and 663 investor 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 distributed to the partners at least quarterly in accordance with the Partnership Agreement. Cash distributions paid during 2009, 2008, and 2007 were $411,181, $1,791,295 and $16,801 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 $90,000,00 (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 or will be used for operations on the Slaughter Dean Project and other properties purchased by the Partnership, and to pay any additional fees owed to Reef as a result of such activities. On May 31, 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, 2009, the Partnership had expended $55,369,408 on acquisition and development of the Slaughter Dean Project. The remaining capital will be used for future acquisition and development costs of oil and gas properties outside of the Slaughter Dean Project to the extent such capital is not used on further development of the Slaughter Dean Project.

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,						Period from Inception (November 27,2007) to December 31,
	2009			2008			2007

Revenue	$	1,655,812		$	2,012,489		$	—
Interest income		140,471			706,243			28,208
Costs and expenses		(3,343,360	)		(1,781,499	)		(30,353	)
Net income (loss)		(1,547,077	)		937,233			(2,144	)

Allocation of net income (loss):
Managing general partner		(70,841	)		128,050			3,064
General partner units		(816,223	)		447,404			(2,252	)
Limited partner units		(660,013	)		361,779			(2,956	)
Net income (loss) per managing partner unit		(7,897.79	)		14,275.84			2,266.11
Net income (loss) per general partner unit		(1,662.43	)		911.25			(38.91	)
Net income (loss) per limited partner unit		(1,662.43	)		911.25			(38.91	)

Total assets		74,855,409			79,860,893			11,663,508
Distributions to managing general partner		49,050			195,938			168
Distributions to investor partners		362,131			1,595,357			16,633
Distributions per general partner unit		407.81			1,796.57			124.25
Distributions per limited partner unit		407.81			1,796.57			124.25
Distributions per managing general partner unit		5,468.41			21,844.32			124.25

Operating Data
Annual sales volume:
Gas (MCF)		7,204			21,466			—
Oil (BBL)		33,235			23,060			—

Average sales price:
Gas (per MCF)	$	1.49		$	2.94		$	—
Oil (per BBL)	$	49.50		$	84.53		$	—

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 2 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 at December 31, 2009, 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, for 2009. 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, 2009 and 2008, the Partnership recognized property impairment expense of proved properties totaling $668,430 and $0, respectively. The Partnership had no proved property during the period from inception (November 27, 2007) to December 31, 2007.

Unproved property consists of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project. The costs associated with the development and waterflood enhancement project are considered unproved pending an initial reservoir production response. 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 data obtained from the operations of the Slaughter Dean Property. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the years ended December 31, 2009 and 2008, the Partnership recognized no property impairment expense of unproved properties. The partnership had no unproved property during the period from inception (November 27, 2007) to December 31, 2007.

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, 2009 and 2008, utilizing prices and costs as promulgated by the SEC. The Partnership had no proved reserves at December 31, 2007. 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. 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.

The determination of depreciation, depletion and amortization expense recognized in the financial statements is also dependent upon the estimates of proved crude oil and natural gas reserves and is computed using the units-of-production method based upon this estimate of proved reserves. During the years ended December 31, 2009 and 2008, the Partnership had depreciation, depletion, and amortization expense totaling $306,507 and $232,436, respectively.

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 years ended December 31, 2009 and 2008 and the period from inception (November 27, 2007) to December 31, 2007, the Partnership recognized $0, $213,365, and $0 of asset retirement obligations and additional capitalized cost in connection with successful wells drilled by the Partnership.

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, 2009, 2008 and 2007, the Partnership had no material gas imbalance positions.

Recently Adopted Accounting Pronouncements

Modernization of Oil and Gas Reporting

In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule also changes certain accounting requirements under the full cost method of accounting for oil and gas activities. The changes are designed to modernize the requirements for the determination of crude oil and natural gas reserves, aligning them with current practices and updating them for changes in technology. The effect of applying the un-weighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12-month period, compared to the use of end-of-period prices and costs, decreased net proved reserves by 19.2%. The standardized measure of discounted future net cash flows for the year ended December 31, 2009 was lower by $1,648,610 as a result of using the new rule as compared to amounts calculated using the previous rules. The effect of applying the new rule resulted in increased depletion expense of $14,402 and increased impairment expense of $226,888.

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on the accounting standards codification and the hierarchy of generally accepted accounting principles. The accounting standards codification is intended to be the source of authoritative US GAAP and reporting standards as issued by the FASB. Its primary purpose is to improve clarity and use of existing standards by grouping authoritative literature under common topics. This accounting standards codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership now describes the authoritative guidance used within the footnotes but no longer uses numerical references. The accounting standards codification does not change or alter existing US GAAP, and there is no expected impact on the Partnership’s financial position, results of operations or cash flows.

Fair Value Measurement of Liabilities

In August 2009, the FASB issued new guidance for the accounting for the fair value measurement of liabilities. The new guidance provides clarification that in certain circumstances in which a quoted price in an active market for the identical liability is not available, a company is required to measure fair value using one or more of the following valuation techniques: the quoted price of the identical liability when traded as an asset, the quoted prices for similar liabilities or similar liabilities when traded as assets, and/or another valuation technique that is consistent with the principles of fair value measurements. The new guidance is effective for interim and annual periods beginning after August 27, 2009. The Partnership does not expect that the provisions of the new guidance will have a material effect on its results of operations, financial position or liquidity.

Subsequent Events

In May 2009, the FASB issued new guidance on accounting for subsequent events. This guidance established general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This guidance is effective for interim and annual reporting periods ending after June 15, 2009. The Partnership adopted the provisions of this guidance for the period ended June 30, 2009. In February 2010, the FASB issued an update to this guidance. Among other provisions, this update provides that an entity that is a SEC filer is not required to disclose the date through which subsequent events have been evaluated. The Partnership adopted the provisions on its effective date of February 24, 2010. There was no impact on the Partnership’s operating results, financial position or cash flows.

Recognition and Presentation of Other-Than-Temporary Impairments

In April 2009, the FASB issued new guidance related to the presentation and disclosure of other-than-temporary impairments on debt and equity securities. The new guidance amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. The guidance does not amend existing recognition and measurement guidance for equity securities, but does establish a new method of recognizing and reporting for debt securities. Disclosure requirements for impaired debt and equity securities have been expanded significantly and are now required quarterly, as well as annually. This guidance became effective for interim and annual reporting periods ending after June 15, 2009. Comparative disclosures are required for periods ending after the initial adoption. This guidance did not have an impact on the Partnership’s financial position, results of operations or cash flows.

Interim Reporting of Fair Value of Financial Instruments

In April 2009, the FASB issued new guidance related to the disclosure of the fair value of financial instruments. The new guidance amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for interim reporting periods. The guidance also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures about the fair value of financial instruments in summarized financial information at interim reporting periods. This guidance is effective for reporting periods ending after June 15, 2009. The adoption of this guidance did not have any impact on the Partnership’s results of operations, cash flows, or financial position.

Overview

The Partnership was organized as a Texas limited partnership on November 27, 2007. The offering of limited and general partner interests began November 27, 2007 and concluded May 31, 2008, with total non-Reef partner contributions of $88,648,094 and Reef contributions of $762,425. The Partnership commenced its business operations effective January 1, 2008.

The Partnership was formed to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties, subject to certain market conditions, no later than 2015, in order to maximize return to the partners of the Partnership. Reef is the managing general partner of the Partnership.

During 2008 and 2009, Partnership proceeds were used to purchase the Slaughter Dean Project and to develop the property and enhance the waterflood operations on the property by drilling new productive and water injection wells, converting old productive wells to water injection wells, reworking and re-activating existing wells, and by repairing, replacing, and expanding water pumping injection facilities and capacity. The Partnership plans to acquire properties in addition to the Slaughter Dean Project with the capital raised by the Partnership.

The Partnership has not borrowed funds during the development and waterflood enhancement of the Slaughter Dean Project. Interest income and oil and gas revenues, net of expenses, are being distributed to the partners. 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. The Partnership is also allowed to utilize cash flows from successful wells in order to drill additional development wells and construct facilities on properties purchased by the Partnership. The Partnership has no plans at this time to borrow funds.

Should the Partnership elect to borrow monies for additional development or waterflood activity on the Slaughter Dean Project, it will be subject to the interest rate risk inherent in borrowing activities. The Partnership is permitted but is not expected to engage in commodity futures trading or hedging activities, and therefore is subject to commodity price risk. See "Item 7A. – Quantitative and Qualitative Disclosures About Market Risk."

Liquidity and Capital Resources

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 397.0173 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. The Partnership was formed on November 27, 2007, and the last partner was admitted to the Partnership on May 31, 2008.

The Partnership’s cash flows are derived from the sales of crude oil and natural gas from Partnership wells. As a result, the Partnership’s cash flows are dependent upon the amount of crude oil and natural gas produced from its wells, as well as the prices of crude oil and natural gas. The Partnership expects oil and gas production and, as a result, cash flows, to increase during 2010 as it utilizes some of its remaining capital as of December 31, 2009 for the purchase of oil and gas properties outside of the Slaughter Dean Project, and as the initial response to the development and waterflood enhancements made to the Slaughter Dean Project are seen.

During 2008 and 2009, in connection with the development and waterflood enhancements made to the Slaughter Dean Project, the Partnership drilled 30 new oil wells, drilled 5 new waterflood injection wells, worked over and stimulated 4 old producing oil wells, and converted 22 old oil producing wells to waterflood injection wells. The Partnership has also repaired, replaced and expanded water pumping and injection facilities and capacity. Enhancement of waterflooding began in the second quarter of 2009 and is ongoing. A new water injection pump installed during March 2010 is expected to increase the water injection capacity of the Slaughter Dean Project to between 3,000-4,000 barrels of water per day in excess of the currently produced fluids. The gradual filling of the productive formation via this enhancement of waterflooding is expected to loosen and force out additional oil. Reef will continue to monitor the Project’s operations and expected response to the waterflood. As of the date of this report, no response to the waterflood enhancement has yet been seen. Should Reef determine that additional new oil or waterflood injection wells should be drilled, or any additional old oil producing wells should be converted to water injectors, the Partnership will conduct such operations using its remaining capital or shall fund such operations from its monthly cash flows. The Partnership has no plans at this time to borrow funds.

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

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of December 31, 2008:

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs

Purchase Existing Wells	$	15,371,780	$	-	$	-	$	15,371,780

New Wells
Producing Wells		76		22,364,049		-		22,364,125
Waterflood Injector Wells		-		3,020,777		-		3,020,777

Existing Wells		-		-		1,184,966		1,184,966

	$	15,371,856	$	25,384,826	$	1,184,966	$	41,941,648

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of December 31, 2009:

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs

Purchase Existing Wells	$	15,817,019	$	-	$	-	$	15,817,019

New Wells
Producing Wells		74		26,889,237		-		26,889,311
Waterflood Injector Wells		-		5,149,620		-		5,149,620
Facilities		-		1,495,913		-		1,495,913

Existing Wells		-		-		6,017,545		6,017,545

	$	15,817,093	$	33,534,770	$	6,017,545	$	55,369,408

The Partnership had cash and accounts receivable of $20,480,009 and $37,430,676 at December 31, 2009 and 2008, respectively, which includes interest income and net revenues available for distribution to partners. At December 31, 2009, the Partnership also had $794,669 of accounts payable and $245,090 of other current payables. At December 31, 2008, the Partnership also had $1,330,079 of accounts payable and $2,775,346 of other current payables.

The unproved properties owned by the Partnership at December 31, 2009 and 2008 consist of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project. The costs associated with the development and waterflood enhancement are considered unproved pending an initial reservoir production response.

Results of Operations

Year Ended December 31, 2009 compared to Year Ended December 31, 2008

The Partnership had a net loss of $1,547,077 for the year ended December 31, 2009, compared to net income of $937,233 for the year ended December 31, 2008.

Partnership revenues totaled $1,655,812 for the year ended December 31, 2009 compared to $2,012,489 for the comparable period in 2008. Volumes increased as the Partnership purchased additional ownership interests from Davric and Sierra Dean pursuant to its agreement with those entities. See “Item 1. Business – Summary of Material Contracts” for additional information. Increases in volumes were offset by steep declines in oil and gas prices during the comparable periods. Average oil prices decreased by 41% and average gas prices decreased by 49% during the year ended December 31, 2009 compared to the year ended December 31, 2008. Lease operating expenses increased from $1,190,395 for the year ended December 31, 2008 to $1,297,997 for the year ended December 31, 2009. This increase is due to the increase in working interest owned by the Partnership. Effective May 1, 2008, the Partnership purchased an additional 11% working interest from Davric. The Partnership also purchases additional interests in the Dean Units monthly from Sierra Dean as funds are advanced to pay costs.

Depreciation, depletion and amortization increased from $232,436 for the year ended December 31, 2008 to $306,507 for the year ended December 31, 2009, primarily due to increased production levels. Crude oil prices reached a low point for 2009 during the first quarter, and consequently the Partnership incurred first quarter 2009 property impairment cost of $441,542. During the fourth quarter of 2009, as a result of adopting the new SEC revisions to the oil and gas reporting disclosures, the Partnership incurred additional property impairment cost of $226,888. The standardized measure of discounted future net cash flows for the year ended December 31, 2009 decreased by $1,648,610 as a result of using the new rule.

General and administrative costs incurred during the years ended December 31, 2009 and 2008 increased from $247,455 in 2008 to $973,859 in 2009. This increase is primarily due to increased legal fees of approximately $155,000 related to regulatory filings and increased audit and accounting fees of approximately $175,000 related to financial reporting during 2009. In addition, direct costs charged to the Partnership increased by approximately $140,000 and overhead charges from Reef increased by approximately $200,000.

Year ended December 31, 2008 compared to Period of Inception (November 27, 2007) to December 31, 2007

Revenues and other income for the period from November 27, 2007 (date of inception) through December 31, 2007 totaled $28,208 and consisted solely of interest income. Revenues and other income for the period from January 1, 2008 to December 31, 2008 totaled $2,718,732 and consisted of oil and gas sales in the amount of $2,012,489 and interest income in the amount of $706,243. Oil production volume for the year ended December 31, 2008 totaled 23,060 Bbls of oil at a corresponding average realized price of $84.53 per Bbl of oil. Gas production volume during the year ended December 31, 2008 amounted to 21,466 Mcf of gas at a corresponding average realized price of $2.94 per Mcf of gas. Expenses for the period ended December 31, 2008, totaling $1,781,499 consisted partially of depreciation, depletion and amortization of $232,436. Lease operating expenses totaled $1,190,395 and production taxes were $94,106. Administrative and general expenses were $247,455 and asset retirement obligation accretion expense was $17,107. As of December 31, 2008, the Partnership had drilled 25 new oil wells, 3 new waterflood injection wells, and had worked over and stimulated 4 old producing oil wells.

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, 2009, 2008 and 2007, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.

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 *

—

* 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. 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.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk

The Partnership has not borrowed any funds to date. The Partnership Agreement allows borrowings from banks or other financial sources up to 30% of the aggregate capital contributions to the Partnership with the consent of the Investor Partners. Should the Partnership elect to borrow monies for additional development activity on Partnership properties, it will be subject to the interest rate risk inherent in borrowing activities. Changes in interest rates could significantly affect the Partnership’s results of operations and the amount of net cash flow available for partner distributions. Also, to the extent that changes in interest rates affect general economic conditions, the Partnership will be affected by such changes.

Commodity Price Risk

The Partnership has not and does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes. 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, 2009, a 10% change in the price received for our crude oil would have had an approximate $165,000 impact on the Partnership’s oil revenues, and a 10% change in the price received for the Partnership’s natural gas would have had an approximate $1,000 impact on our natural gas revenues.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The reports 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.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T).

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 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. Based on that evaluation, the principal executive officer and principal financial officer of our managing general partner have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our managing general partner, as appropriate to allow timely decisions regarding financial disclosure.

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 that the Partnership’s internal control over financial reporting was effective as of December 31, 2009.

This annual report does not include an attestation report of the Partnership’s 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 temporary rules of the SEC that permit the Partnership to provide only management’s report in this annual report.

Changes in Internal Controls

The Partnership became obligated to file periodic reports under the Securities & Exchange Act of 1934 as amended as a result of exceeding the threshold amount of assets and number of partners during the year ended December 31, 2008. The Partnership’s first filing, the Form 10, was due on April 30, 2009 (120 days after the closing of the fiscal year in which it reached the necessary thresholds). However, the Partnership was delinquent in its filings under the securities registration provisions of the Exchange Act regarding its Form 10.

Reef’s controller (the person in charge of the accounting system under which the financial books and records for the Partnership were maintained) left the Company in January of 2009, and the Company hired a new Chief Financial Officer (“CFO”) in mid-January 2009. The new CFO learned that the accounting system software utilized for partnerships other than the Partnership did not accommodate the accounting nuances involved in the Partnership. The CFO determined that the Partnership did not have adequate disclosure controls and procedures in place and assumed the primary task of creating and/or revamping the necessary systems, controls and accounting programs to allow for the integration and implementation of the Partnership’s books and records into an accounting system by which all Reef-partnerships’ financial books were maintained, bring the Partnership’s books and records in compliance, and to have the necessary financial records for audit by the outside independent auditors. Based upon the complexity of the accounting related to the Slaughter-Dean project and the accounting system limitations, the time available did not permit the manual bookkeeping system to be converted to the Company’s system in time for an audit to be commenced and completed by the filing deadline for Form 10.

The necessary accounting systems and programs of the Partnership were internally tested and the financial statements for the Partnership were subjected to an audit by the independent public accountants subsequent to the filing deadline. The Form 10 has now been filed and as of December 31, 2009, management believes that the necessary systems and programs are in place to avoid a reoccurrence of the issue with respect to the Partnership and further believes that any future filings will be timely made.

ITEM 9B.

OTHER INFORMATION

None.

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.

On January 4, 2010, Reef SWD 2007-A L.P., an affiliate of Reef for which Reef Oil & Gas Partners, L.P. is the managing general partner, instituted a Federal bankruptcy Chapter 11 proceeding in U.S. Bankruptcy Court, Northern District of Texas. On March 30, 2010, Reef SWD 2007-A, L.P., filed an application with the court to convert the Chapter 11 proceeding to a Chapter 7 proceeding under the U.S. Bankruptcy Code.

Name	Age	Positions and Offices Held
Michael J. Mauceli	53	Manager of Reef Oil & Gas Partners GP, LLC; Chief Executive Officer of RELP
H. Walt Dunagin	52	Executive Vice President and Land Manager of RELP
Byron H. Dean	60	Manager of Acquisitions and Divestitures of RELP
Daniel C. Sibley	58	Chief Financial Officer and General Counsel of RELP
L. Mark Price	47	Controller of RELP; Chief Financial Officer of Pure Reef, L.P.
David M. Tierney	57	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.

H. Walt Dunagin is Executive Vice President and Land Manager of RELP. He has held this position since January 2006 and has served in this position with its predecessor entity, OREI, since 1990. He is responsible for all contracts with other industry partners and all land activities required for exploration, development and production, including lease acquisition, title opinions, curative, permitting, unitization, rights-of-way and environmental issues. A graduate of the University of Mississippi in 1969 with a B.B.A. degree, Walt’s career has also involved land work for ExxonMobil, ChevronTexaco, UNOCAL, Santa Fe Energy and Oryx Energy (now Kerr-McGee). Walt is a member of the Dallas Association of Petroleum Landmen, the Association of International Petroleum Negotiators, and the American Association of Professional Landmen.

Byron H. (Howard) Dean is Manager – Acquisitions and Divestitures of RELP and is responsible for solicitation and technical evaluation of acquisition and development opportunities for Reef. A registered petroleum engineer, Mr. Dean has over 30 years of industry experience with oil and natural gas operations and reservoir engineering, both domestic onshore and offshore. Prior to joining RELP in 2006, Mr. Dean was Senior Petroleum Engineer and Acquisition and Divestiture Specialist for PLS, Inc. in 2006, and Senior Acquisitions Engineer of Noble Royalties, Inc. from 2004 to 2007. From 1998 to 2004, Mr. Dean was an engineering consultant to H&D Management, and from 1997 to 1998 he was Operations Manager for Hrubetz Oil Company. Mr. Dean served as Senior Staff Engineer for Coda Energy from 1988 to 1997and for Santa Fe Minerals from 1983 to 1988. He was Senior Reservoir Engineer for General American Oil Company from 1979 to 1983, worked for Amoco Production Company from 1974 to 1979, attaining the position of Senior Petroleum Engineer. He is a 1974 graduate of the University of Texas at Arlington with a Bachelor of Science degree in Civil Engineering. Mr. Dean is an active member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, ADAM Energy Forum, and Texas Independent Producer and Royalty Owners Association.

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 (L.L.M.) from Southern Methodist University in 1984. Mr. Sibley became a certified public accountant in 1977, but no longer maintains this license.

L. Mark Price is Controller of RELP and Chief Financial Officer of Pure Reef L.P., an affiliate of Reef. Mr. Price was appointed to his position with RELP in March 2010 and to his position with Pure Reef in October 2009. Mr. Price joined RELP in January 2009 as Chief Financial Officer of RELP. He served in that capacity until October 2009 when he became Chief Financial Officer of Pure Reef L.P. He has over twenty-two years of experience working in the oil and gas and manufacturing industries. He previously served as the Chief Financial Officer for The Terramar Group, Inc., an international oil and gas and manufacturing company, beginning in 2007. From 2004 to 2007, he served as the Chief Accounting Officer for Lancer Corporation, an international manufacturing company. Additionally, Mr. Price served as the Chief Financial Officer of Nunn Manufacturing, and for PCLC Asset Management after its acquisition of Nunn Manufacturing in 1998, from 1996 until 2004. Mr. Price received his BBA in accounting and finance from Texas Tech University in 1984 and is a licensed certified public accountant in the state of Texas. In October 2003, Mr. Price filed a personal bankruptcy petition under Chapter 7 in U.S. Bankruptcy Court, Northern District of Texas. On September 30, 2004, the court granted a discharge under §727 of the U.S. Bankruptcy Code.

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.

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 years ended December 31, 2009 and 2008, the Partnership paid a management fee of $0 and $13,320,000 respectively.

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, 2009 and 2008, the Partnership paid administrative fees of $896,880 and $700,706 respectively.

Recipient	Form of Compensation	Amount

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 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, 2009 and 2008, the Partnership paid a drilling compensation fee of $1,544,858 and $3,388,264 respectively.

Managing General Partner and its Affiliates	Direct costs	Reimbursement at cost. For the years ended December 31, 2009 and 2008, the Partnership paid direct costs of $475,747 and $0 respectively.

Managing General Partner and its Affiliates	Payment for equipment, supplies, marketing, and other services	Competitive prices. For the years ended December 31, 2009 and 2008, the Partnership paid no payments for equipment, supplies, marketing and other services.

Recipient	Form of Compensation	Amount

Managing General Partner and its Affiliates	Acquisition and Development Costs	Reimbursement at cost. For the years ended December 31, 2009 and 2008, the Partnership reimbursed the Managing General Partners and its affiliates for acquisition and development costs of $0 and $0 respectively.

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 related expenses. During the years ended December 31, 2009 and 2008 and during the period from inception (November 27, 2007) to December 31, 2007, Reef has received $49,050, $195,938 and $168, 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 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 year ended December 31, 2009, RELP received $1,544,858 in drilling compensation. During the year ended December 31, 2008, RELP received $3,388,264 in drilling compensation. During the period from inception (November 27, 2007) to December 31, 2007, neither Reef nor RELP received any drilling compensation. 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, 2009, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $475,747 and $38,208, respectively. However, during the year ended December 31, 2008 and the period from inception (November 27, 2007) to December 31, 2007, no reimbursements were made to Reef and its affiliates for direct and all documented out-of-pocket costs. Reef also receives 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 until the partnership is dissolved). During the years ended December 31, 2009 and 2008, Reef received $896,880 and $700,706, respectively, in administrative fees. Reef did not receive any administrative fees during the period from inception (November 27, 2007) to December 31, 2007. Administrative fees paid to Reef and its affiliates are included in general and administrative expenses in the financial statements. Reef’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by Reef or its affiliates that are necessary to the conduct of the partnership's business, whether generated by Reef, its affiliates or by third parties, but excluding direct costs and operating costs.

The Partnership also reimburses Reef and its affiliates for their costs relating to the acquisition of the oil and gas properties and for costs relating to the development of Partnership wells. No reimbursements of such costs were paid to Reef and its affiliates during the years ended December 31, 2009 and 2008 or during the period from inception (November 27, 2007) to December 31, 2007. Development costs include the cost of drilling, testing, completing, equipping, plugging, abandoning, deepening, plugging back, reworking, recompleting, fracturing, implementing waterflood activities, and similar activities on partnership wells which are not defined as routine operating costs. Acquisition costs include all reasonable and necessary costs and expenses incurred in connection with the acquisition of a property or arising out of or relating to the acquisition of properties, including but not limited to all reasonable and necessary costs and expenses incurred in connection with searching for, screening and negotiating the possible acquisition of properties for the Partnership, the conduct of reserve and other technical studies of properties for purposes of acquisition of a property, and the actual purchase price of a property and any other assets acquired with such property.

Reef and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment, and will be entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. RELP receives a monthly overhead reimbursement for general services it provides. These services include accounting, legal, risk management, and other administrative services as requested by the Partnership.

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, 2009 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.

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.”

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

	2009		2008
Audit fees	$	126,250	$	164,543
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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: April 2, 2010

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

By:	/s/ Michael J. Mauceli
Michael J. Mauceli
Manager (principal executive officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Michael J. Mauceli	Manager and Member of the general partner of Reef	April 2, 2010
Michael J. Mauceli	Oil & Gas Partners, L.P. (principal executive officer)

/s/ Daniel C. Sibley	Chief Financial Officer	April 2, 2010
Daniel C. Sibley	of Reef Exploration, L.P.
	(principal financial and accounting officer)

EXHIBIT INDEX

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 Form 10, SEC File No. 000-53795, as filed with the SEC on October 2, 2009).

4.1		Second Amended 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 Form 10, SEC File No. 000-53795, as filed with the SEC on 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 10.1 to Form 10, SEC File No. 000-53795, as filed with the SEC on 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 Form 10, SEC File No. 000-53795, as filed with the SEC on 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 Form 10, SEC File No. 000-53795, as filed with the SEC on 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 Form 10, SEC File No. 000-53795, as filed with the SEC on 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 Form 10, SEC File No. 000-53795, as filed with the SEC on October 2, 2009).

10.6		Consulting Agreement, dated September 1, 2006, by and between Reef Exploration, L.P. and William R. Dixon (incorporated by reference to Exhibit 10.6 to Form 10, SEC File No. 000-53795, as filed with the SEC on 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 Form 10, SEC File No. 000-53795, as filed with the SEC on October 2, 2009).

10.8		Purchase and Sale Agreement, dated January 19, 2010, by and between Azalea Properties Ltd. And RCWI, L.P. (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K, as filed with the SEC on January 22, 2010).

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 Form 8-K, as filed with the SEC on 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 10.3to the Partnership's Form 8-K, as filed with the SEC on 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 Form 8-K, as filed with the SEC on 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 Form 8-K, as filed with the SEC on January 22, 2010).

23.2		Consent of William M. Cobb & Associates, Inc.*

31.1		Certification of Principal Executive Officer pursuant to Rule 13a-14(a) under the 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 William M. Cobb & Associates, Inc.*

* Attached herewith

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

Financial Statements

Years Ended December 31, 2009 and 2008, and the period from November 17, 2007 (date of inception) to

December 31, 2007

Contents

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

Report of Independent Registered Public Accounting Firm

Partners

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

Dallas, TX

We have audited the accompanying balance sheets of Reef Oil & Gas Income and Development Fund III, L.P. (“the Partnership”) as of December 31, 2009 and 2008 and the related statements of operations, partnership equity, and cash flows for each of the two years in the period ended December 31, 2009 and the period from November 27, 2007 (date of inception) through December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Reef Oil & Gas Income and Development Fund III, L.P. at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2009 and the period from November 27, 2007 (date of inception) through December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, effective December 31, 2009, the Partnership changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

Dallas, Texas

April 2, 2010

F-1

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

Balance Sheets

December 31,	2009		2008

Assets
Current assets:
Cash and cash equivalents	$	18,243,848	$	34,549,487
Accounts receivable		736,161		671,889
Accounts receivable from affiliates		1,500,000		2,209,300
Prepaids and other current assets		-		507,640
Total current assets		20,480,009		37,938,316

Oil and gas properties, full cost method of accounting:
Accounting:
Proved properties, net of accumulated depletion of $1,207,373 and $232,436		2,364,672		3,339,609
Unproved properties		52,010,728		38,582,968
Net oil and natural gas properties		54,375,400		41,922,577

Total assets	$	74,855,409	$	79,860,893

Liabilities and partnership equity

Current liabilities:
Accounts payable	$	571,154	$	1,330,079
Accounts payable to affiliates		223,515		-
Accrued liabilities		245,090		2,775,346
Total current liabilities		1,039,759		4,105,425

Long term liabilities:
Asset retirement obligation		248,912		230,472
Total long term liabilities		248,912		230,472

Commitments and contingencies (Note 5)

Partnership equity
General partners		40,609,693		41,626,140
Limited partners		32,253,928		33,075,848
Managing general partner		703,117		823,008
Total partnership equity		73,566,738		75,524,996

Total liabilities and partnership equity	$	74,855,409	$	79,860,893

See accompanying notes to financial statements.

F-2

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

Statements of Operations

	As of and For the Years Ended December 31,					Period from inception (November 27, 2007) to December 31,
	2009			2008		2007)

Revenues	$	1,655,812		$	2,012,489	$	-

Costs and expenses:
Lease operating expenses		1,297,997			1,190,395		-
Production taxes		78,127			94,106		-
Depreciation, depletion and amortization		306,507			232,436		-
Accretion of asset retirement obligation		18,440			17,107		-
Property impairment		668,430			-		-
General and administrative		973,859			247,455		30,353
Total costs and expenses		3,343,360			1,781,499		30,353

Income (loss) from operations		(1,687,548	)		230,990		(30,353	)

Other income
Interest income		140,471			706,243		28,208
Total other income		140,471			706,243		28,208

Net income (loss)	$	(1,547,077	)	$	937,233	$	(2,144	)

Net income (loss) per general partner unit	$	(1,662.43	)	$	911.25	$	(38.91	)
Net income (loss) per limited partner unit	$	(1,662.43	)	$	911.25	$	(38.91	)
Net income (loss) per managing general partner unit	$	(7,897.79	)	$	14,275.84	$	2,266.11

See accompanying notes to financial statements.

F-3

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

Partner contributions		57.8753	$	4,933,466			75.9892	$	6,474,736			1.3522	$	137,530			135.2167	$	11,545,732
Partner distributions		-		(7,191	)		-		(9,442	)		-		(168	)		-		(16,802	)
Net loss		-		(2,252	)		-		(2,956	)		-		3,064			-		(2,144	)
Balance at December 31, 2007		57.8753	$	4,924,023			75.9892	$	6,462,338			1.3522	$	140,426			135.2167	$	11,526,786

Distribution amount per partnership unit			$	124.25				$	124.25				$	124.24

Balance at December 31, 2007		57.8753	$	4,924,023			75.9892	$	6,462,338			1.3522	$	140,426			135.2167	$	11,526,786
Partner contributions		433.1074		37,136,799			321.0280		26,965,003			7.6175		750,470			761.7529		64,852,272
Partner distributions		-		(882,086	)		-		(713,271	)		-		(195,938	)		-		(1,791,295	)
Net loss		-		447,404			-		361,779			-		128,050			-		937,233
Balance at December 31, 2008		490.9827	$	41,626,140			397.0172	$	33,075,848			8.9697	$	823,008			896.9696	$	75,524,996

Distribution amount per partnership unit			$	1,796.57				$	1,796.57				$	21,844.43

Balance at December 31, 2008		490.9827	$	41,626,140			397.0172	$	33,075,848			8.9697	$	823,008			896.9696	$	75,524,996
Partner distributions		-		(200,224	)		-		(161,907	)		-		(49,050	)		-		(411,181	)
Net loss		-		(816,223	)		-		(660,013	)		-		(70,841	)		-		(1,547,077	)
Balance at December 31, 2009		490.9827	$	40,609,693			397.0172	$	32,253,928			8.9697	$	703,117			896.9696	$	73,566,738

Distribution amount per partnership unit			$	407.79				$	407.81				$	5,468.41

See accompanying notes to financial statements.

F-4

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

Statements of Cash Flows

	For the Years Ended December 31,						Period from inception (November 27, 2007) to December
	2009			2008			31, 2007

Operating activities
Net income (loss)	$	(1,547,077	)	$	937,233		$	(2,144	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		306,507			232,436			-
Accretion of asset retirement obligation		18,440			17,107			-
Property impairment		668,430			-			-
Changes in operating assets and liabilities
Accounts receivable		(64,272	)		(671,889	)		-
Accounts receivable from affiliates		709,300			(2,209,300	)		-
Prepaid expenses		507,640			(507,640	)		-
Accounts payable		(900,104	)		277,948			16,802
Accounts payable to affiliates		154,790			(119,920	)		119,920
Accrued liabilities		(2,636,425	)		104,492			-

Net cash provided by (used in) operating activities		(2,782,771	)		(1,939,533	)		134,578

Investing activities:
Purchase of oil & gas properties		(80,758	)		(15,260,041	)		-
Property development		(12,951,445	)		(22,943,170	)		(111,739	)

Net cash used in investing activities		(13,032,203	)		(38,203,211	)		(111,739	)

Financing activities:
Proceeds from the sale of partnership interest		-			76,109,019			13,578,985
Distributions to partners		(490,665	)		(1,711,811	)		(16,802	)
Syndication costs		-			(11,256,747	)		(2,033,253	)

Net cash provided by (used in) investing activities		(490,665	)		63,140,461			11,528,930

Net increase (decrease) in cash and cash equivalents		(16,305,639	)		22,997,717			11,551,769
Cash and cash equivalents, beginning of year		34,549,487			11,551,769			-

Cash and cash equivalents, end of year	$	18,243,848		$	34,549,487		$	11,551,769

Supplemental disclosure of non-cash investing transactions
Property additions included in accounts payable	$	(141,179	)	$	(1,035,331	)	$	-
Property additions included in accounts payable to affiliates	$	(68,725	)	$	0		$	-
Property additions included in accrued liabilities	$	(185,653	)	$	(2,821,842	)	$	-
Supplemental disclosure of non-cash financing transactions
Distributions included in accrued liabilities	$	-		$	79,484		$	-

See accompanying notes to financial statements.

F-5

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

Notes to Financial Statements

1. Organization and Basis of Presentation

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.

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 primarily 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”), and is not involved in any other industry segment. The Partnership will participate in developmental drilling and not exploratory drilling. To the extent any acreage the Partnership acquires contains unproved reserves, such acreage may be farmed out or sold to third parties or other partnerships formed by Reef for exploratory drilling.

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 Partnership’s interests in 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 a producing oil property located in the Slaughter Dean Project and under the terms of the acquisition agreement, each month thereafter purchases additional working interests based on the amount the Partnership spends developing the project through January 2013. Under the acquisition agreement the Partnership generally pays 82% of all drilling, development and repair costs (including amounts allocable to the working interest initially retained by Sierra Dean), and Sierra Dean conveys additional working interests to the Partnership each month in 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. 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.

F-6

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

Notes to Financial Statements (continued)

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.

Crude Oil and Natural Gas Properties

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

In applying the full cost method at December 31, 2009, 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, for 2009. 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 alter the rate of depletion and amortization. During the years ended December 31, 2009 and 2008, the Partnership recognized property impairment expense of proved properties of $668,430 and $0, respectively. The Partnership had no proved property at December 31, 2007.

Unproved property consists of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project. The costs associated with the development and waterflood enhancement project are considered unproved pending an initial reservoir production response. 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 data obtained from the waterflood operations of the Slaughter Dean Property. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the years ended December 31, 2009 and 2008, the Partnership recognized no property impairment expense of unproved properties. The Partnership had no unproved property at December 31, 2007.

F-7

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

Notes to Financial Statements (continued)

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at December 31, 2009 have been prepared and presented in accordance with new SEC rules and accounting standards. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting entities to prepare their reserve estimates using revised reserve definitions and revised 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. Estimates of the Partnership’s proved reserves at December 31, 2008 have been prepared and presented using previous SEC rules and accounting standards that required pricing based upon end-of-period commodity prices and 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. Our 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.

The adoption of the new SEC rules and accounting standards at December 31, 2009 resulted in a downward adjustment of $1,648,610 to the estimated discounted future cash flows from proved reserves, and in a reduction of 29,820 BOE equivalent of proved reserves. Additionally, the change resulted in increases of $14,402 and $226,888 in depletion and impairment expense, respectively, in the fourth quarter of 2009.

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.

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. Upon settlement of the obligation a gain or loss is recognized to the extent actual charges are less than or exceed the liability recorded.

The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2009 and 2008.

	2009		2008
Beginning asset retirement obligation	$	230,472	$	—
Additions related to new properties		—		213,365
Accretion expense		18,440		17,107
Ending asset retirement obligation	$	248,912	$	230,472

Recognition of Revenue

The Partnership enters into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenues are 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, 2009, 2008, and 2007.

F-8

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

Notes to Financial Statements (continued)

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, 2009, the financial reporting basis of the Partnership’s assets exceeds the tax basis of the assets by approximately $23.5 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

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 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, disclosure and transition.

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, 2009.

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 and accounts payable approximates their carrying value due to their short-term nature.

Recently Adopted Accounting Pronouncements

Modernization of Oil and Gas Reporting

In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule requires disclosure of crude oil and natural gas proved reserves by geographical area, using the un-weighted arithmetic average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period prices, and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. In addition, in January 2010, the FASB issued guidance relating to crude oil and natural gas reserve estimation and disclosures to provide consistency with the new SEC rules. The Partnership adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. The effect of applying the un-weighted arithmetic average of first-day-of-the-month commodity prices over the preceding 12-month period, versus applying the 2009 end-of-period price, decreased net proved reserves by 19.2%. The standardized measure of discounted future net cash flows for the year ended December 31, 2009 was lower by $1,648,610 using the new rule as compared to amounts calculated using the previous rules. The effect of applying the new rule resulted in increased depletion expense of $14,402 and increased impairment expense of $226,888.

F-9

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

Notes to Financial Statements (continued)

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on the accounting standards codification and the hierarchy of generally accepted accounting principles. The accounting standards codification is intended to be the source of authoritative US GAAP and reporting standards as issued by the FASB. Its primary purpose is to improve clarity and use of existing standards by grouping authoritative literature under common topics. The accounting standards codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Partnership now describes the authoritative guidance used within the footnotes but no longer uses numerical references. The accounting standards codification does not change or alter existing US GAAP, and there has been no expected impact on the Company’s financial position, results of operations or cash flows.

Fair Value Measurement of Liabilities

Subsequent Events

Recognition and Presentation of Other-Than-Temporary Impairments

F-10

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

Notes to Financial Statements (continued)

Interim Reporting of Fair Value of Financial Instruments

3. Transactions with Affiliates

Reef received a payment equal to 15% ($13,320,000, less $151,906 of unpaid net asset values) of the Partnership's subscriptions. From this payment, Reef paid organization and offering costs of $30,000 to the Partnership, as well as commissions of $7,449,426. Reef recorded the excess ($5,688,668) of such amount over actual costs as a one-time management fee.

Reef also received an 11% interest in the Partnership for which it pays 1% of all costs related to the Partnership; the additional 10% is "carried" by the Investor Partners and for which Reef will pay no related expenses. During the years ended December 31, 2009 and 2008 and the period from inception (November 27, 2007) to December 31, 2007, Reef received $49,050, $195,938 and $168, 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 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 development Partnership. 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 appropriate 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. During the years ended December 31, 2009 and 2008 and the period from inception (November 27, 2007) to December 31, 2007, RELP has received $1,544,858, $3,388,264 and $0, respectively, in drilling compensation. Drilling compensation is included in oil and gas properties in the financial statements.

RELP receives 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. During the years ended December 31, 2009 and 2008 and the period from inception (November 27, 2007) to December 31, 2007, Reef has received $896,880, $700,706 and $0, respectively, in administrative fees. Administrative fees are included in general and administrative expense in the financial statements. Reef’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by Reef or its affiliates that are necessary to the conduct of the Partnership's business, whether generated by Reef, its affiliates or by third parties, but excluding direct costs and operating costs.

The Partnership also reimburses Reef and its affiliates for their costs relating to the acquisition of the oil and gas properties and for costs relating to the development of Partnership wells. During the years ended December 31, 2009 and 2008 and from inception (November 27, 2007) to December 31, 2007, Reef and its affiliates have received no reimbursement for such costs. Development costs include the cost of drilling, testing, completing, equipping, plugging, abandoning, deepening, plugging back, reworking, recompleting, fracturing, implementing waterflood activities, and similar activities on partnership wells which are not defined as routine operating costs. Acquisition costs include all reasonable and necessary costs and expenses incurred in connection with the acquisition of a property or arising out of or relating to the acquisition of properties, including but not limited to all reasonable and necessary costs and expenses incurred in connection with searching for, screening and negotiating the possible acquisition of properties for the Partnership, the conduct of reserve and other technical studies of properties for purposes of acquisition of a property, and the actual purchase price of a property and any other assets acquired with such property.

F-11

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

Notes to Financial Statements (continued)

4. 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. Prior to December 31, 2007, the Partnership had no crude oil and natural gas production and, therefore, had no customers. During the years ended December 31, 2009 and 2008, one marketer accounted for all of the Partnership’s crude oil revenues, and one marketer accounted for all of the Partnership’s natural gas revenues. During 2008 and 2009, the Partnership’s only oil and gas property was the Slaughter Dean Project located in Cochran County, Texas. Reef has chosen to sell the Partnership’s crude oil and natural gas to two subsidiaries of a large international oil and gas company because of the price they pay, the promptness with which they pay, and their credit worthiness indicated by their publicly filed financial statements. There are other large companies (or subsidiaries thereof) active in purchasing crude oil and natural gas in the area of the Slaughter Dean Property, including Exxon, Royal Dutch Shell, Plains All American Pipeline, Conoco-Phillips, Genesis Energy, and Holly Energy. There are also several smaller companies that purchase and re-sell crude oil. 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 the current purchaser would have a material adverse impact on the Partnership.

The Partnership does not use long-term contracts to sell crude oil or natural gas produced on the Slaughter Dean Property. Prices received for our crude oil production are based upon “posted” prices for West Texas Intermediate grade crude oil. The Partnership's contracts generally provide for a 30-day termination notice by either party. As a result, there should be limited cost, delay or inconvenience in the event the Partnership replaces an oil and gas purchaser.

5. Commitments and Contingencies

The Partnership is not currently involved in any legal proceedings.

6. 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, 2009 and 2008 and the period from inception (November 27, 2007) through December 31, 2007, is detailed below:

For the year ended December 31, 2009

Type of Unit	Number of Units		Net loss			Net loss per unit
Managing general partner		8.9697	$	(70,841	)	$	(7,897.79	)
General partner		490.9827		(816,223	)	$	(1,662.43	)
Limited partner		397.0172		(660,013	)	$	(1,662.43	)
Total		896.9696	$	(1,547,077	)

F-12

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

Notes to Financial Statements (continued)

For the year ended December 31, 2008

Type of Unit	Number of Units		Net income		Net income per unit
Managing general partner		8.9697	$	128,050	$	14,275.84
General partner		490.9827		447,404	$	911.25
Limited partner		397.0172		361,779	$	911.25
Total		896.9696	$	937,233

For the period from inception through December 31, 2007

Type of Unit	Number of Units		Net income (loss)			Net income (loss) per unit
Managing general partner		1.3522	$	3,064		$	2,266.11
General partner		57.8753		(2,252	)	$	(38.91	)
Limited partner		75.9892		(2,956	)	$	(38.91	)
Total		135.2167	$	(2,144	)

7. Subsequent Events

On January 19, 2010, RCWI , L.P. (“RCWI”) 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”) at the beginning of the periods presented. The Azalea Purchase Agreement is 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”).

The following unaudited pro forma condensed consolidated statements of revenue and earnings for the years ended December 31, 2009 and 2008 are presented as if the acquisition 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 Azalea acquisition had occurred at the dates presented or of our future financial position or results of operations. In addition the results may vary significantly from the results reflected in such statements due to normal oil and gas production declines, reductions in prices paid for oil and gas, future acquisitions and other factors.

F-13

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

Notes to Financial Statements (continued)

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF REVENUE AND EARNINGS

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

Revenues	$	4,219,565		$	6,456,431
Net loss	$	(4,272,297	)	$	(11,270,531	)

Net loss per general partner unit	$	(4,903.11	)	$	(13,099.73	)
Net loss per limited partner unit	$	(4,903.11	)	$	(13,099.73	)
Net income per managing general partner unit	$	8,881.85		$	40,361.38

8. 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, 2009			December 31, 2008			December 31, 2007

Oil and natural gas properties:
Unproved properties	$	52,010,728		$	38,582,968		$	111,739
Proved properties		3,358,680			3,358,680			—
Capitalized asset retirement obligation		213,365			213,365			—
		55,582,773			42,155,013			111,739
Less:
Accumulated depreciation, depletion and amortization		(538,943	)		(232,436	)		—
Property impairment		(668,430	)		—			—
		(1,207,373	)		(232,436	)		—

Total	$	54,375,400		$	41,922,577		$	111,739

F-14

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

Notes to Financial Statements (continued)

Costs Withheld from Amortization

The Partnership excludes from amortization the cost of unproved properties and major development projects in progress. Oil and gas property and equipment not being amortized as of December 31, 2009, 2008, and 2007 are as follows by the year in which such costs were incurred:

	Total		2009		2008		2007
Acquisition costs	$	12,013,174	$	—	$	11,901,435	$	111,739
Development costs		33,518,369		10,929,932		22,588,437		—
Capitalized overhead		6,479,185		2,497,828		3,981,357		—
	$	52,010,728	$	13,427,760	$	38,471,229	$	111,739

Costs Incurred

The following table sets forth the costs incurred in oil and gas exploration and development activities during the periods ended December 31, 2009, 2008, and 2007.

	2009		2008		2007

Oil and natural gas properties:
Exploration	$	—	$	—	$	—
Development		10,929,932		22,588,437		—
Total	$	10,929,932	$	22,588,437	$	—

Results of Operations

The following table sets forth the other results of operations from oil and gas producing activities for the periods ended December 31, 2009 and 2008. There were no operating activities during 2007.

	2009			2008

Oil and gas producing activities:
Oil sales	$	1,645,056		$	1,949,274
Natural gas sales		10,756			63,215
Production expenses		(1,376,124	)		(1,284,501	)
Accretion of asset retirement obligation		(18,440	)		(17,107	)
Depreciation, depletion and amortization		(306,507	)		(232,436	)
Property impairment		(668,430	)
Results of operations from producing activities	$	(713,689	)	$	478,445

Depletion rate per BOE	$	8.90		$	9.68

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

F-15

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

Notes to Financial Statements (continued)

Crude Oil and Natural Gas Reserves

Recent SEC and FASB Rule Making Activity

In January 2009, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The Partnership adopted the rules effective December 31, 2009, and the rule changes, including those related to pricing and technology, are included in the Partnership’s reserve estimates. See Note 2, “Summary of Significant Accounting Policies – Modernization of Oil and Gas Reporting.”

In accordance with new SEC rules, estimates of the Partnership’s proved reserves and future net revenues are made using the un-weighted arithmetic average of first-day-of-the-month commodity prices over the preceding 12 month period for the year ended December 31, 2009. These prices are held constant in accordance with SEC guidelines for the economic life of the wells included in the reserve report but are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by crude oil and natural gas prices, which have fluctuated significantly in recent years.

The new rules resulted in the use of lower prices at December 31, 2009 for both crude oil and natural gas than would have been used under the previous rules, and resulted in a downward adjustment of approximately 29,820 BOE to our proved reserves as of December 31, 2009, as compared to the old end-of-period prices rule.

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 firms William M. Cobb & Associates as of December 31, 2009 and 2008. A copy of the William M. Cobb & Associates summary reserve report is included as Exhibit 99.1 to this Annual Report. 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, 2009, 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, 2009 and 2008. The Partnership had no proved crude oil and natural gas reserves at December 31, 2007.

	Oil (BBL) (1)			Gas (mcf)			BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2007		—			—			—
Purchases of reserves in place		331,656			224,048			368,997
Production		(23,354	)		(3,939	)		(24,010	)
Reserves at December 31, 2008		308,302			220,109			344,987

Revisions of previous estimates (3)		(160,667	)		(146,845	)		(185,141	)
Production		(33,235	)		(7,204	)		(34,436	)
Reserves at December 31, 2009		114,400			66,060			125,410

F-16

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

Notes to Financial Statements (continued)

(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.

(3)	Revisions of previous estimates include the effects of the modernization of oil and gas reporting rules. See Footnote 2, “Summary of Significant Accounting Policies – Modernization of Oil and Gas Reporting,” for further information.

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 year ended December 31, 2009, future cash inflows are computed by applying the new SEC pricing, which holds constant the un-weighted arithmetic average of the first-day-of-the-month prices for crude oil and natural gas over the preceding 12-month period as the price basis for estimating the Partnership’s proved reserves. For the year ended December 31, 2009, calculations were made using average prices of $58.19 per barrel of crude oil and $1.57 per MCF of natural gas. For the year ending December 31, 2008, future cash inflows were computed by applying the former SEC pricing rules, which hold constant the end-of-year price for crude oil and natural gas as the price basis for estimating the Partnership’s proved reserves. During 2008, the calculations were made using average prices of $45.13 per barrel of oil and $2.16 per MCF of natural gas. 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.

The adoption of the new SEC rules and accounting standards at December 31, 2009 resulted in a downward adjustment of $1,648,610 to the estimated discounted future cash flows from proved reserves, and in a reduction of 29,820 BOE equivalent of proved reserves. See Note 2, “Summary of Significant Accounting Policies – Modernization of Oil and Gas Reporting.”

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 their present worth. 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.

The standardized measure of discounted future net cash flows as of December 31, 2009 and 2008 were as follows:

	December 31,2009			December 31, 2008
Future cash inflows	$	6,761,420		$	14,389,086
Future production costs		(3,482,310	)		(7,377,434	)
Future development costs		—			—
Future net cash flows		3,279,110			7,011,652
Effect of discounting net cash flows at 10%		(906,310	)		(2,527,910	)
Discounted future net cash flows	$	2,372,800		$	4,483,742

F-17

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

Notes to Financial Statements (continued)

Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Natural Gas Reserves

	December 31,2009			December 31, 2008
Standardized measure at beginning of period	$	4,483,742		$	—
Purchases of minerals in place		—			5,211,730
Net change in sales price, net of production costs		(1,516,341	)		—
Revisions of quantity estimates		(1,231,016	)		—
Changes in production timing rates		449,289			—
Accretion of discount		448,374			—
Sales net of production costs		(261,248	)		(727,988	)
Net increase (decrease)		(2,110,942	)		4,483,742
Standardized measure at end of year	$	2,372,800		$	4,483,742

F-18

Attached files

Reef Oil & Gas Income & Development Fund III LP Reports

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