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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**Form 10-K**

 

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**(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, 2010**

 

**or**

 

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

 

**For the Transition period from                to               **

 

**COMMISSION FILE NUMBER 000-53795**

 

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

(Exact name of registrant as specified in its charter)

** **

| **Texas**                                                        | ** ** | **26-0805120**                         |
|------------------------------------------------------------------|------------|----------------------------------------|
| (State or other jurisdiction of   incorporation or organization) |       | (I.R.S. Employer   Identification No.) |

 

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

(Address of principal executive offices including zip code)

 

**(972)-437-6792**

(Registrant’s telephone number, including area code)

 

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

 

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

 

**General and Limited Partnership Interests**

(Title of Class)

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o No o

 

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

 

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

 

| Large accelerated filer o |   | Accelerated filer o         |
|---------------------------|--------|-----------------------------|
|                      |   |                        |
| Non-accelerated filer o   |   | Smaller reporting company x |

 

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

 

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

 

As of April 15, 2011, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest held by the managing general partner, and 397.0172 units of limited partner interest outstanding.

 

Documents incorporated by reference:  None

 

 

 

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

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2010

TABLE OF CONTENTS

 
| **Part I**   | ** **                                                                                                            | ** ** |
|-------------------|-----------------------------------------------------------------------------------------------------------------------|------------|
| ** **        | ** **                                                                                                            | ** ** |
| Item 1.           | Business                                                                                                              |       |
| Item 1A.          | Risk Factors                                                                                                          |       |
| Item 1B.          | Unresolved Staff Comments                                                                                             |       |
| Item 2.           | Properties                                                                                                            |       |
| Item 3.           | Legal Proceedings                                                                                                     |       |
| Item 4.           | (Removed and Reserved)                                                                                                |       |
|              |                                                                                                                  |       |
| **PART II**  |                                                                                                                  |       |
|              |                                                                                                                  |       |
| Item 5.           | Market for Registrant’s   Common Equity, Related Stockholder Matters and Issuer Purchases of Equity   Securities |       |
| Item 6.           | Selected Financial Data                                                                                               |       |
| Item 7.           | Management’s Discussion and Analysis of   Financial Condition and Results of Operations                          |       |
| Item 7A.          | Quantitative and   Qualitative Disclosure About Market Risk                                                           |       |
| Item 8.           | Financial Statements and   Supplementary Data                                                                         |       |
| Item 9.           | Changes in and   Disagreements with Accountants on Accounting and Financial Disclosure                                |       |
| Item 9A.          | Controls and Procedures                                                                                               |       |
| Item 9B.          | Other Information                                                                                                     |       |
|              |                                                                                                                  |       |
| **PART III** |                                                                                                                  |       |
|              |                                                                                                                  |       |
| Item 10.          | Directors, Executive   Officers and Corporate Governance                                                              |       |
| Item 11.          | Executive Compensation                                                                                                |       |
| Item 12.          | Security Ownership of   Certain Beneficial Owners and Management and Related Stockholder Matters                      |       |
| Item 13.          | Certain Relationships and   Related Transactions, and Director Independence                                           |       |
| Item 14.          | Principal Accountant Fees   and Services                                                                              |       |
|              |                                                                                                                  |       |
| **PART IV**  |                                                                                                                  |       |
|              |                                                                                                                  |       |
| Item 15.          | Exhibits and Financial Statement Schedules                                                                            |       |
|              | Signatures                                                                                                            |       |

 

**PART I**

 

**ITEM 1.**  **BUSINESS**

 

**Introduction**

 

Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) is a limited partnership formed under the laws of Texas on November 27, 2007. The 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

 

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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 (“Azalea Acquired 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.

 

In June 2010, the Partnership acquired certain working interests in oil and gas properties (“Lett Acquired Properties”) located in the Thums Long Beach Unit, which include approximately 870 producing wells and 485 injection wells.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.  The acquired working interests represent a minority interest in this unit, which is not operated by Reef or any of Reef’s affiliates. For further information on the Lett Acquired Properties, see “Summary of Material Contracts — Lett Purchase Agreement” below.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties located in Wheeler County, Texas and Roger Mills County, Oklahoma, as well as interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives described above, the Partnership does not intend to participate in exploratory drilling activities.  The Partnership’s interests in these properties were originally acquired in January 2010 through the RCWI Agreement. For further information on these transactions, see “Property Acquisition and Development” below.

 

**Property Acquisition and Development**

 

*Slaughter Dean Project*

 

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 has developed 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.

 

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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.

 

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.  During the year ended December 31, 2010, the Partnership installed an additional injection pump to increase injection volume. Prior to the Partnership’s purchase of the Slaughter Dean Project, only the water produced with the crude oil was being injected back into the oil producing formation.  Currently, approximately 6,100 barrels of water are being injected back into the oil producing formation per day.   The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil. The actual results to date of the Partnership’s waterflood operations have not produced the desired production of additional oil. The Slaughter Dean Project was producing approximately 110 barrels of crude oil and 4,300 barrels of water per day as of December 31, 2010, compared to approximately 110 barrels of crude oil and 3,700 barrels of water per day as of December 31, 2009.

 

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

 

The Partnership has expended approximately $56.5 million and $55.4 million on the Slaughter Dean Project as of December 31, 2010 and December 31, 2009, respectively.  The Partnership is currently monitoring the implementation of waterflood operations and daily production of total fluids (oil and water), which are less than the total water injected each day to determine the cause of the underperformance of the waterflood operations. The Partnership may gather additional data in order to determine whether alternate configurations of water injection wells may be more effective in producing a better waterflood response in the future, though such alternative configurations may be costly to the Partnership to implement. In the event that the Partnership determines, based on its monitoring activities, that additional or alternative configurations of water injection wells will not materially increase production from the Slaughter Dean Project, the Partnership may decide not to pursue such activities. 

 

*Azalea Acquired Properties*

 

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

 

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Subsequently, RCWI entered into a Purchase and Sale Agreement with the Partnership dated January 19, 2010 to sell portions of the working interests acquired from Azalea Properties Ltd. to the Partnership.  The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties Ltd. for a purchase price of $13,182,171 in cash subject to post-closing adjustments.  RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Acquired Properties cover more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset locations.  The acquired working interests represent minority non-operated interests.  The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef. Approximately $10.7 million of the purchase price is associated with proved developed reserves.

 

On June 15, 2010, Reef Oil & Gas Income and Development Fund IV (“Income Fund IV”) paid $1,252,844 to Azalea Properties Ltd. for the post closing settlement related to the Side Letter Agreements which were a part of the original Azalea Purchase Agreement. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post closing settlement amount. There was no additional payment for undeveloped properties; the entire post closing settlement is associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

 

*Lett Acquired Properties*

 

On June 23, 2010, RCWI entered into a Purchase and Sale Agreement (the “Lett Purchase Agreement”) with Lett Oil & Gas, L.P. for certain proved developed oil and gas properties owned by Lett Oil & Gas, L.P. for a purchase price of $6,000,000.  The Lett Acquired Properties are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.   The oil and gas properties included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010. Revenues and expenses related to June 2010 are treated as a purchase price adjustment.

 

*Sales of Interests — Granite Wash Formation*

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Granite Wash formation located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were initially acquired as part of the Azalea Acquired Properties, and were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved. In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled.  The Partnership received a cash payment of $933,300 during December 2010 in exchange for these interests.

 

*Sale of Interests — Lusk Field*

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were initially acquired as part of the Azalea Acquired Properties, and were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities.  The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled.  The Partnership received $59,455 in exchange for these interests, which is included in accounts receivable from affiliates on the balance sheet as of December 31, 2010. This amount has been paid in cash to the Partnership during the first quarter of 2011.

 

**Major Customers**

 

The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the

 

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operator of the property who disburses to the Partnership its percentage share of the revenues.  During the year ended December 31, 2010, one marketer accounted for 39.5% and one operator accounted for 20.8% of the Partnership’s crude oil and natural gas revenues.  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. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

 

**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 including, without limitation, blowouts, lost circulation, and stuck drillpipe that may result in unanticipated additional liability materially in excess of a general partner’s investment in the Partnership.

 

RELP has obtained various insurance policies, as described below, and intends to maintain such policies subject to its analysis of their premium costs, coverage and other factors. In the exercise of its fiduciary duty as managing general partner, Reef has obtained insurance on behalf of the Partnership to provide the Partnership with coverage Reef believes is sufficient to protect 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 RELP for its share of the insurance premium.  The following types and amounts of insurance have been maintained:

 

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

 

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

 

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

 

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

 

·              Energy exploration and development liability (including well control, environmental and pollution

 

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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 both the acquisition of producing oil and gas properties, as well as the exploration for and production of crude oil and natural gas.  Reef expects the Partnership to encounter strong competition at every phase of business.  The Partnership competes with entities having financial resources and staffs substantially larger than those available to it.

 

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

 

·      the amount of crude oil and natural gas imports;

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

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

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

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

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

 

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

 

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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.

 

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

 

*Proposed Regulation*. Various legislative proposals are being considered in Congress and in the legislatures of various states, which, if enacted, may significantly and adversely affect the petroleum and natural gas industries. Such proposals involve, among other things, the imposition of price controls on all categories of natural gas production, the imposition of land use controls, such as prohibiting drilling activities on certain federal and state lands in protected areas, as well as other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals will have on the Partnership’s operations.

 

**Employees**

 

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

 

**Summary of Material Contracts**

 

*Operating Agreements.*

 

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

 

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

 

*Slaughter Dean Purchase Agreement.*

 

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

 

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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 approximately 13.5% and 20.8%, respectively.  The Partnership initially owned a 50.0% working interest (with a 33.9% net revenue interest) in the Dean “K” Lease.  The Dean “K” Lease accounts for 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, 2010, the Partnership owned the approximate interests shown as follows:

 
| ** **               | ** ** | **Working**  | ** ** | **Revenue**  | ** ** |
|--------------------------|------------|--------------|------------|--------------|------------|
| ** **               | ** ** | **Interest** | ** ** | **Interest** | ** ** |
| Dean Unit                |       | 75.7         | %          | 64.6         | %          |
| Dean “B” Unit  |       | 75.7         | %          | 59.9         | %          |
| Dean “K” Lease |       | 78.9         | %          | 53.5         | %          |

 

As of December 30, 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         | %          |

 

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*RCWI Agreement*

 

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

 

Subsequently, RCWI entered into the RCWI Agreement, dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties Ltd. to the Partnership.  The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties Ltd. for a purchase price of $13,182,171 in cash subject to post-closing adjustments.  RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Acquired Properties cover more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset locations.  The acquired working interests represent minority non-operated interests.  The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef. Approximately $10.7 million of the purchase price is associated with proved developed reserves.

 

On June 15, 2010, Income Fund IV, an affiliate of Reef, paid $1,252,844 to Azalea Properties Ltd. for the post closing settlement related to the Side Letter Agreements which were a part of the original Azalea Purchase Agreement. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post closing settlement amount. There was no additional payment for undeveloped properties; the entire post closing settlement is associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

 

*Lett Purchase Agreement*

 

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

 

*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 only.

 

**FORWARD LOOKING STATEMENTS**

 

This Annual Report contains forward-looking statements that involve risks and uncertainties.  You should exercise extreme caution with respect to all forward-looking statements made in this Annual Report.  Specifically, the following statements are forward-looking:

 

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

 

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

 

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

 

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

 

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

 

·                                          any statements of other than historical fact.

 

Reef believes that it is important to communicate its future expectations to the non-Reef general and limited investor partners (“investor partners”).  Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the factors listed in ITEM 1A. of this Annual Report captioned, “RISK FACTORS.”  Although Reef believes that the expectations reflected in such forward-looking statements are reasonable, Reef can give no assurance that such expectations will prove to have been correct.  Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein.  There can be no assurance that the projected results will occur, that these judgments or assumptions will prove correct or that unforeseen developments will not occur.

 

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

** **

**ITEM 1A.****              ****RISK FACTORS**

 

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

 

***The waterflood operations 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.  During 2010, the Partnership installed an additional injection pump to increase injection volume. The Partnership has also repaired, replaced, and expanded water pumping and injection facilities and capacity.   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.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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***The e******ffect of borrowing and other financing may negatively impact partnership distributions.***

 

Net proceeds from the sale of units in the Partnership were used to acquire interests in the Slaughter Dean Project and execute the waterflood operations work plan, including drilling new oil wells within the Slaughter Dean Project and providing necessary production equipment and facilities to service such oil and gas wells.  Net proceeds from the sale of units in the Partnership were also used in connection with the acquisition of the Azalea Acquired Properties in January 2010. However, the Partnership has borrowed $5,000,000 from a bank in connection with the acquisition of the Lett Acquired Properties in June 2010.  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 is not an exact science and involves a high degree of risk.  The risks of acquiring and operating producing properties are generally less than those associated with the drilling of wells.  Developmental drilling may result in dry holes or wells that do not produce crude oil or natural gas in sufficient quantities to make them commercially profitable to complete.  The producing  properties acquired by the Partnership may not produce sufficient quantities of crude oil or natural gas to enable a partner to obtain any certain projected rate of return on his or her investment, and it is possible that partners may lose money.

 

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

 

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

 

The financial condition, results of operations, and the carrying value of our oil and gas properties depend primarily upon the prices received for our crude oil and natural gas production. Crude oil and natural gas prices historically have been volatile and likely will continue to be volatile given current geopolitical conditions. Cash flow from

 

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operations is highly dependent upon the sales prices received from crude oil and natural gas production. The prices for crude oil and natural gas are subject to a variety of factors beyond our control. These factors include:

 

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

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

·                                 domestic government regulations and taxes;

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

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

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

·                                 domestic and worldwide economic conditions.

 

These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, crude oil and natural gas prices do not necessarily move in tandem. Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the amount of crude oil and natural gas that can be economically produced from successful wells drilled by the Partnership, and, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas reserves, and the carrying value of the Partnership’s oil and gas properties. Approximately 80.5% of the Partnership’s estimated proved reserves at December 31, 2010 were crude oil, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.

 

The Partnership, while not prohibited from engaging in commodity trading or hedging activities in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at December 31, 2010. Accordingly, the Partnership is at risk for the volatility in crude oil and natural gas prices, and the level of commodity prices has a significant impact upon the Partnership’s results of operations.

 

***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 experienced an economic downturn in 2008 and 2009 which could continue to impact the industry in 2011 and beyond. The economic downturn 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,

 

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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.***

 

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

 

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

 

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

 

***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.***

 

Titles to the Partnership’s interest in the leases for the Slaughter Dean Project and the Thums Long Beach Unit are held in the name of the Partnership.  Under the RCWI Agreement, title to the Azalea Acquired Properties is held in the name of RCWI.  Currently RCWI holds record title to 93.75% 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. 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.”

 

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***We cannot control activities on non-operated properties.***

 

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

 

·                                 timing and amount of capital expenditures;

·                                 expertise and financial resources; 

·                                 inclusion of other participants in drilling wells; and

·                                 use of technology.

 

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

 

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

 

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

 

You should not assume the present value of future net cash flows referred to in this Annual Report to be the current market value of our estimated crude oil and natural gas reserves. The estimated discounted future net cash flows from our proved reserves as of December 31, 2010 are based upon the 12-month un-weighted arithmetic average of the first-day-of-the-month prices and costs in effect when the estimate is made. Actual current prices, as well as future prices and costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.

 

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

 

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

 

***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.

 

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**ITEM 1B.**               **UNRESOLVED STAFF COMMENTS**

 

None.

 

**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, 2010, the Partnership has expended $56,525,553 on the acquisition and development of the Slaughter Dean Project.  As a result, as of December 31, 2010, the Partnership holds an approximate 75.7% working interest in both the Dean Unit and the Dean “B” Unit and holds a net revenue interest of approximately 64.6% and 59.9% in each respectively.  Additionally, as of December 31, 2010, the Partnership holds an approximate 78.9% working interest in the Dean “K” Lease and holds a net revenue interest of approximately 53.5%.

 

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.  During 2010, the Partnership installed an additional injection pump to increase injection volume. The Partnership has also repaired, replaced, and expanded water pumping and injection facilities and capacity.

 

The drilling of new waterflood injection wells and the conversion of a number of old already-producing oil wells to waterflood injection wells was intended to increase the productivity of the Project as a whole.  The Partnership is currently injecting approximately 6,100 barrels of water per day back into the oil producing formation. The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil, thereby increasing the ultimate recovery of crude oil and natural gas in the Slaughter Dean project.

 

During the year ended December 31, 2010, the Slaughter Dean Project has experienced periodic, small increases in production. The waterflood activities described above have reduced the rate of decline in oil production. However, waterflood activity has not increased oil and natural gas production as desired.  Although significant crude oil and natural gas reserves may remain in the reservoir, the Partnership’s current efforts to increase the waterflood response is less likely than not to be effective in materially increasing the recovery of those reserves, based upon the results of the Partnership’s efforts during 2010.  The Partnership re-evaluated the unproved reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean Project to determine what quantities of crude oil and natural gas reserves the Partnership can reasonably expect to recover from this reservoir under the current economic and operating conditions. Based on this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean Project of $53,166,873 as of December 31, 2010. The Partnership is currently monitoring the Implementation of waterflood operations and daily production of total fluids (oil and water), which are less than the total water injected each day to determine the cause of the underperformance of the waterflood operations. The Partnership may gather additional data in order to determine whether alternate configurations of water injection wells may be more effective in producing a better waterflood response in the future, though such alternative configurations may be costly to the Partnership to implement. In the event that the Partnership determines based on its monitoring activities that additional or alternative configurations of water injection wells will not materially increase production from the Slaughter Dean Project, the Partnership may decide not to pursue such activities.

 

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In January 2010, the Partnership entered into the RCWI Agreement with RCWI, an affiliate of Reef, to purchase the Azalea Acquired 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 included in this package is the Thums Long Beach Unit, discussed in more detail below.

 

In June 2010, the Partnership acquired the Lett Acquired Properties located in the Thums Long Beach unit, which include approximately 870 producing wells and 485 injection wells.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.  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.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled.  The Partnership received a cash payment of $933,300 in December 2010 in exchange for these interests.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities.  The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled.  The Partnership received $59,455 in exchange for these interests, which is included in accounts receivable from affiliates on the balance sheet as of December 31, 2010. This amount has been paid in cash to the Partnership during the first quarter of 2011.

 

**Crude Oil and Natural 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, 2010, 2009, and 2008, proved reserves do not include any reserves associated with the redevelopment and enhancement of the waterflood.  Based on its reevaluation of reservoir response at December 31, 2010, the Partnership has recognized no proved reserves related to the waterflood. Costs associated with the implementation of the waterflood development process have been capitalized and categorized as unproved, and at December 31, 2010, the Partnership recognized impairment of unproved properties of $53,166,873 related to the Slaughter Dean Project.

 

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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. 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, 2010, 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             |       |
|                                             |       |               |       |               |       |
| Net proved reserves as of December 31, 2010 |       | 838,200            |       | 1,217,840          |       |

 

The standardized measure of discounted future net cash flows as of December 31, 2010 and 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  |   |
| Standardized measure of discounted future net cash   flows as of December 31, 2010 |   | $ | 14,318,440 |   |

 

During the years ended December 31, 2010, 2009 and 2008, the Partnership recorded property impairment costs of proved properties totaling $4,777,151, $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.  During the year ended December 31, 2010, the Partnership recorded property impairment costs of unproved properties totaling $53,166,873 based on its evaluation of the data obtained from the waterflood operations of the Slaughter Dean Project.

 

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

 

The Partnership used an independent petroleum consulting company, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2010 reserve estimates of net proved crude oil and natural gas reserves.  FGA estimated reserves for all of our properties as of December 31, 2010.  The technical personnel responsible for preparing the reserve estimates at FGA meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.  FGA is an independent firm of petroleum engineers and geologists.  They do not own an interest in any of our properties, and are not employed on a contingent fee basis.  FGA’s report was developed utilizing state reporting records and published production data purchased from third parties, and data provided by Reef.  Their reserve summary, which contains further discussions of the reserve estimates and evaluations, as well as the qualifications of FGA’s technical personnel responsible for overseeing their estimates and evaluations, is included as Exhibit 99.1 to this Annual Report.

 

The Partnership used an independent petroleum engineer, William M. Cobb & Associates of Dallas, Texas, to prepare its December 31, 2009 and 2008 estimates of net proved crude oil and natural gas reserves.

 

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

 

Reef maintains a staff of technical personnel who are well versed in the engineering evaluation computer programs 

 

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and technology used and who provide well and production data to our independent petroleum engineering firm, FGA. Our accounting department accumulates historical production and pricing data and lease operating expenses for our wells, as well as the percentage interest owned by the Partnership, which is reviewed by our technical staff. Reserve estimates are prepared by FGA. Our technical staff and members of our accounting department meet regularly with FGA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. H. Walt Dunagin, Executive Vice President, Land Manager — Acquisitions and Divestitures for RELP, is the senior executive of RELP primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Dunagin is a Professional Landman with over thirty years of industry experience in oil and gas operations, acquisitions and divestitures. He is an active member of the American Association of Petroleum Landmen (AAPL) and the Association of International Petroleum Negotiators (AIPN). Any significant reserve changes are approved by Mr. Dunagin and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

 

**Title to Properties**

 

Title to the Partnership’s interest in the leases for the Slaughter Dean Project and the Thums Long Beach Unit 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 93.75% 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.                (Removed and Reserved)**

 

**PART II**

** **

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

 

As of December 31, 2010, the Partnership had one managing general partner, 811 non-Reef general partners, and 665 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.

 

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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 2010, 2009, and 2008 were $1,028,526, $411,181, and $1,791,295 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 1⁄4 unit at $25,000) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, with a maximum offering amount of $90,000,000 (900 units).  Reef Securities, Inc., an affiliate of Reef, served as the dealer manager for the private placement.  An amount equal to 15% of the proceeds realized from the sale of interests to investors was paid to Reef as a management fee.  A percentage of the management fee (8.5% of the total amount raised by the Partnership) was then used by Reef to pay sales commissions and marketing fees.  The remaining 85% of the proceeds has been expended on the purchase of the Slaughter Dean Project, the Azalea Acquired Properties, the Lett Acquired Properties, the waterflood development project at Slaughter Dean and drilling of developmental wells upon acreage purchased in connection with the Azalea Acquired Properties, and payment of additional fees owed to Reef as a result of such activities.  On 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, 2010, the Partnership had expended $56,525,553 on acquisition and development of the Slaughter Dean Project, $13,944,929 on the acquisition and development of the Azalea Acquired Properties, and $6,096,727 on the acquisition and development of the Lett Acquired Properties.  Expenditures in excess of capital contributions have been financed through debt or recovered from cash flows by reducing Partnership distributions. The Partnership has no current plans to purchase additional oil and gas properties.

 

**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.

 

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| ** **                                      | ** ** | **As of and For the Years Ended December 31,** | ** ** | **Period from   Inception   (November   27,2007) to   December 31,** | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| ** **                                      | ** ** | **2010**                                                                               | ** ** | **2009**                                                                            | ** ** | **2008** | ** ** | **2007** | ** ** |
|                                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Revenue                                         |       | $                                                                                      | 5,599,090  |                                                                                | $          | 1,655,812 |   | $ | 2,012,489 |   | $ | — |   |
| Interest income                                 |       | 3,490                                                                                  |       | 140,471                                                                             |       | 706,243 |   | 28,208 |   |
| Costs and expenses                              |       | (65,305,926                                                                            | )          | (3,343,360                                                                          | )          | (1,781,499 | ) | (30,353 | ) |
| Net income (loss)                               |       | (59,839,904                                                                            | )          | (1,547,077                                                                          | )          | 937,233 |   | (2,144 | ) |
|                                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Allocation of net income (loss):                |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Managing general partner                        |       | (588,353                                                                               | )          | (70,841                                                                             | )          | 128,050 |   | 3,064 |   |
| General partner                                 |       | (32,760,687                                                                            | )          | (816,223                                                                            | )          | 447,404 |   | (2,252 | ) |
| Limited partner                                 |       | (26,490,864                                                                            | )          | (660,013                                                                            | )          | 361,779 |   | (2,956 | ) |
| Net income (loss) per managing partner unit     |       | (65,593.41                                                                             | )          | (7,897.79                                                                           | )          | 14,275.84 |   | 2,266.11 |   |
| Net income (loss) per general partner unit      |       | (66,724.73                                                                             | )          | (1,662.43                                                                           | )          | 911.25 |   | (38.91 | ) |
| Net income (loss) per limited partner unit      |       | (66,724.73                                                                             | )          | (1,662.43                                                                           | )          | 911.25 |   | (38.91 | ) |
|                                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Total assets                                    |       | 18,362,120                                                                             |       | 74,855,409                                                                          |       | 79,860,893 |   | 11,663,508 |   |
| Distributions to managing general partner       |       | 101,085                                                                                |       | 49,050                                                                              |       | 195,938 |   | 168 |   |
| Distributions to general and limited partners   |       | 927,441                                                                                |       | 362,131                                                                             |       | 1,595,357 |   | 16,633 |   |
| Distributions per general partner unit          |       | 1,044.42                                                                               |       | 407.81                                                                              |       | 1,796.57 |   | 124.25 |   |
| Distributions per limited partner unit          |       | 1,044.42                                                                               |       | 407.81                                                                              |       | 1,796.57 |   | 124.25 |   |
| Distributions per managing general partner unit |       | 11,269.61                                                                              |       | 5,468.41                                                                            |       | 21,844.43 |   | 124.25 |   |
|                                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| **Operating Data**                              |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Annual sales volume:                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Gas (MCF)                                       |       | 190,208                                                                                |       | 7,204                                                                               |       | 21,466 |   | — |   |
| Oil (BBL)                                       |       | 66,352                                                                                 |       | 33,235                                                                              |       | 23,060 |   | — |   |
|                                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Average sales price:                            |       |                                                                                   |       |                                                                                |       |   |   |   |   |
| Gas (per MCF)                                   |       | $                                                                                      | 4.66       |                                                                                | $          | 1.49 |   | $ | 2.94 |   | $ | — |   |
| Oil (per BBL)                                   |       | $                                                                                      | 71.04      |                                                                                | $          | 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, 2010, we perform a quarterly ceiling test on the capitalized costs

 

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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 2010. 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, 2010, 2009 and 2008, the Partnership recognized property impairment expense of proved properties totaling $4,777,151, $668,430 and $0, respectively.

 

Unproved property consists primarily of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project.  In addition, the Partnership recorded $2,486,463 of unproved properties during the year ended December 31, 2010 related to the Azalea Acquired Properties.  Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the data obtained from the operations of the Slaughter Dean Project and relevant activity in the Azalea Acquired Properties. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the year ended December 31, 2010, the Partnership recognized property impairment expense of unproved properties totaling $53,166,873 related to the Slaughter Dean Project. During the years ended December 31, 2009 and 2008, the Partnership recognized no property impairment expense of unproved properties.

 

The estimate of proved crude oil and natural gas reserves used to determine property impairment expense, and also utilized in the Partnership’s disclosures of supplemental information regarding oil and gas producing activities, including the standardized measure of discounted cash flows, was prepared by an independent petroleum engineer at December 31, 2010, 2009 and 2008, utilizing prices and costs as promulgated by the SEC. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and is based upon assumptions that may vary considerably from actual results. 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, 2010, 2009 and 2008, the Partnership had depreciation, depletion, and amortization expense totaling $1,933,948, $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, 2010, 2009 and 2008, the Partnership recognized $668,800, $0, and $213,365 of asset retirement obligations and additional capitalized cost in connection with properties acquired by the Partnership and 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, 2010, 2009 and 2008, the Partnership had no material gas imbalance positions.

 

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**Recently Adopted Accounting Pronouncements**

 

**Modernization of Oil and Gas Reporting**

 

In January 2009, the SEC adopted a new rule 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 unweighted 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 Financial Accounting Standards Board (“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. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.

 

**Overview**

 

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

 

On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but 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 Partnership purchased an initial 41% 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 from Sierra-Dean Production Company, L.P. (“Sierra Dean”).   Under the terms of the acquisition agreement, each month thereafter additional working interests are purchased 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 11% of the 18% working interest in the Slaughter Dean Project owned by Davric Corporation (“Davric”).

 

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

 

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

 

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

 

Subsequently, RCWI entered into a Purchase and Sale Agreement with the Partnership, dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties Ltd. to the Partnership.  The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties Ltd. for a purchase price of $13,182,171 in cash subject to post-closing adjustments.  RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Acquired Properties cover more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset locations.  The acquired working interests represent minority non-operated interests.  The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef. Approximately $10.7 million of the purchase price is associated with proved developed reserves.

 

On June 15, 2010, Income Fund IV, an affiliate of Reef, paid $1,252,844 to Azalea Properties Ltd. for the post closing settlement related to the Side Letter Agreements which were a part of the original Azalea Purchase Agreement. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post closing settlement amount. There was no additional payment for undeveloped properties; the entire post closing settlement is associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

 

On June 23, 2010, RCWI entered into the Lett Purchase Agreement for certain oil and gas property interests owned by Lett Oil & Gas, L.P. for a purchase price of $6,000,000.  The Lett Acquired Properties are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells.  The entire $6,000,000 purchase price is associated with proved developed reserves. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.   The Lett Purchase Agreement acknowledged two $500,000 deposits which were refundable to RCWI only upon certain terms set forth in the agreement and which were credited towards the purchase price at closing.  The Partnership advanced the two $500,000 deposits as well as the remaining $5,000,000 of the purchase price payable at closing by RCWI under the Lett Purchase Agreement.  The oil and gas properties included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010. Revenues and expenses related to June 2010 are treated as a purchase price adjustment.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Granite Wash formation located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled.  The Partnership received a cash payment of $933,300 during December 2010 in exchange for these interests.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities.  The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled.  The Partnership received $59,455 in exchange for these interests, which is included in accounts receivable from affiliates on the balance sheet as of December 31, 2010. This amount has been paid in cash to the Partnership during the first quarter of 2011.

 

The Partnership has borrowed funds from a bank in connection with the purchase of the Lett Acquired Properties,

 

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and is subject to the interest rate risk inherent in borrowing activities. The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. See “Item 7A — Quantitative and Qualitative Disclosure About Market Risk.”

 

**Liquidity and Capital Resources**

 

*Capital Contributions*

 

The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef, net of adjustments for sales to brokers for their own accounts, who were permitted to buy Units at a price net of the commission that they would normally earn on sales of Units.  Non-Reef partners purchased 490.9827 general partner units and 397.0173 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. As of December 31, 2010, the Partnership had expended $56,525,553 on property acquisition and development costs related to the Slaughter Dean Project, $13,944,929 on the acquisition and development of the Azalea Acquired Properties, and $6,096,727 on the acquisition of the Lett Acquired Properties.  Expenditures in excess of available capital have been financed through debt or recovered from cash flows by reducing Partnership distributions.

 

*Credit Agreement*

 

On June 30, 2010, the Partnership and Texas Capital Bank, N.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) which currently has a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding the acquisition of oil and gas properties purchased from Lett by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in the overview above.  The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly.  The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2013, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.  At December 31, 2010, the borrowing base was equal to $5,000,000.  The Partnership borrowed $5,000,000 from TCB under the Credit Agreement which was paid directly to Lett to satisfy the closing obligations of RCWI under the Lett Purchase Agreementdescribed in the overview above.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.  In December 2010, the Partnership prepaid $250,000 of principal to TCB.

 

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

 

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

 

The Credit Agreement contains various covenants, including among others restrictions on liens, incurring other indebtedness, and distributions, as well as the maintenance of a certain current ratio and interest coverage ratio.  The Partnership was not in compliance with certain non-financial covenants under the Credit Agreement, for which it obtained a waiver from the lender.

 

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

 

*Capital Expenditures*

 

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of December 31, 2010:

 
| ** **                | ** ** | **Leasehold Costs** | ** ** | **Drilling and   Facilities Costs** | ** ** | **Workovers** | ** ** | **Total Costs** | ** ** |
|---------------------------|------------|--------------------------|------------|-----------------------------------------------|------------|---------------|------------|----------------------|------------|
|                      |       |                     |       |                                          |       |          |       |                 |       |
| Purchase Existing Wells   |       | $                        | 35,150,152 |                                          | $          | —        |       | $                    | —     |   | $ | 35,150,152 |   |
|                      |       |                     |       |                                          |       |          |       |                 |       |
| New Wells                 |       |                     |       |                                          |       |          |       |                 |       |
| Producing Wells           |       | 74                       |       | 27,464,452                                    |       | —        |       | 27,464,526           |       |
| Waterflood Injector Wells |       | —                   |       | 5,149,620                                     |       | —        |       | 5,149,620            |       |
| Facilities                |       | —                   |       | 1,795,397                                     |       | —        |       | 1,795,397            |       |
|                      |       |                     |       |                                          |       |          |       |                 |       |
| Existing Wells            |       | —                   |       | —                                        |       | 7,007,513     |       | 7,007,513            |       |
|                      |       |                     |       |                                          |       |          |       |                 |       |
|                      |       | $                        | 35,150,226 |                                          | $          | 34,409,469    |       | $                    | 7,007,513  |   | $ | 76,567,208 |   |

 

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 unproved properties owned by the Partnership at December 31, 2010 and 2009 consist primarily of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project. During the year ended December 31, 2010, the Partnership recorded property impairment costs of unproved properties totaling $53,166,873 based on its evaluation of the data obtained from the waterflood operations of the Slaughter Dean Project.

 

In addition to the unproved properties related to the Slaughter Dean Project, the Partnership acquired $2,486,463 of unproved properties during the year ended December 31, 2010 related to the Azalea Acquired Properties, portions of which were sold during December 2010 due to intended or in-process exploratory drilling activities.  In addition, the Partnership transferred portions of unproved properties to proved properties as the related wells from the unproved

 

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properties began to be drilled.

 

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2010:

 
| ** **                        | ** ** | **Slaughter   Dean Project** | ** ** | **Azalea   Acquired   Properties** | ** ** | **Total Costs** | ** ** |
|-----------------------------------|------------|-----------------------------------|------------|------------------------------------|------------|----------------------|------------|
| Beginning balance                 |       | $                                 | 52,010,728 |                               | $          | —               |       | $ | 52,010,728 |   |
| Additions due to development      |       | 1,156,145                         |       | —                             |       | 1,156,145            |       |
| Additions due to acquisitions     |       | —                            |       | 2,486,462                          |       | 2,486,462            |       |
| Sales of unproved properties      |       | —                            |       | (480,781                           | )          | (480,781             | )          |
| Transfers to proved properties    |       | —                            |       | (36,248                            | )          | (36,248              | )          |
| Impairment of unproved properties |       | (53,166,873                       | )          | —                             |       | (53,166,873          | )          |
| Ending balance                    |       | $                                 | —     |                               | $          | 1,969,433            |       | $ | 1,969,433 |   |

 

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2009:

 
| ** **                   | ** ** | **Slaughter   Dean Project** | ** ** | **Azalea   Acquired   Properties** | ** ** | **Total Costs** | ** ** |
|------------------------------|------------|-----------------------------------|------------|------------------------------------|------------|----------------------|------------|
| Beginning balance            |       | $                                 | 38,582,968 |                               | $          | —               |       | $ | 38,582,968 |   |
| Additions due to development |       | 13,427,760                        |       | —                             |       | 13,427,760           |       |
| Ending balance               |       | $                                 | 52,010,728 |                               | $          | —               |       | $ | 52,010,728 |   |

 

The Partnership had working capital of $2,064,381 and $19,440,250 at December 31, 2010 and 2009, respectively.  The Partnership has expended $76,567,208 on the property acquisitions and development costs detailed above. Expenditures in excess of available capital have been financed through debt as discussed above, or recovered from cash flows by reducing Partnership distributions. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the Partnership working capital consists primarily of cash flows from productive properties utilized to pay cash distributions to investors.  Sources of future funding consist of cash on hand, cash flow from operations, and sales of properties.  The Partnership may not be able to sell properties at the values desired.  As a result, the Partnership’s future ability to participate in the further development of properties in which the Partnership holds an interest may be restricted, unless the Partnership chooses to utilize cash flows from operations available for distributions to investors.

 

**Results of Operations**

 

**Year Ended December 31, 2010 compared to Year Ended December 31, 2009**

 

The Partnership had a net loss of $59,839,904 for the year ended December 31, 2010, compared to a net loss of $1,547,077 for the year ended December 31, 2009.  The change in operating results is primarily due to significant impairment of proved and unproved properties during the year ended December 31, 2010.  In addition, increases in depreciation, depletion and amortization expense, as well as general and administrative expenses, contributed to the greater loss during the year ended December 31, 2010 compared to the year ended December 31, 2009.

 

During the year ended December 31, 2009, the Partnership recognized impairment expense of $668,430, primarily

 

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due to lower commodity prices during 2009.  At March 31, 2010, the Partnership recorded impairment expense of proved properties totaling $1,452,475, and at June 30, 2010, the Partnership recorded impairment expense of proved properties totaling $2,072,207.  At December 31, 2010, the Partnership recorded impairment expense of proved properties of $1,252,469.  These impairments were primarily related to the Azalea Acquired Properties and the Lett Acquired Properties, for which the quarterly ceiling test is calculated using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10% for the entire life of these very long-lived properties, as opposed to using the prices in effect at the time of the transactions.  The impairment related to the Azalea Acquired Properties primarily is the result of revised engineering analysis, adjustments to projected decline rates for the acquired properties and continued depressed prices for natural gas.

 

In addition to the impairment expense of proved properties, the Partnership recorded impairment expense of unproved properties related to the Slaughter Dean Project.  During the year ended December 31, 2010, the Slaughter Dean Project has experienced periodic, small increases in production. However, waterflood activity has not increased oil and natural gas production as desired.  Although significant crude oil and natural gas reserves may remain in the reservoir, the Partnership’s current efforts to increase the waterflood response is less likely than not to be effective in materially increasing the recovery of those reserves, based upon the results of the Partnership’s efforts during 2010.  The Partnership re-evaluated the unproved reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean Project to determine what quantities of crude oil and natural gas reserves the Partnership can reasonably expect to recover from this reservoir under the current economic and operating conditions. Based on this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean Project of $53,166,873 as of December 31, 2010.  The Partnership is currently monitoring the implementation of waterflood operations and daily production of total fluids (oil and water), which are less than the total water injected each day to determine the cause of the underperformance of the waterflood operations.  The Partnership may gather additional data in order to determine whether alternate configurations of water injection wells may be more effective in producing a better waterflood response in the future, though such alternative configurations may be costly to the Partnership to implement.  In the event that the Partnership determines, based on its monitoring activities, that additional or alternative configurations of water injection wells will not materially increase production from the Slaughter Dean Project, the Partnership may decide not to pursue such activities.

 

Partnership revenues totaled $5,599,090 for the year ended December 31, 2010 compared to $1,655,812 for the comparable period in 2009.  Volumes increased due primarily to the Partnership’s purchase in January 2010 of the Azalea Acquired Properties and the Partnership’s purchase in June 2010 of the Lett Acquired Properties.  These purchases resulted in oil volumes of 33,803 Bbl and gas volumes of 185,250 Mcf during the year ended December 31, 2010.  In addition, average crude oil and natural gas sales prices rose significantly during the comparable periods.  Average oil prices increased by 43.5% and average gas prices increased by 212.8% during the year ended December 31, 2010 compared to the year ended December 31, 2009.  The large increase in gas prices is primarily due to the fact that because of its lower quality, Slaughter Dean gas is sold at a heavily discounted price, while gas from the newly acquired Azalea and Lett properties is sold at a higher price.

 

Lease operating expenses increased from $1,297,997 for the year ended December 31, 2009 to $2,369,144 for the year ended December 31, 2010, and production taxes increased from $78,127 for the year ended December 31, 2009 to $385,740 for the year ended December 31, 2010.  These increases are primarily due to the Partnership’s purchases of the Azalea Acquired Properties in January 2010 and the Lett Acquired Properties in June 2010, as well as the Partnership’s assumption of Davric’s 7% working interest in Slaughter Dean.

 

Depreciation, depletion and amortization increased from $306,507 for the year ended December 31, 2009 to $1,933,948 for the year ended December 31, 2010. The Azalea and Lett purchases have resulted in increased production levels and a higher depletion rate, as well as a higher property depletable basis.

 

General and administrative costs incurred during the years ended December 31, 2010 and 2009 increased from $973,859 in 2009 to $2,610,680 in 2010. This increase is primarily due to acquisition costs related to the Azalea Acquired Properties and the Lett Acquired Properties of approximately $791,000, as well as increased overhead.  Overhead charges from RELP charged to general and administrative expense increased by approximately $595,000.  During the year ended December 31, 2009, a portion of RELP overhead charges were capitalized due to the capital expenditures program in the Slaughter Dean Field.  In addition, direct costs charged to the Partnership increased by approximately $243,000 during the year ended December 31, 2010.

 

Total other income and expense for the years ended December 31, 2010 and 2009 decreased from interest income of $140,471 in 2009 to total other expense of $133,068 in 2010.  Interest income decreased from $140,471 to $3,490 due to the fact that the Partnership spent its remaining capital available during 2010 to acquire the Azalea Acquired Properties and the Lett Acquired Properties. In addition, the Partnership was charged interest expense of $128,472 during the third and fourth quarters of 2010 related to its borrowings under the Credit Agreement for financing the acquisition of the Lett Acquired Properties, as described in Note 4 to the financial statements.

 

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**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.

 

**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, 2010, 2009 and 2008, 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 *                 |       | —                                   |       | — |   | — |   | — |   | — |   |
| Credit Agreement                       |       | $                                        | 4,750,000  |   | — |   | $ | 4,750,000 |   | — |   | — |   |
| Interest related to Credit Agreement** |       | $                                        | 613,542    |   | $ | 245,417 |   | $ | 368,125 |   | — |   | — |   |
|                                        |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |

 

 

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* The Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN Associates whereby the Partnership agreed to assign a one percent (1%) overriding royalty interest, proportionately reduced to the Partnership’s working interest, to William R. Dixon in exchange for Dixon’s agreement to “review and evaluate exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnership’s working interest in the Slaughter Dean Field only.  The amounts payable to William R. Dixon under the aforementioned agreement are not fixed and determinable amounts, and will vary based upon sales revenues from the Slaughter Dean Project.

** Interest expense assumes the balance of the Credit Agreement at the end of the period and the rate in effect as of December 31, 2010.

 

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**ITEM 7A.**                                            **QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK**

 

**Interest Rate Risk**

 

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.  At December 31, 2010, the Partnership has $4,750,000 of outstanding debt under the Credit Agreement. Interest is calculated under the terms of the agreement based on the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. A 1.0% increase in interest rates during the year ended December 31, 2010 would have increased interest expense by approximately $25,000. The Partnership does not currently intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.

 

**Commodity Price Risk**

 

As of December 31, 2010, the Partnership does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes.  The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

 

Assuming the production levels the Partnership attained during the year ended December 31, 2010, a 10% change in the price received for our crude oil would have had an approximate $471,400 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 $88,600 impact on our natural gas revenues.

** **

**ITEM 8.****                                                    ****FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

 

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

** **

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

 

None.

 

**ITEM 9A.**                                            **CONTROLS AND PROCEDURES**

 

**Evaluation of Disclosure Controls and Procedures**

 

As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this Annual Report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial 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

 

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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, 2010.

 

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

 

**Changes in Internal Controls**

 

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

** **

**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.

 
| **Name**           | ** ** | **Age** | ** ** | **Positions and Offices Held**                                         |
|--------------------|------------|---------|------------|---------------------------------------------------------------------------------------|
| Michael J. Mauceli |       | 54      |       | Manager of Reef Oil & Gas Partners GP, LLC;

Chief Executive Officer of RELP |
| H. Walt Dunagin    |       | 53      |       | Executive Vice President and Land Manager of RELP                                     |
| Daniel C. Sibley   |       | 59      |       | General Counsel of RELP                                                               |
| David M. Tierney   |       | 58      |       | 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

 

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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.

 

**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.

 

**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.

 

On May 29, 2009, Reef SWD 2007-A, L.P. (“Reef SWD 2007-A”), an affiliate of Reef,filed a lawsuit against Ricardo Guevara and certain of his affiliates alleging that Guevara misrepresented and omitted material information in regard to Reef SWD 2007-A’s purchase of four salt water disposal facilities located in Webb and Zapata Counties, Texas for a price of $7.5 million.  The lawsuit, styled Reef SWD 2007-A v. Ricardo Guevara, et al. (Cause No. 09-06828) was filed in the 14th-A Judicial District Court of Dallas County, Texas and sought rescission and actual damages, consequential damages, exemplary damages, attorneys’ fees, and costs.  On October 1, 2009, the court entered an order transferring the venue of the case to Zapata County, Texas.  On January 4, 2010, Reef SWD 2007-A non-suited Mr. Guevara and his affiliates and terminated its Texas state court litigation against them.  On January 5, 2010, Reef SWD 2007-A instituted a federal bankruptcy Chapter 11 proceeding in the U.S. Bankruptcy Court for the Northern District of Texas.  As part of that proceeding, Reef SWD 2007-A is asserting claims against Mr. Guevara and his affiliates similar in nature to the claims that were brought in the Texas state courts, as well as certain claims regarding fraudulent conveyances, which can only be brought in bankruptcy court.  On March 30, 2010, Reef SWD 2007-A filed an application with the court to convert the Chapter 11 proceeding to a Chapter 7 proceeding under the U.S. Bankruptcy Code. Pursuant to those proceedings, Reef SWD 2007-A sold all of its operating assets for approximately $1.3 million dollars. On November 3, 2010, Mr. Guevara et al. filed a counterclaim against Reef SWD 2007-A in the bankruptcy matter, alleging breach of contract for unpaid amounts allegedly due under the note from Reef SWD 2007-A (related to the original, underlying transaction) and tort claims of fraud, negligent misrepresentation, negligence, gross negligence, and breach of fiduciary duty.  On February 23, 2011, the court dismissed with prejudice in part the tort claims asserted by Defendants.  The court gave Defendants until March 15, 2011 to file an amended counterclaim relating to alleged fraud concerning Reef SWD 2007-A’s prior experience with saltwater disposal facilities but no amended counterclaim was filed. The case is presently set for trial during the week of October 17, 2011. Reef SWD 2007-A still intends to vigorously pursue its claims against Mr. Guevara and his affiliates and to defend any remaining counterclaims.

 

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**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, 2010 and 2009, the Partnership paid administrative fees of   $896,880 and $896,880 respectively.                                                                                                                                                                                                                                                                                                                                                                                                        |
|                                          |       |                               |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Managing   General Partner or its Affiliates  |       | Drilling   compensation            |       | When Reef or an affiliate of Reef serves as   operator of a Partnership property, then Reef or such affiliate, as the case   may be, will receive drilling compensation equal to 15% of the total well   costs, excluding lease acquisition costs. Total well costs include the costs   associated with all developmental activities on a well, such as drilling,   completing, reworking, working over, deepening, sidetracking, or fracturing a   well. Because RELP will serve as operator of the Slaughter Dean Project, such   drilling compensation payable to RELP may amount to approximately 9% total   partnership subscriptions, depending on the |

 

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| **Recipient**                                 | ** ** | **Form of Compensation**                               | ** ** | **Amount**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|-----------------------------------------------|------------|------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                          |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|                                          |       |                                                             |       | 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, 2010 and 2009, the Partnership paid a   drilling compensation fee of $232,775 and $1,544,858 respectively. |
|                                          |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Managing   General Partner and its Affiliates |       | Direct   costs                                                   |       | Reimbursement   at cost. For the years ended December 31, 2010 and 2009, the Partnership   paid direct costs of $441,881 and $475,747 respectively.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|                                          |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Managing   General Partner and its Affiliates |       | Payment   for equipment, supplies, marketing, and other services |       | Competitive   prices. For the years ended December 31, 2010 and 2009, the Partnership   paid no payments for equipment, supplies, marketing and other services.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|                                          |       |                                                             |       |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| Managing   General Partner and its Affiliates |       | Acquisition   and Development Costs                              |       | Reimbursement   at cost. For the years ended December 31, 2010 and 2009, 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, 2010, 2009 and 2008 and, Reef has received $101,085, $49,050, and

 

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$195,938, 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, 2010, RELP received $232,775 in 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.  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, 2010, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $441,881 and $10,192, respectively. 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, no reimbursements were made to Reef and its affiliates for direct or out-of-pocket costs.

 

RELP receives an administrative fee to cover all general and administrative costs in an amount equal to 1/12 th of 1% of all capital raised payable monthly.  During the year ended December 31, 2010, RELP received $896,880 in administrative fees. During the year ended December 31, 2009, RELP received $896,880 in administrative fees.  During the year ended December 31, 2009, $595,381 of administrative fees were capitalized and are included in property costs in the financial statements, with the remainder included in general and administrative expenses.  Administrative fees related to 2010 are included in general and administrative expense in the financial statements. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

 

Beginning on January 1, 2010, RELP began processing joint interest billings and revenues on behalf of the Partnership. At December 31, 2010, RELP owed the Partnership $45,640 for net revenues processed in excess of joint interest and technical and administrative services charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.

 

**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, 2010 concerning all persons known by Reef to own beneficially more than 5% of the interests in the Partnership. Unless expressly indicated otherwise, each partner exercises sole voting and investment power with respect to the units beneficially owned.

 

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

 

----

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

 

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

 

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

 

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

 

On January 19, 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 for approximately $13,182,171 in cash, subject to post closing adjustments.

 

On June 15, 2010, Reef Oil & Gas Income and Development Fund IV (“Income Fund IV”) paid $1,252,844 to Azalea Properties Ltd. for the post closing settlement related to the Side Letter Agreements which were a part of the original Azalea Purchase Agreement. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post closing settlement amount. There was no additional payment for undeveloped properties; the entire post closing settlement is associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

 

On June 30, 2010, RCWI conveyed to the Partnership acquired certain working interests in oil and gas properties (“Lett Acquired Properties”) located in the Thums Long Beach unit, which include approximately 870 producing wells and 485 injection wells, pursuant to an Assignment, Conveyance and Bill of Sale effective June 1, 2010.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilminton Field, located underneath the Long Beach Harbor in southern California.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Granite Wash formation located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled.  The Partnership received $933,300 in cash in exchange for these interests.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities.  The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled.  The

 

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Partnership accepted a sales price of $59,455 in exchange for these interests, of which the entire amount is included in accounts receivable from affiliates on the balance sheet as of December 31, 2010.

 

**ITEM 14.               PRINCIPAL ACCOUNTANT FEES AND SERVICES**

 

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

 
| ** **         | ** ** | **2010** | ** ** | **2009** | ** ** |
|--------------------|------------|----------|------------|----------|------------|
| Audit fees         |       | $        | 65,440     |     | $          | 80,314 |   |
| Audit related fees |       | —   |       | —   |       |
| Tax fees           |       | —   |       | —   |       |
| All other fees     |       | —   |       | —   |       |
|                    |            |          |            |          |            |  |  |

 

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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 15, 2011

 

 
|   | **REEF   OIL & GAS INCOME** |
|--------|--------------------------------------|
|   | **AND   DEVELOPMENT FUND III, L.P.** |
|   |                                 |   |
|   |                                 |   |
|   | By:                                  | Reef   Oil & Gas Partners, L.P. |
|   |                                 | Managing   General Partner |
|   |                                 |   |
|   |                                 |   |
|   | By:                                  | Reef   Oil & Gas Partners, GP, LLC, |
|   |                                 | its   general partner |
|   |                                 |   |
|   |                                 |   |
|   | By:                                  | /s/   Michael J. Mauceli |
|   |                                 |   |
|   |                                 | Michael   J. Mauceli |
|   |                                 | Manager   and Member |
|   |                                 | (*Principal Executive Officer*) |

 

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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 Reef Oil & Gas Partners, GP, LLC, the general partner   of Reef Oil & Gas Partners, L.P., the Managing General Partner of   the Partnership   (*Principal Executive Officer*) |       | April 15, 2011 |
| Michael J. Mauceli     |       |                                                                                                                                                                                                                    |       |
|                   |
|                   |       |                                                                                                                                                                                                                    |       |                |
|                   |       |                                                                                                                                                                                                                    |       |                |
| /s/   Daniel C. Sibley |       | Chief   Financial Officer and General Counsel of Reef Exploration, L.P.   (*Principal Financial and Accounting Officer*)                                                                                                |       | April 15, 2011 |
| Daniel   C. Sibley     |

 

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**EXHIBIT INDEX**

 

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

 
| **Exhibit** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|-------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number**  | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                                            |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 3.1         |       | Certificate   of Formation of Reef Oil & Gas Income and Development Fund III, L.P.   dated November 27, 2007(incorporated by reference to Exhibit 3.1 to   the Partnership’s Registration Statement on Form 10, dated   October 2, 2009).                                                                                                                                                                |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.1         |       | Second   Amendment and Restated Agreement of Limited Partnership of Reef   Oil & Gas Income and Development Fund III, L.P., dated June 4,   2008 (incorporated by reference to Exhibit 4.1 to the Partnership’s   Registration Statement on Form 10, dated October 2, 2009).                                                                                                                             |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.1        |       | Operating   Agreement dated January 7, 2008, by and among Reef Exploration, L.P.,   Reef Oil & Gas Income and Development Fund III, L.P. and Davric   Corporation (incorporated by reference to Exhibit 3.1 to the   Partnership’s Registration Statement on Form 10, dated October 2,   2009).                                                                                                          |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.2        |       | Operating   Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef   Oil & Gas Income and Development Fund III, L.P. and Davric   Corporation (incorporated by reference to Exhibit 10.2 to the   Partnership’s Registration Statement on Form 10, dated October 2,   2009).                                                                                                             |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.3        |       | Purchase   and Sale Agreement dated January 7, 2008 by and among Sierra-Dean   Production Company L.P., Reef Oil & Gas Income and Development Fund   III, L.P., Reef Exploration L.P. and SPI Operations LLC, as amended on   January 8, 2008 (incorporated by reference to Exhibit 10.3 to the   Partnership’s Registration Statement on Form 10, dated October 2,   2009).                        |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.4        |       | Assignment,   dated May 1, 2008, by and between Davric Corporation and Reef   Oil & Gas Income and Development Fund III, L.P. (incorporated by   reference to Exhibit 10.4 to the Partnership’s Registration Statement on   Form 10, dated October 2, 2009).                                                                                                                                             |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.5        |       | Crude   Oil Contract, dated March 13, 2008, by and between Reef Exploration,   L.P. and Occidental Energy Marketing, Inc., as amended by Amendment   No. 1, dated June 24, 2008, by and between Reef Exploration, L.P.   and Occidental Energy Marketing, Inc. (incorporated by reference to   Exhibit 10.5 to the Partnership’s Registration Statement on   Form 10, dated October 2, 2009). |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.6        |       | Consulting   Agreement, dated September 1, 2006, by between Reef Exploration, L.P.   and William R. Dixon (incorporated by reference to Exhibit 10.6 to the   Partnership’s Registration Statement on Form 10, dated October 2,   2009).                                                                                                                                                                          |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.7        |       | Casinghead   Gas Sales Contract, dated January 1, 1978, by and between Amoco   Production Company and Amoco Production Company (incorporated by reference to   Exhibit 10.7 to the Partnership’s Registration Statement on   Form 10, dated October 2, 2009).                                                                                                                                                     |
|        |       |                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| 10.8        |       | Purchase   and Sale Agreement, dated January 19, 2010, by and between Azalea   Properties Ltd. And RCWI, LP. (incorporated by reference to Exhibit 10.1   to the Partnership’s Current Report on Form 8-K, dated January 22,   2010).                                                                                                                                                                             |

 

41

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Table of Contents

 
| 10.9   |   | Purchase   and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P.,   and Reef Oil & Gas Income and Development Fund III, L.P.   (incorporated by reference to Exhibit 10.2 to the Partnership’s Current   Report on Form 8-K, dated January 22, 2010).                                                                                                        |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.10  |   | Side   Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea   Properties Ltd. Regarding Post Closing PUDs (incorporated by reference to   Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated   January 22, 2010).                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.11  |   | Side   Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea   Properties Ltd. Regarding Post Closing Properties/Title Defect Notice   (incorporated by reference to Exhibit 10.4 to the Partnership’s Current   Report on Form 8-K, dated January 22, 2010).                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.12  |   | Side   Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea   Properties Ltd. Regarding Third Party Consents (incorporated by reference to   Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated   January 22, 2010).                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.13  |   | Purchase   and Sale Agreement by and between Lett Oil & Gas, L.P., as seller   and RCWI, L.P., as buyer dated as of June 23, 2010 (incorporated by reference   to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K,   dated July 9, 2010).                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.14  |   | Assignment,   Conveyance and Bill of Sale between Lett Oil & Gas, L.P.   (“Assignor”) and Reef Oil & Gas Income and Development Fund III,   L.P. (“Assignee”) executed June 30, 2010 and dated effective   June 1, 2010 (incorporated by reference to Exhibit 10.2 to the   Partnership’s Current Report on Form 8-K, dated July 9, 2010). |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.15  |   | $50,000,000   Credit Agreement dated June 30, 2010 between Reef Oil & Gas Income   and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as   lender (incorporated by reference to Exhibit 10.3 to the Partnership’s   Current Report on Form 8-K, dated July 9, 2010).                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.16  |   | Form of   Security Agreement (General) dated June 30, 2010 by Reef Oil &   Gas Income and Development Fund III, L.P., in favor of Texas Capital Bank,   N.A., as lender (incorporated by reference to Exhibit 10.4 to the   Partnership’s Current Report on Form 8-K, dated July 9, 2010).                                                                              |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.17  |   | Promissory   Note in the principal amount of up to $50,000,000 dated June 30, 2010   payable to Texas Capital Bank, N.A. (incorporated by reference to   Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated   July 9, 2010).                                                                                                                                         |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                           |
| 23.2   | *      | Consent   of Forrest A. Garb. & 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 Forrest A. Garb & Associates, Inc.                                                                                                                                                                                                                                                                                                                                   |
|        |        |                                                                                                                                                                                                                                                                                                                                                                                                                |  |

 

----

* Filed herewith

 

42

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Table of Contents

 

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

 

Financial Statements

 

Years Ended December 31, 2010, 2009, and 2008

 

**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    |

 

43

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Table of Contents

 

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, 2010 and 2009 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

 

As discussed in Note 3 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.

 
| /S/   BDO USA, LLP |   |
|--------------------|--------|
|               |   |
|               |   |
| Dallas,   Texas    |   |
| April   15, 2011   |   |

 

F-1

----

Table of Contents

 

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

 

**Balance Sheets**

 
| **December 31, **                                                     | ** ** | **2010**   | ** ** | **2009**   | ** ** |
|---------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Assets                                                                          |       |       |       |       |       |
| Current assets:                                                                 |       |       |       |       |       |
| Cash and cash equivalents                                                       |       | $          | 1,136,682  |       | $          | 18,243,848 |   |
| Accounts receivable                                                             |       | 832,471    |       | 736,161    |       |
| Accounts receivable from affiliates                                             |       | 105,094    |       | 1,500,000  |       |
| Total current assets                                                            |       | 2,074,247  |       | 20,480,009 |       |
|                                                                            |       |       |       |       |       |
| Oil and gas properties, full cost method of   accounting:                       |       |       |       |       |       |
| Accounting:                                                                     |       |       |       |       |       |
| Proved properties, net of accumulated depletion of   $60,980,309 and $1,207,373 |       | 14,318,440 |       | 2,364,672  |       |
| Unproved properties                                                             |       | 1,969,433  |       | 52,010,728 |       |
| Net oil and natural gas properties                                              |       | 16,287,873 |       | 54,375,400 |       |
|                                                                            |       |       |       |       |       |
| Total assets                                                                    |       | $          | 18,362,120 |       | $          | 74,855,409 |   |
|                                                                            |       |       |       |       |       |
| Liabilities and partnership equity                                              |       |       |       |       |       |
|                                                                            |       |       |       |       |       |
| Current liabilities:                                                            |       |       |       |       |       |
| Accounts payable                                                                |       | $          | 47         |       | $          | 571,154 |   |
| Accounts payable to affiliates                                                  |       | —     |       | 223,515    |       |
| Accrued liabilities                                                             |       | 9,819      |       | 245,090    |       |
| Total current liabilities                                                       |       | 9,866      |       | 1,039,759  |       |
|                                                                            |       |       |       |       |       |
| Long term liabilities:                                                          |       |       |       |       |       |
| Note payable                                                                    |       | 4,750,000  |       | —     |       |
| Asset retirement obligation                                                     |       | 903,946    |       | 248,912    |       |
| Total long term liabilities                                                     |       | 5,653,946  |       | 248,912    |       |
|                                                                            |       |       |       |       |       |
| Commitments and contingencies (Note 7)                                          |       |       |       |       |       |
|                                                                            |       |       |       |       |       |
| Partnership equity                                                              |       |       |       |       |       |
| General partners                                                                |       | 7,336,215  |       | 40,609,693 |       |
| Limited partners                                                                |       | 5,348,414  |       | 32,253,928 |       |
| Managing general partner                                                        |       | 13,679     |       | 703,117    |       |
| Total partnership equity                                                        |       | 12,698,308 |       | 73,566,738 |       |
|                                                                            |       |       |       |       |       |
| Total liabilities and partnership equity                                        |       | $          | 18,362,120 |       | $          | 74,855,409 |   |

 

*See accompanying notes to financial statements.*

 

F-2

----

Table of Contents

 

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

 

**Statements of Operations**

 
| ** **                                            | ** ** | **As of and For the Years Ended December 31,** | ** **  |
|-------------------------------------------------------|------------|----------------------------------------------------------------------------------------|-------------|
| ** **                                            | ** ** | **2010**                                                                               | ** **  | **2009** | ** ** | **2008** | ** ** |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Revenues                                              |       | $                                                                                      | 5,599,090   |   | $ | 1,655,812 |   | $ | 2,012,489 |   |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Costs and expenses:                                   |       |                                                                                   |        |   |   |   |   |
| Lease operating expenses                              |       | 2,369,144                                                                              |        | 1,297,997 |   | 1,190,395 |   |
| Production taxes                                      |       | 385,740                                                                                |        | 78,127 |   | 94,106 |   |
| Depreciation, depletion and amortization              |       | 1,933,948                                                                              |        | 306,507 |   | 232,436 |   |
| Accretion of asset retirement obligation              |       | 62,390                                                                                 |        | 18,440 |   | 17,107 |   |
| Property impairment                                   |       | 57,944,024                                                                             |        | 668,430 |   | — |   |
| General and administrative                            |       | 2,610,680                                                                              |        | 973,859 |   | 247,455 |   |
| Total costs and expenses                              |       | 65,305,926                                                                             |        | 3,343,360 |   | 1,781,499 |   |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Income (loss) from operations                         |       | (59,706,836                                                                            | )           | (1,687,548 | ) | 230,990 |   |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Other income (expense)                                |       |                                                                                   |        |   |   |   |   |
| Miscellaneous income (expense)                        |       | (8,086                                                                                 | )           | — |   | — |   |
| Interest income                                       |       | 3,490                                                                                  |        | 140,471 |   | 706,243 |   |
| Interest expense                                      |       | (128,472                                                                               | )           | — |   | — |   |
| Total other income (expense)                          |       | (133,068                                                                               | )           | 140,471 |   | 706,243 |   |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Net income (loss)                                     |       | $                                                                                      | (59,839,904 | ) | $ | (1,547,077 | ) | $ | 937,233 |   |
|                                                  |       |                                                                                   |        |   |   |   |   |
| Net income (loss) per general partner unit            |       | $                                                                                      | (66,724.73  | ) | $ | (1,662.43 | ) | $ | 911.25 |   |
| Net income (loss) per limited partner unit            |       | $                                                                                      | (66,724.73  | ) | $ | (1,662.43 | ) | $ | 911.25 |   |
| Net income (loss) per managing general partner   unit |       | $                                                                                      | (65,593.41  | ) | $ | (7,897.79 | ) | $ | 14,275.84 |   |

 

*See accompanying notes to financial statements.*

 

F-3

----

Table of Contents

 

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

 

**Statements of Partnership Equity**

** **
| ** **                               | ** ** | **General Partners** | ** ** | **Limited Partners** | ** ** | **Managing General Partner** | ** ** | **Total**   | ** ** |
|------------------------------------------|------------|---------------------------|------------|---------------------------|------------|----------------------------------------|------------|-------------|------------|
| ** **                               | ** ** | **Units**                 | ** ** | **Amount**                | ** ** | **Units**                              | ** ** | **Amount**  | ** ** | **Units** | ** ** | **Amount** | ** ** | **Units** | ** ** | **Amount** | ** ** |
|                                     |       |                      |       |                      |       |                                   |       |        |       |   |   |   |   |   |   |   |   |
| Balance at December 31, 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 income                               |       | —                    |       | 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 |       |                      |       | $                         | 407.81     |                                   |       |        | $          | 407.81 |   |   |   | $ | 5,468.41 |   |   |   |   |   |
|                                     |       |                      |       |                      |       |                                   |       |        |       |   |   |   |   |   |   |   |   |
| Balance at December 31, 2009        |       | 490.9827                  |       | $                         | 40,609,693 |                                   | 397.0172   |        | $          | 32,253,928 |   | 8.9697 |   | $ | 703,117 |   | 896.9696 |   | $ | 73,566,738 |   |
| Partner distributions                    |       | —                    |       | (512,791                  | )          | —                                 |       | (414,650    | )          | — |   | (101,085 | ) | — |   | (1,028,526 | ) |
| Net loss                                 |       | —                    |       | (32,760,687               | )          | —                                 |       | (26,490,864 | )          | — |   | (588,353 | ) | — |   | (59,839,904 | ) |
| Balance at December 31, 2010        |       | 490.9827                  |       | $                         | 7,336,215  |                                   | 397.0172   |        | $          | 5,348,414 |   | 8.9697 |   | $ | 13,679 |   | 896.9696 |   | $ | 12,698,308 |   |
|                                     |       |                      |       |                      |       |                                   |       |        |       |   |   |   |   |   |   |   |   |
| Distribution amount per partnership unit |       |                      |       | $                         | 1,044.42   |                                   |       |        | $          | 1,044.42 |   |   |   | $ | 11,269.61 |   |   |   |   |   |

 

*See accompanying notes to financial statements.*

 

F-4

----

Table of Contents

 

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

 

**Statements of Cash Flows**

** **
| ** **                                                                             | ** ** | **For the Years Ended December 31,** | ** **  |
|----------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                                             | ** ** | **2010**                                                      | ** **  | **2009** | ** ** | **2008** | ** ** |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Operating activities                                                                   |       |                                                          |        |   |   |   |   |
| Net income (loss)                                                                      |       | $                                                             | (59,839,904 | ) | $ | (1,547,077 | ) | $ | 937,233 |   |
| Adjustments to reconcile net income (loss) to net   cash used in operating activities: |       |                                                          |        |   |   |   |   |
| Depletion, depreciation and amortization                                               |       | 1,933,948                                                     |        | 306,507 |   | 232,436 |   |
| Accretion of asset retirement obligation                                               |       | 62,390                                                        |        | 18,440 |   | 17,107 |   |
| Property impairment                                                                    |       | 57,944,024                                                    |        | 668,430 |   | — |   |
| Changes in operating assets and liabilities                                            |       |                                                          |        |   |   |   |   |
| Accounts receivable                                                                    |       | (531,700                                                      | )           | (64,272 | ) | (671,889 | ) |
| Accounts receivable from affiliates                                                    |       | 1,454,361                                                     |        | 709,300 |   | (2,209,300 | ) |
| Prepaid expenses                                                                       |       | —                                                        |        | 507,640 |   | (507,640 | ) |
| Accounts payable                                                                       |       | (429,928                                                      | )           | 135,227 |   | 277,948 |   |
| Accounts payable to affiliates                                                         |       | (154,790                                                      | )           | 2,746,160 |   | (119,920 | ) |
| Accrued liabilities                                                                    |       | (49,618                                                       | )           | (2,405,953 | ) | 104,492 |   |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Net cash provided by (used in) operating   activities                                  |       | 388,783                                                       |        | 1,074,402 |   | (1,939,533 | ) |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Investing activities:                                                                  |       |                                                          |        |   |   |   |   |
| Proceeds from sale of oil & gas   properties                                  |       | 933,300                                                       |        | — |   | — |   |
| Purchase of oil & gas properties                                              |       | (18,547,948                                                   | )           | (80,758 | ) | (15,260,041 | ) |
| Property development                                                                   |       | (3,602,775                                                    | )           | (16,808,618 | ) | (22,943,170 | ) |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Net cash used in investing activities                                                  |       | (21,217,423                                                   | )           | (16,889,376 | ) | (38,203,211 | ) |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Financing activities:                                                                  |       |                                                          |        |   |   |   |   |
| Proceeds from note payable                                                             |       | 5,000,000                                                     |        | — |   | 76,109,019 |   |
| Payment of note payable                                                                |       | (250,000                                                      | )           | (490,665 | ) | — |   |
| Distributions to partners                                                              |       | (1,028,526                                                    | )           | — |   | (1,711,811 | ) |
| Syndication Costs                                                                      |       | —                                                        |        | — |   | (11,256,747 | ) |
| Net cash provided by (used in) financing   activities                                  |       | 3,721,474                                                     |        | (490,665 | ) | 63,140,461 |   |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Net increase (decrease) in cash and cash   equivalents                                 |       | (17,107,166                                                   | )           | (16,305,639 | ) | 22,997,717 |   |
| Cash and cash equivalents, beginning of year                                           |       | 18,243,848                                                    |        | 34,549,487 |   | 11,551,769 |   |
|                                                                                   |       |                                                          |        |   |   |   |   |
| Cash and cash equivalents, end of year                                                 |       | $                                                             | 1,136,682   |   | $ | 18,243,848 |   | $ | 34,549,487 |   |
|                                                                                   |       |                                                          |        |   |   |   |   |
| **Supplemental cash flow disclosure**                                                  |       |                                                          |        |   |   |   |   |
| Cash paid for interest expense on note payable                                         |       | $                                                             | 128,472     |   | $ | — |   | $ | — |   |
| **Supplemental disclosure of   non-cash investing transactions**                       |       |                                                          |        |   |   |   |   |
| Property sales included in accounts receivable   from affiliates                       |       | $                                                             | 59,455      |   | $ | — |   | $ | — |   |
| Property additions included in accounts payable                                        |       | $                                                             | —      |   | $ | (141,179 | ) | $ | (1,035,331 | ) |
| Property additions included in accounts payable to   affiliates                        |       | $                                                             | —      |   | $ | (68,725 | ) | $ | (2,591,370 | ) |
| Property additions included in accrued liabilities                                     |       | $                                                             | —      |   | $ | (185,653 | ) | $ | — |   |
| Additions to property and asset retirement   obligation                                |       | $                                                             | (668,800    | ) | $ | — |   | $ | (213,365 | ) |
| Property additions related to Davric default                                           |       | $                                                             | (435,390    | ) | $ | — |   | $ | — |   |
| **Supplemental disclosure of   non-cash financing transactions**                       |       |                                                          |        |   |   |   |   |
| Distributions included in accrued liabilities                                          |       | $                                                             | —      |   | $ | — |   | $ | 79,484 |   |

* *

*See accompanying notes to financial statements.*

 

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Table of Contents

 

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

Notes to Financial Statements (continued)

 

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

 

The Partnership engages in oil and gas development and production in a producing oil property located in the Slaughter Field in Cochran County, Texas, approximately 50 miles southwest of Lubbock, Texas (the “Slaughter Dean Project”).  During 2010, the Partnership also acquired working interests in certain oil and gas properties as described in detail in Note 2 “Acquisitions” below.  The Partnership 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. Acquisitions**

 

On January 19, 2010, RCWI, L.P. (“RCWI”), an affiliate of the Partnership, completed the acquisition of certain working interests in oil and gas properties from Azalea Properties Ltd. (“Azalea Properties”) for a purchase price of $21,610,116 pursuant to a Purchase and Sale Agreement between RCWI and Azalea Properties dated December 18, 2009 (the “Azalea Purchase Agreement”).  The Azalea Purchase Agreement 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”).

 

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

Notes to Financial Statements (continued)

 

Subsequently, RCWI entered into a Purchase and Sale Agreement with the Partnership (the “RCWI Agreement”), dated January 19, 2010, to sell portions of the working interests acquired from Azalea Properties to the Partnership.  The Partnership acquired 61% of the working interests initially acquired by RCWI from Azalea Properties for a purchase price of $13,182,171 in cash subject to post-closing adjustments.  RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The acquired working interests (“Azalea Acquired Properties”) cover more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset acreage. Approximately $10.7 million of the purchase price is associated with proved developed reserves.

 

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

 

On June 15, 2010, Reef Oil & Gas Income and Development Fund IV (“Income Fund IV”) paid $1,252,844 to Azalea Properties for the post closing settlement related to the Side Letter Agreements which were a part of the original Azalea Purchase Agreement. The Partnership reimbursed Income Fund IV $764,235 for its 61% of the post closing settlement amount. There was no additional payment for undeveloped properties; the entire post closing settlement is associated with proved developed reserves related to seventeen properties that were not included in the January 19, 2010 closing as a result of title issues and preferential purchase rights held by other parties that were unresolved at January 19, 2010.

 

On June 23, 2010, RCWI entered into a Purchase and Sale Agreement (the “Lett Purchase Agreement”) with Lett Oil & Gas, L.P. (“Lett”) for certain oil and gas property interests owned by Lett for a purchase price of $6,000,000.  The properties (“Lett Acquired Properties”) are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells.  The entire $6,000,000 purchase price is associated with proved developed reserves. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.   The Lett Purchase Agreement acknowledged two $500,000 deposits which were refundable to RCWI only upon certain terms set forth in the agreement and which were credited towards the purchase price at closing.  The Partnership advanced the two $500,000 deposits as well as the remaining $5,000,000 of the purchase price payable at closing by RCWI under the Lett Purchase Agreement.  The oil and gas properties included in the purchase transaction were acquired by RCWI for benefit of the Partnership and were assigned directly to the Partnership at closing pursuant to an Assignment, Conveyance and Bill of Sale dated June 30, 2010, but effective June 1, 2010.

 

The transaction described above is recorded under acquisition accounting rules.  The Partnership allocated the entire $6,000,000 to proved properties based on the fair value of the assets acquired at the acquisition date. Revenues and expenses related to June 2010 are treated as a purchase price adjustment.  Revenues and expenses subsequent to June 2010 related to the Lett Acquired Properties are included in the statements of operations for the year ended December 31, 2010.  Revenues related to the Lett Acquired Properties were $559,452 for the year ended December 31, 2010.  The Partnership recorded impairment expense of $2,203,927 related to the Lett Acquired Properties during the year ended December 31, 2010.  The Partnership also recorded $61,037 of acquisition related costs during the year ended December 31, 2010, as general and administrative expenses on its statements of operations.

 

The following unaudited pro forma condensed consolidated statements of revenue and earnings for the years ended December 31, 2010 and 2009 are presented as if the acquisitions of the Azalea Acquired Properties and the Lett Acquired Properties had occurred at the beginning of the periods presented. The unaudited pro forma condensed consolidated financial information is not indicative of our financial position or the results of our operations that might have actually occurred if the acquisition of the Azalea Acquired Properties and Lett Acquired Properties had occurred at the dates presented or of our future financial position or results of operations. The information presented for the year ended December 31, 2010 includes pro forma information for the Lett Acquired Properties only, as the Azalea Acquired Properties are included in the statements of operations of the Partnership beginning January 2010.

 

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

Notes to Financial Statements (continued)

 

**Unaudited Pro Forma Condensed Consolidated Statements of Revenues and Earnings**

 
| **For the Year Ended December 31,** | ** ** | **2010** | ** **  | **2009** | ** ** |
|--------------------------------------------------------------|------------|----------|-------------|----------|------------|
|                                                         |       |     |        |     |       |
| Revenues                                                     |       | $        | 6,019,282   |     | $          | 4,904,198 |   |
| Net loss                                                     |       | $        | (58,883,524 | )        | $          | (5,841,977 | ) |
|                                                         |       |     |        |     |       |
| Net loss per general partner unit                            |       | $        | (65,676.03  | )        | $          | (6,679.85 | ) |
| Net loss per limited partner unit                            |       | $        | (65,676.03  | )        | $          | (6,679.85 | ) |
| Net income (loss) per managing general partner   unit        |       | $        | (62,791.11  | )        | $          | 10,003.09 |   |

 

**3. Summary of Accounting Policies**

 

**Use of Estimates**

 

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

 

**Cash and Cash Equivalents**

 

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

 

**Risks and Uncertainties**

 

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

 

The Partnership has not engaged in commodity futures trading or hedging activities and has not entered into derivative financial instrument transactions for trading or other speculative purposes. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

 

**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, 2010, 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 2010. 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

 

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Table of Contents

 

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

Notes to Financial Statements (continued)

 

gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the years ended December 31, 2010, 2009 and 2008, the Partnership recognized property impairment expense of proved properties of $4,777,151, $668,430 and $0, respectively.

 

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 Project. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the year ended December 31, 2010, the Partnership recognized property impairment expense of unproved properties of $53,166,873. During the years ended December 31, 2009 and 2008, the Partnership recognized no property impairment expense of unproved properties.

 

**Estimates of Proved Oil and Gas Reserves**

 

Estimates of the Partnership’s proved reserves at December 31, 2010 and 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

 

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Table of Contents

 

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

Notes to Financial Statements (continued)

 

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, 2010 and 2009.

 
| ** **                                | ** ** | **2010** | ** ** | **2009**   | ** ** |
|-------------------------------------------|------------|----------|------------|------------|------------|
| Beginning asset retirement obligation     | ** ** | **$**    | 248,912    | ** ** | **$**      | 230,472 | ** ** |
| Additions related to new properties       |       | 668,800  |       | —     |       |
| Retirement related to sales of properties |       | (76,156  | )          | —     |       |
| Accretion expense                         |       | 62,390   |       | 18,440     |       |
| Ending asset retirement obligation        | ** ** | **$**    | 903,946    | ** ** | **$**      | 248,912 | ** ** |

 

**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, 2010, 2009, and 2008.

 

**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, 2010, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $32.1 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, 2010.

 

**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. The fair market value of the Partnership’s long-term debt approximates the carrying value at December 31, 2010.

 

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

Notes to Financial Statements (continued)

 

**Recently Adopted Accounting Pronouncements**

 

**Modernization of Oil and Gas Reporting**

 

In January 2009, the SEC adopted a new rule 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 unweighted 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 Financial Accounting Standards Board (“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. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.

 

**4. Long-Term Debt**

 

On June 30, 2010, the Partnership and Texas Capital Bank, N.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) which currently has a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding the acquisition of oil and gas properties purchased from Lett by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in Note 2 above.  The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. At December 31, 2010, the interest rate was 5.17%.  The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2013, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.  At June 30, 2010, the borrowing base was equal to $5,000,000.  The Partnership borrowed $5,000,000 from TCB under the Credit Agreement which was paid directly to Lett to satisfy the closing obligations of RCWI under the Lett Purchase Agreementdescribed in Note 2 above.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.  In December 2010, the Partnership prepaid $250,000 of principal to TCB.

 

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

 

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

 

The Credit Agreement contains various covenants, including among others:

 

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Table of Contents

 

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

Notes to Financial Statements (continued)

 

·                  restrictions on liens;

 

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

 

·                  restrictions on distributions and other restricted payments; 

 

·                  maintenance of a current ratio as of the end of each fiscal quarter commencing September 30, 2010 of not less than 1.0 to 1.0, as adjusted; and

 

·                  maintenance of an interest coverage ratio of cash flow to fixed charges as of the end of each fiscal quarter commencing September 30, 2010, to be at least 3.0 to 1.0. 

 

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

 

·                  failure to make payments under the Credit Agreement; 

 

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

 

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

 

At December 31, 2010, the Partnership was not in compliance with certain non-financial covenants under the Credit Agreement, for which it obtained a waiver from the lender.

 

**5. 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, 2010, 2009 and 2008, Reef received $101,085, $49,050, and $195,938, 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.

 

Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, currently serves as the operator of the Slaughter Dean Project and receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership.  RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells included in the Azalea Acquired Properties and the Lett Acquired Properties. All of the wells included in these two purchases are non-operated. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point.  In addition, total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion.  Total well costs do not include costs relating to lease acquisitions.  During the year ended December 31, 2010, RELP received $232,775 in drilling compensation. During the year ended December 31, 2009, RELP received $1,544,858 in drilling compensation.  Drilling compensation payments are included in oil and gas properties in the financial statements.

 

Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership. During the year ended December 31, 2010, Reef and its affiliates received total

 

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

Notes to Financial Statements (continued)

 

reimbursements for direct costs and other documented out-of-pocket expenses of $441,881 and $10,192, respectively. 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, no reimbursements were made to Reef and its affiliates for direct or out-of-pocket costs.

 

RELP receives an administrative fee to cover all general and administrative costs in an amount equal to 1/12 th of 1% of all capital raised payable monthly.  During the years ended December 31, 2010, 2009, and 2008, RELP received $896,880, $896,880, and 700,706, respectively, in administrative fees.  During the year ended December 31, 2010, administrative fees are included in general and administrative expense in the financial statements. During the years ended December 31, 2009 and 2008, $595,381 and $593,093, respectively, of administrative fees were capitalized and are included in property costs in the financial statements, with the remainder included in general and administrative expenses.  RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

 

Beginning on January 1, 2010, RELP began processing joint interest billings and revenues on behalf of the Partnership. At December 31, 2010, RELP owed the Partnership $45,640 for net revenues processed in excess of joint interest and technical and administrative services charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month to which the revenues pertain.  Prior to 2010, the Partnership processed its own joint interest billings and revenues.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Granite Wash formation located in Wheeler County, Texas and Roger Mills County, Oklahoma, to Reef 2010 Drilling Fund, L.P., a Reef affiliate.  These interests were sold primarily due to the intended or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities. The sale included the Partnership’s interests in nine existing wells, as well as the undeveloped acreage on which additional wells are intended to be drilled.  The Partnership received $933,300 in cash in exchange for these interests.

 

In December 2010, the Partnership sold its interests in certain oil and gas properties in the Lusk Field in Lea County, New Mexico, to Reef 2010 Drilling Fund, L.P., a Reef affiliate. These interests were sold primarily due to the planned or actual drilling of exploratory wells on the acreage involved.  In accordance with its stated objectives, the Partnership will not participate in exploratory drilling activities.  The sale included the Partnership’s interests in five existing wells, as well as the undeveloped acreage upon which an exploratory well is intended to be drilled.  The Partnership accepted a sales price of $59,455 in exchange for these interests, of which the entire amount is included in accounts receivable from affiliates on the balance sheet as of December 31, 2010.

 

**6. Major Customers**

 

The Partnership may sell crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues can be received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues.  During the year ended December 31, 2010, one marketer accounted for 39.5% and one operator accounted for 20.8% of the Partnerships crude oil and natural gas revenues.  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 2009 and 2008, the Partnership’s only oil and gas property was the Slaughter Dean Project located in Cochran County, Texas. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

 

**7. Commitments and Contingencies**

 

The Partnership is not currently involved in any legal proceedings.

 

F-13

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Table of Contents

 

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

Notes to Financial Statements (continued)

 

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.

 

**8. Partnership Equity**

 

Information regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the years ended December 31, 2010, 2009 and 2008 is detailed below:

 

For the year ended December 31, 2010

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

 

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 | )                                 |       |   |

 

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    |                                |       |   |

 

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

 

**Capitalized Costs**

 

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

 

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Table of Contents

 

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

Notes to Financial Statements (continued)

 
| ** **                                             | ** ** | **December   31, 2010** | ** **     | **December   31, 2009** | ** ** | **December   31, 2008** | ** ** |
|--------------------------------------------------------|------------|------------------------------|----------------|------------------------------|------------|------------------------------|------------|
| ** **                                             | ** ** | ** **                   | ** **     | ** **                   | ** ** | ** **                   | ** ** |
| **Oil and natural gas properties:**                    |       |                         | ** **     | ** **                   | ** ** | ** **                   | ** ** |
| Unproved properties                                    | ** ** | **$**                        | 55,136,307     | ** **                   | **$**      | 52,010,728                   | ** ** | **$** | 38,582,968 | ** ** |
| Proved properties                                      |       | 21,430,901                   |           | 3,358,680                    |       | 3,358,680                    |       |
| Capitalized asset retirement obligation                |       | 810,574                      |           | 213,365                      |       | 213,365                      |       |
|                                                   | ** ** | **77,377,782**               | ** **     | **55,582,773**               | ** ** | **42,155,013**               | ** ** |
| Less:                                                  | ** ** | ** **                   | ** **     | ** **                   | ** ** | ** **                   | ** ** |
| Accumulated depreciation, depletion and   amortization |       | (2,477,455                   | )              | (538,943                     | )          | (232,436                     | )          |
| Property impairment                                    |       | (58,612,454                  | )              | (668,430                     | )          | —                       |       |
| ** **                                             | ** ** | **(61,089,909**              | **)**          | **(1,207,373**               | **)**      | **(232,436**                 | **)**      |
| ** **                                             | ** ** | ** **                   | ** **     | ** **                   | ** ** | ** **                   | ** ** |
| **Total**                                              | ** ** | **$**                        | **16,287,873** | ** **                   | **$**      | **54,375,400**               | ** ** | **$** | **41,922,577** | ** ** |

 

**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, 2010, 2009, and 2008 are as follows by the year in which such costs were incurred:

 
| ** **             | ** ** | **Total**  | ** ** | **2010**   | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| Acquisition   costs    | ** ** | **$**      | 14,499,637 | ** ** | **$**      | 2,486,463  | ** ** | **$**      | **—** | ** ** | **$** | 11,901,435 | ** ** |
| Development   costs    |       | 33,924,710 |       | 406,341    |       | 10,929,932 |       | 22,588,437 |       |
| Capitalized   overhead |       | 6,711,960  |       | 232,775    |       | 2,497,828  |       | 3,981,357  |       |
| ** **             | ** ** | **$**      | 55,136,307 | ** ** | **$**      | 3,125,579  | ** ** | **$**      | 13,427,760 | ** ** | **$** | 38,471,229 | ** ** |

 

Unproved property consists primarily of the capitalized costs associated with the development and enhancement of waterflood operations in the Slaughter Dean Project.  In addition, the Partnership recorded $2,486,463 of unproved properties during the year ended December 31, 2010 related to the Azalea Acquired Properties.  Based on its reevaluation of reservoir response at December 31, 2010, the Partnership has recognized no proved reserves related to the waterflood, and at December 31, 2010, the Partnership recognized impairment of unproved properties of $53,166,873 related to the Slaughter Dean Project.

 

**Costs Incurred**

 

The following table sets forth the costs incurred in oil and gas exploration and development activities during the periods ended December 31, 2010, 2009, and 2008.

 
| ** **                          | ** ** | **2010**   | ** **     | **2009**   | ** ** | **2008**       | ** ** |
|-------------------------------------|------------|------------|----------------|------------|------------|----------------|------------|
| ** **                          | ** ** | ** ** | ** **     | ** ** | ** ** | ** **     | ** ** |
| **Oil and natural gas properties:** | ** ** | ** ** | ** **     | ** ** | ** ** | ** **     | ** ** |
| Exploration                         | ** ** | **$**      | **—**     | ** ** | **$**      | **—**     | ** ** | **$** | — | ** ** |
| Development                         |       | 21,795,010 |           | 13,427,760 |       | 42,043,274     |       |
| **Total**                           | ** ** | **$**      | **21,795,010** | ** ** | **$**      | **13,427,760** | ** ** | **$** | **42,043,274** | ** ** |

 

**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, 2010, 2009 and 2008.

 

F-15

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Table of Contents

 

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

Notes to Financial Statements (continued)

 
| ** **                                            | ** ** | **2010**    | ** **      | **2009**   | ** ** | **2008**     | ** ** |
|-------------------------------------------------------|------------|-------------|-----------------|------------|------------|--------------|------------|
| ** **                                            | ** ** | ** **  | ** **      | ** ** | ** ** | ** **   | ** ** |
| **Oil and gas producing   activities:**               |       |        |            |       | ** ** | ** **   | ** ** |
| Oil sales                                             |       | $           | 4,713,431       |       | $          | 1,645,056    | ** ** | **$** | 1,949,274 | ** ** |
| Natural gas sales                                     |       | 885,659     |            | 10,756     |       | 63,215       |       |
| Production expenses                                   |       | (2,754,884  | )               | (1,376,124 | )          | (1,284,501   | )          |
| Accretion of asset retirement obligation              |       | (62,390     | )               | (18,440    | )          | (17,107      | )          |
| Depreciation, depletion and amortization              |       | (1,933,948  | )               | (306,507   | )          | (232,436     | )          |
| Property impairment                                   |       | (57,944,024 | )               | (668,430   | )          | —       |       |
| **Results of operations from   producing activities** | ** ** | **$**       | **(57,096,156** | **)**      | **$**      | **(713,689** | **)**      | **$** | **478,445** | ** ** |
| ** **                                            | ** ** | ** **  | ** **      | ** ** | ** ** | ** **   | ** ** |
| Depletion rate per BOE                                |       | $           | 19.72           |       | $          | 8.90         | ** ** | **$** | 9.68 | ** ** |

 

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

 

**Crude Oil and Natural Gas Reserves**

 

**Net Proved Developed Reserve Summary**

 

The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2010, and by William M. Cobb & Associates as of December 31, 2009 and 2008.   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, 2010, 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, 2010, 2009 and 2008.

 
| ** **                                                    | ** ** | **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          |       |
|                                                          |       |                          |       |                 |       |             |       |
| Purchases of reserves in place                                |       | 566,505                       |       | 1,607,592            |       | 834,437          |       |
| Revisions of previous estimates                               |       | 223,647                       |       | (265,604             | )          | 179,380          |       |
| Production                                                    |       | (66,352                       | )          | (190,208             | )          | (98,053          | )          |
| Reserves at December 31, 2010                            |       | 838,200                       |       | 1,217,840            |       | 1,041,174        |       |

 

F-16

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Table of Contents

 

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 years ended December 31, 2010 and 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, 2010, calculations were made using average prices of $79.79 per barrel of crude oil and $4.39 per MCF of natural gas. 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 3, “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, 2010, 2009 and 2008 were as follows:

 

F-17

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Table of Contents

 

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

Notes to Financial Statements (continued)

 
| ** **                                  | ** ** | **December   31, 2010** | ** **     | **December   31, ****2009** | ** ** | **December   31, 2008** | ** ** |
|---------------------------------------------|------------|------------------------------|----------------|----------------------------------|------------|------------------------------|------------|
| Future cash inflows                         |       | $                            | 68,288,340     |                             | $          | 6,761,420                    |       | $ | 14,389,086 |   |
| Future production costs                     |       | (34,643,170                  | )              | (3,482,310                       | )          | (7,377,434                   | )          |
| Future development costs                    |       | —                       |           | —                           |       | —                       |       |
| Future net cash flows                       | ** ** | **33,643,170**               | ** **     | **3,279,110**                    | ** ** | **7,011,652**                | ** ** |
| Effect of discounting net cash flows at 10% |       | (19,326,730                  | )              | (906,310                         | )          | (2,527,910                   | )          |
| Discounted future net cash flows            | ** ** | **$**                        | **14,318,440** | ** **                       | **$**      | **2,372,800**                | ** ** | **$** | **4,483,742** | ** ** |

 

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

 
| ** **                                         | ** ** | **December   31, 2010** | ** **     | **December   31,****2009** | ** ** | **December   31, 2008** | ** ** |
|----------------------------------------------------|------------|------------------------------|----------------|----------------------------|------------|------------------------------|------------|
| Standardized measure at beginning of period        |       | $                            | 2,372,800      |                       | $          | 4,483,742                    |       | $ | — |   |
| Purchases of minerals in place                     |       | 11,899,186                   |           | —                     |       | 5,211,730                    |       |
| Net change in sales price, net of production costs |       | 868,538                      |           | 1,453,208                  |       | —                       |       |
| Revisions of quantity estimates                    |       | 1,995,861                    |           | (2,722,758                 | )          | —                       |       |
| Changes in production timing rates                 |       | (273,409                     | )              | (1,028,518                 | )          | —                       |       |
| Accretion of discount                              |       | 237,280                      |           | 448,374                    |       | —                       |       |
| Sales net of production costs                      |       | (2,781,816                   | )              | (261,248                   | )          | (727,988                     | )          |
| Net increase (decrease)                            |       | 11,945,640                   |           | (2,110,942                 | )          | 4,483,742                    |       |
| Standardized measure at end of year                | ** ** | **$**                        | **14,318,440** | ** **                 | **$**      | **2,372,800**                | ** ** | **$** | **4,483,742** | ** ** |

 

F-18

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