UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For The Fiscal Year Ended December 31, ~~2010~~2011

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 333-122935-02

REEF GLOBAL ENERGY VII, L.P.

(Exact name of registrant as specified in its charter)

Nevada		20-3963203
(State or other jurisdiction of		(I.R.S. Employer
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
incorporation or organization)		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 ox 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 March 31 27, ~~2011~~2012, the registrant had 48.620 units of general partner interest held by the managing general partner, and 923.784 units of limited partner interest outstanding.

Documents incorporated by reference: None

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REEF GLOBAL ENERGY VII, L.P.

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, ~~2010~~2011

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Part I
Item 1.	Business
Item 1A.	Risk Factors
Item 1B.	Unresolved Staff Comments
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	~~(Removed~~Mine ~~and~~Safety ~~Reserved)~~Disclosures
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

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PART I

ITEM 1. BUSINESS

Introduction

Reef Global Energy VII, L.P. (the Partnership) is the second in a series of four Nevada limited partnerships comprising a program called Reef Global Energy Ventures II (the Program). The Partnership was formed in the state of Nevada on December 29, 2005. The Partnership purchased working interests in oil and gas prospects and participated in the drilling of wells on those prospects. The primary objectives of the Partnership are to generate revenue from the production of crude oil and natural gas, distribute cash to the partners, and provide tax benefits. Reef Oil & Gas Partners, L.P. (Reef) is the managing general partner of the Partnership.

The Partnership was formed to drill, complete and own working interests in oil and gas wells located onshore in the continental United States. The Partnership purchased working interests in six developmental prospects upon which it participated in the drilling of twenty-one developmental wells. The Partnership purchased working interests in seven exploratory prospects upon which it participated in the drilling of seven exploratory wells and one developmental well. These prospects are located onshore in Louisiana, New Mexico, Texas, and Wyoming. In 2008, the Partnership completed drilling operations with the capital ~~previously~~ raised by the Partnership. The Partnership will not purchase additional prospects. In accordance with the Partnership’s limited partnership agreement, (the Partnership Agreement), the Partnership may conduct additional drilling operations to fully develop those prospects already owned by the Partnership.

Other partnerships formed as a part of the Program also own working interests in some of the prospects owned by this Partnership. Reef has also purchased working interests in certain partnership prospects for some of the other partnerships it manages. In instances where the percentage ownership of the Partnership and Reef-affiliated entities in a prospect is large enough, Reef Exploration, L.P. (RELP), an affiliate of Reef formed in 2005, serves as operator of the prospect. RELP serves as operator of ~~three~~two developmental and two exploratory Partnership prospects. RELP operates ~~sixteen~~nine successful developmental wells, one of which has been converted to a salt water disposal well~~, and operates one successful developmental well~~. In this Annual Report on Form 10-K (Annual Report), we use the term “successful” to refer to wells that are drilled, tested, and either capable of or actually producing in commercial quantities. We use the term “unsuccessful” to refer to wells that do not meet one or more of these criteria.

Acquisition and Drilling of Undeveloped Prospects

The Partnership purchased working interests in three developmental and one exploratory prospect internally sourced by RELP, and three developmental and six exploratory prospects generated by and purchased from third parties. A “prospect” is generally defined as a contiguous oil and gas leasehold estate, or lesser interest in a leasehold estate, upon which drilling operations may be conducted. A prospect may be characterized as “exploratory” or “developmental” based upon the type of well to be drilled on the prospect. A developmental well is a well drilled within a proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Generally an exploratory well is any well that is not a developmental well, including wells drilled to find and produce oil or gas in an unproven area, wells drilled to find a new reservoir in a field previously found to be productive of oil or gas, or wells drilled to extend a known reservoir.

Prospects were evaluated utilizing data generated by RELP or provided by unaffiliated third parties to RELP. This data included well logs, production records from other area wells, seismic, geological and geophysical information, and such other information available and considered useful. Prospects in which the Partnership purchased a working interest were evaluated by petroleum engineers, geophysicists, geologists, and other technical consultants employed by or retained by RELP on the Partnership’s behalf.

The Partnership prospects were acquired pursuant to an arrangement in which the Partnership purchased part of the working interest. A working interest bears a specified portion of the costs of development, operation and maintenance. A working interest is subject to landowners’ royalty interests and may be subject to other royalty interests payable to unaffiliated third parties. Where the Partnership acquired less than 100% of the working interest, costs were reduced proportionately. The Partnership Agreement prohibits Reef or any of its affiliates from retaining

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any overriding royalty interest, that is, any royalty interest that would be paid out of the Partnership’s working interest, in any working interest purchased by the Partnership. The Partnership is a non-operator working interest owner in all prospects purchased by the Partnership.

Drilling and Completion Phase of Operations

On all prospects currently operated by RELP, drilling operations were contracted to independent third party drillers, and the costs of the wells to the Partnership were determined by actual third party costs, plus monthly operator fees charged at the competitive rate for the geographical area where the wells are located.

The Partnership generally pays drilling and completion costs as incurred. Wells drilled that failed to result in the discovery of commercial quantities of crude oil or natural gas were plugged and abandoned in accordance with applicable regulations. Three development wells and six exploratory wells in which the Partnership participated in drilling operations were unsuccessful. Nineteen developmental and one exploratory well in which the Partnership participated in drilling operations were successful. The successful exploratory well ceased production during 2007. One of the nineteen successful developmental wells was converted to a salt water disposal well during 2010.

RELP is currently the operator of ~~three~~two developmental and two exploratory prospects, and serves as operator of ~~seventeen~~nine successful developmental wells in which the Partnership has a working interest, including the eight wells located on the Sand Dunes prospect discussed in more detail in “Item 2 — Properties”. RELP also served as operator for two unsuccessful Partnership wells. As a well operator, RELP receives operator fees during the drilling and production phase of each well at the competitive rate in the geographical area where the well is located. These fees are charged as a monthly fee per well as agreed to in an operating agreement signed by the Partnership and participating third parties in the well. The wells are subject to a model form operating agreement issued by the American Association of Petroleum Landmen and an accounting procedure for joint operations issued by the Council of Petroleum Accountants Societies of North America.

Production Phase of Operations

Wells capable of producing quantities of crude oil and/or natural gas in commercial quantities, were completed by installing all surface equipment necessary to control the flow of production or to shut down the well, and by installing any storage facilities, gathering lines, or sales lines required to produce and sell the crude oil and/or natural gas production from the well. The Partnership ~~drilled~~participated in the drilling of nineteen successful developmental wells, including the eight wells located on the Sand Dunes prospect discussed in more detail in “Item 2 — Properties”, and one successful exploratory well. The successful exploratory well ceased producing during 2007. RELP currently operates ~~seventeen~~nine Partnership wells and third parties operate two Partnership wells.

On August 24, 2011, the Partnership completed the sale of certain assets in accordance with a Purchase and Sale Agreement among the Partnership, Reef Exploration, L.P., Reef Global Energy VIII, L.P., and Reef Global Energy IX, L.P., affiliates of the Partnership, as sellers, and with Energen Resources Corporation (“Energen”) as buyer. This agreement includes the sale of all rights, title, and interest in leases, lands, and wells located in Glasscock County, Texas (“Cole Ranch Properties”) for an aggregate purchase price to the selling parties of $10,000,000, subject to certain purchase price adjustments. The Partnership received approximately $4,438,400 of the purchase price, prior to purchase price adjustments. The Cole Ranch Properties were assigned directly to Energen at closing pursuant to an Assignment, Conveyance and Bill of Sale whereby Energen received all economic interests in the Cole Ranch Properties as if those properties had been transferred to Energen on July 1, 2011. Prior to the sale, RELP had served as the operator of eight successful developmental wells located on the Cole Ranch Properties.

The Partnership has entered into agreements with third party marketers to sell the crude oil and/or natural gas produced from successful wells on a competitive basis at the best available terms and prices. In some cases the Partnership has elected to sell its production under marketing arrangements entered into by the operator of the well. Generally, purchase contracts for the sale of crude oil are cancelable on 30 days’ notice, but purchase contracts for the sale of natural gas may have a longer term. The Partnership sells natural gas discovered by it at negotiated prices domestically, based upon a number of factors, such as the quality of the gas, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission (FERC).

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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 balance for crude oil.

The Partnership has not and does not expect to engage in commodity futures trading or hedging activities, or enter into derivative financial instrument transactions for trading or other speculative purposes. 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. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”

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The Partnership’s share of revenue from productive wells is burdened by and/or subject to royalties and overriding royalties, monthly operating charges, and other operating costs. These items of expenditure involve amounts payable solely out of, or expenses incurred solely by reason of, production operations. The Partnership deducts operating expenses from the production revenue for the corresponding period.

Major Customers

The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, ~~2010~~2011, ~~two~~one ~~marketers~~marketer and one operator accounted for 2027.~~1%, 35.~~5%, and 4363.59% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, ~~2009~~2010, two marketers and one operator accounted for 3320.41%, 3935.45%, and 2643.95% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, ~~2008~~2009, two marketers and one operator accounted for 4133.74%, 4139.4%, and 1426.9% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

Insurance

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

The Partnership is a named insured under various insurance policies and intends to maintain such policies subject to its analysis of their premium costs, coverage and other factors. In the exercise of Reef ‘s fiduciary duty as managing general partner, Reef has obtained insurance on behalf of the Partnership to provide the Partnership with such coverage as Reef believes is sufficient to protect the investor partners against the foreseeable risks of drilling and production. Reef reviewed the Partnership insurance coverage prior to commencing drilling operations and periodically evaluates the sufficiency of insurance. In no event will the Partnership maintain public liability insurance of less than two times the Partnership’s capitalization. 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 Reef deems appropriate under the circumstances, which may vary materially.

In accordance with the Partnership Agreement of the Partnership, all general partner units held by investors were converted into limited partner units during the third quarter of 2008. At that time, Reef amended the Certificate of Limited Partnership to effectuate the conversion of the interest of the former non-Reef general partners to that of a limited partner. Non-Reef general partners will have limited liability as a limited partner for any Partnership operations conducted after their conversion date. However, non-Reef general partners that converted to limited partners continue to have unlimited liability regarding partnership activities that occurred prior to their conversion date.

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Competition

There are thousands of oil and ~~natural~~ gas companies in the United States. Competition is strong among persons and entities involved in 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 the supply. As a result of deregulation of the natural gas industry enacted by Congress and FERC, natural gas prices are generally determined by competitive market forces. Prices of crude oil, condensate and natural gas liquids are not currently regulated and are generally determined by competitive market forces.

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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 power;

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

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

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

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

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

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

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.6

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month a well can produce. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits such as hazardous materials certificates, which RELP has obtained.

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

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

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

Proposed Regulation. Various legislative proposals are being considered in Congress and in the legislatures of various states, which, if enacted, may significantly and adversely affect the petroleum and 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 its 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.”

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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 prospects, including its intent to diversify the Partnership’s investments;

· statements estimating any number or specific type or size of prospects the Partnership may acquire or size of the interest the Partnership may acquire in such prospects;

· 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;

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

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

· any statements of other than historical fact.

Reef believes that it is important to communicate its future expectations to the partners. Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the 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 Partnership does not intend, and is not expected, to continue as a going concern.

The original business plan for the Partnership was to use its initial capital to purchase working interests in oil and gas prospects, participate in the drilling of oil and gas wells on those prospects, retain ownership of successful wells until they were either sold or ceased operations, and distribute all operating cash flows and sales proceeds to the investor partners. It was not expected that operating revenues would be reinvested in the business other than such funds as would be necessary to maintain operation of the original wells drilled by the Partnership.

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Partnership distributed the Cole Ranch sales proceeds to investors, and has no plans to drill additional wells. The Partnership also has no plans to engage in commodity futures trading or hedging activities. Finally, the estimated economic reserve life of Partnership wells is computed based upon operating revenues and costs and does not consider Partnership general and administrative costs. Future cash flows generated from Partnership wells will be significantly impacted by actual prices received subsequent to December 31, 2011, and by actual production volumes from the Partnership’s most significant wells. While management anticipates that the Partnership will generate positive cash flows during 2012, variations in pricing and production volumes could lead to rapidly declining cash flows from operations and Partnership losses. Our independent registered public accounting firm’s opinion on our 2011 financial statements includes an explanatory paragraph indicating substantial doubt about our ability to continue as a going concern.

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

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

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

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

· domestic government regulations and taxes;

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

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

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

· domestic and worldwide economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, crude oil and natural gas prices do not necessarily move in tandem. Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the amount of crude oil and natural gas that can be economically produced from successful wells drilled by the Partnership, and, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas reserves, and the carrying value of the Partnership’s oil and gas properties. Approximately 5530.35% of the Partnership’s estimated proved reserves were crude oil reserves and 69.5% were natural gas reserves at December 31, 2011. As a result, the Partnership’s financial results are sensitive to fluctuations in both crude oil and natural gas prices.

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estimated proved reserves were crude oil reserves and 44.7% were natural gas reserves at December 31, 2010. As a result, the Partnership’s financial results are sensitive to fluctuations in both crude oil and natural gas 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 not engaged in such activities. 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~~A ~~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 has~~ had an adverse impact on demand and pricing for crude oil and natural gas. AAnother ~~continuation~~downturn ofsimilar ~~the~~to ~~economic~~that ~~downturn~~experienced in 2008 and 2009 could ~~have~~lead to a ~~further~~similar negative impact on crude oil and natural gas prices. ~~The~~or ~~Partnership’s~~reduced ~~operating~~demand ~~cash~~for ~~flows~~crude oil and ~~profitability~~natural ~~will~~gas bethat ~~significantly~~could ~~affected~~have bya ~~declining~~significant ~~crude~~impact ~~oil~~on ~~and~~the ~~natural~~Partnership’s ~~gas~~operating ~~prices.~~cash ~~Further~~flows ~~declines~~and profitability. Declines in crude oil and natural gas prices may also impact the value of our crude oil and natural gas reserves, which could result in future impairment charges to reduce the carrying value of the Partnership’s oil and gas properties.

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We are subject to substantial operating risks that may adversely affect the results of operations.

There are numerous hazards involved in the drilling and operation of oil and gas wells, including blowouts involving possible damages to property and third parties, bodily injuries, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressure, pollution, releases of toxic gas and other environmental hazards and risks. The Partnership could suffer substantial losses as a result of any of these risks. The Partnership is not fully insured against all risks inherent to the oil and gas business. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for the general partners. Although the Partnership maintains insurance coverage in amounts Reef deems appropriate, it is possible that insurance coverage may be insufficient. In that case Partnership assets may have to be sold to pay personal injury and property claims and the cost of controlling blowouts or replacing damaged equipment rather than for drilling activities.

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 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.

8You 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, 2011 are based upon the 12-month unweighted 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.

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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 unweighted arithmetic average of the first-day-of-the-month prices and costs in effect when the estimate is made. Actual current prices, as well as future prices and costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.

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

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

· Reef determines in good faith that its action was in the best interest of the Partnership; · Reef was acting on behalf of or performing services for the Partnership; and · Reef’s actions did not constitute negligence or misconduct.10

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

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

· Reef’s actions did not constitute negligence or misconduct.

The production and producing life of Partnership wells is uncertain.

Production will decline. It is not possible to predict the life and production of any well. The actual life 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 well’s initial production.

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

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

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

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

We face strong competition within the energy industry.

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

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consummate transactions, and obtain technical, managerial and other professional personnel in this highly competitive environment. Specifically, larger competitors may be able to pay more for competent personnel than the Partnership, Reef and its affiliates. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that will be increasingly important to success. Such competitors may also be in a better position to secure drilling and oilfield services, as well as equipment, more timely or on more favorable terms. Finally, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future.

The Partnership has limited external sources of funds, which could result in a shortage of working capital.

The Partnership expended funds in excess of the previously raised capital in connection with the drilling and completion of wells and acquisition of the prospects during the drilling phase of operations. These excess expenditures have been recovered through reductions in Partnership distributions. The Partnership only has nominal funds available for Partnership purposes until there are revenues from Partnership operations. Any future requirement for additional funding for drilling will have to come, if at all, from the Partnership’s revenues or from borrowings. Reef cannot assure the partners that Partnership operations will be sufficient to provide the Partnership with necessary additional funding. Reef cannot assure the partners that the Partnership will be able to borrow funds from third parties on commercially reasonable terms or at all.

~~The Partnership may incur liability for liens against its subcontractors.~~11

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The Partnership may incur liabilities 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 such liens.

Other partnerships Reef sponsors will compete with the Partnership for equipment, contractors, and personnel.

Reef plans to offer interests in other partnerships to be formed for substantially the same purposes as those of the Partnership. Therefore, a number of partnerships with unexpended capital funds, including those partnerships to be formed in future oil and gas programs sponsored by Reef, may exist at the same time. Due to competition among the partnerships for equipment, contractors, and Reef’s personnel, the fact that other partnerships organized by Reef and its affiliates may still be purchasing prospects and drilling and completing wells when the Partnership is attempting to drill and complete wells on its prospects may make such activities of the Partnership more difficult.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Drilling Activities and Productive Wells

Partnership prospects are located onshore in Texas, Louisiana, New Mexico, and Wyoming. The Partnership purchased working interests in six developmental prospects. The Partnership participated in drilling ten successful developmental wells and one unsuccessful developmental well on three developmental prospects located in Glasscock County, Texas, Terrebonne Parish, Louisiana, and Park County, Wyoming. The Partnership participated in drilling two unsuccessful developmental wells on two developmental prospects located in San Patricio and Lavaca County, Texas.

The Partnership participated in the drilling of eight developmental wells on the Sand Dunes prospect located in Eddy County, New Mexico during the fourth quarter of 2007 and the first quarter of 2008. Initial testing confirmed the presence of crude oil and natural gas in all eight wells. However, the field was temporarily shut-in because of the lack of electric service and because of the high cost of trucking offsite the salt water volumes associated with the production of the crude oil and natural gas from the wells. Electrical service to the eight Sand Dunes wells was connected in September 2008. Based upon initial testing, larger bottom hole pumps were placed below the well perforations in three of the wells and testing was resumed in late September 2008 to determine the three wells’ commercial productivity. Water continued to be trucked offsite, and RELP applied for and received a permit which would allow for the conversion of one of the existing eight Sand Dunes wells into a water disposal well. RELP also explored the possibility of drilling a ninth well as a salt water disposal well for the field. Testing results on two of the three wells were positive, and salt water production volumes declined as a result of pumping off the wells using the larger bottom hole pumps. However, the price of crude oil also declined at a rapid rate while testing was being conducted. In late December 2008, two of the three testing wells were shut-in again. Crude oil prices continued declining to a level below $40 per barrel. In February 2009, following a mechanical failure in the third testing well, RELP, as operator, shut-in the field. The eight wells could not be commercially productive without efficient salt water disposal capabilities, and none of the options regarding salt water disposal were economically viable at first quarter 2009 commodity prices. As of December 31, 2008, the eight Sand Dunes wells were considered temporarily non-commercial until the conversion of one of the eight wells into a salt water disposal well was completed and commodity prices recovered.

10Beginning with March 2009, oil prices increased from levels below $40 per barrel to between $60 and $70 per barrel by the third quarter of 2009. As a result of this increase in prices, in October 2009, Reef approved the conversion of one of the eight wells on the Sand Dunes development prospect located in Eddy County, New Mexico to a salt water disposal well. The conversion work on the well began in March 2010 and was completed during April 2010. Upon completion of the disposal facilities, the new disposal well became operational during August 2010. Based on the

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~~perforations~~disposal incapacity ~~three~~ of the ~~wells~~converted ~~and~~well, ~~testing~~the ~~was~~remaining ~~resumed~~seven inSand ~~late~~Dunes ~~September 2008 to determine the three~~ wells’ ~~commercial~~were ~~productivity.~~placed ~~Water~~into ~~continued~~production toas beof ~~trucked~~December ~~offsite~~31, ~~and~~2010. ~~RELP~~The ~~applied~~cost ~~for and received a permit which would allow for the conversion~~ of ~~one of~~ the ~~existing eight Sand Dunes wells into a water disposal~~ well. ~~RELP~~conversion ~~also~~to ~~explored~~this ~~the~~Partnership ~~possibility~~as of ~~drilling~~December a31, ~~ninth~~2010 ~~well~~was asapproximately a$191,152. ~~salt~~This ~~water~~cost ~~disposal~~was ~~well~~paid for by the ~~field.~~Partnership ~~Testing~~by ~~results~~retaining ona ~~two~~portion of the ~~three~~funds ~~wells~~normally ~~were~~paid ~~positive,~~out ~~and~~in ~~salt~~distributions ~~water~~to ~~production volumes declined as a result of pumping off~~ the ~~wells~~partners. ~~using~~At ~~the~~December ~~larger~~31, ~~bottom~~2010, ~~hole~~there ~~pumps.~~were ~~However~~2,350 ~~the~~BBL ~~price~~ of crude oil ~~also~~and ~~declined at a rapid rate while testing was being conducted. In late December 2008~~2,650 ~~two~~Mcf of ~~the~~natural ~~three~~gas ~~testing~~reserves ~~wells~~net ~~were shut-in again. Crude oil prices continued declining~~ to ~~a level below $40 per barrel. In February 2009, following a mechanical failure in~~ the ~~third~~Partnership’s ~~testing~~interest ~~well,~~for ~~RELP, as operator, shut-in~~ the ~~field. The eight~~ wells ~~could~~placed ~~not~~on befull ~~commercially~~time ~~productive~~production ~~without~~during ~~efficient salt water disposal capabilities, and none of the options regarding salt water disposal were economically viable at first quarter 2009 commodity prices~~2010. As a result, ~~as of December 31, 2008,~~ the ~~eight~~ Sand Dunes wells were classified as ~~unsuccessful,~~successful ~~and~~as noof ~~crude oil and natural gas reserves for these wells were included in the~~ December 31, ~~2008 reserve information presented in this Annual Report~~2010.

~~Beginning with March 2009, oil prices increased from levels below $40 per barrel to between $60 and $70 per barrel by the third quarter of 2009.~~ As ~~a result~~ of ~~this~~December ~~increase in prices~~31, ~~in October 2009~~2011, ~~Reef~~three ~~approved the conversion~~ of ~~one of~~ the ~~eight wells on the~~ Sand Dunes ~~development~~wells ~~prospect~~were ~~located~~ shut-in ~~Eddy County, New Mexico to a salt water disposal well~~. Repair ~~The~~and ~~conversion~~maintenance work ~~on the well began in March 2010 and~~ was ~~completed~~performed ~~during~~on ~~April 2010. Upon~~two ~~completion~~ of the ~~disposal~~shut-in ~~facilities~~wells, ~~the~~and ~~new~~they ~~disposal~~have ~~well~~been ~~became~~returned ~~operational~~to production during ~~August 2010. Based on~~ the ~~disposal~~first ~~capacity~~quarter of ~~the~~2012. To ~~converted well~~date, ~~all~~performance of the ~~remaining seven~~ Sand Dunes wells ~~have~~has ~~been~~fallen ~~placed~~short ~~into production as~~ of ~~December 31~~Reef’s expectations, ~~2010.~~due ~~The~~to ~~cost~~lower ofproduction ~~the~~volumes ~~well~~and ~~conversion~~higher torepair ~~this~~and ~~Partnership~~maintenance ascosts ofthan ~~December 31,~~were ~~2010~~originally ~~was approximately $191,152~~anticipated. Reef ~~This~~does ~~cost~~not ~~was~~believe ~~paid~~the ~~for~~Sand byDunes ~~the~~wells ~~Partnership~~will byachieve ~~retaining~~the alevel ~~portion~~ of ~~the~~production ~~funds~~originally ~~normally~~forecast ~~paid~~when ~~out~~considering inthe ~~distributions~~conversion toof the ~~partners~~salt water disposal well. At ~~There~~December ~~are~~31, 22011,~~350~~ there were 300 BBL of crude oil and ~~2,650~~550 Mcf of natural gas reserves net to the Partnership’s interest for the ~~wells placed on full time production during 2010. As a result, the~~ Sand Dunes wells ~~have been classified as successful as of December 31, 2010~~.

The Partnership also has interests in unproved property consisting of un-drilled leasehold interest (11 potential drilling locations) in the Sand Dunes prospect. The Partnership fully impaired this unproved property during the fourth quarter of 2008 and has no plans to conduct any drilling operations on this acreage.

The Partnership has purchased working interests in seven exploratory prospects, upon which a total of seven exploratory wells and one developmental well were drilled. The Partnership drilled one successful exploratory well, one successful developmental well, and six unsuccessful exploratory wells on seven exploratory prospects located in St. Mary, Iberville, Cameron Parish, Louisiana, and San Patricio, Lavaca (two prospects), and Galveston County, Texas. The successful exploratory well in San Patricio, Texas ceased production in 2007.

~~Eighteen~~On ofAugust 24, 2011, the ~~twenty~~Partnership ~~successful~~completed ~~wells~~the sale of certain assets in ~~which~~accordance with a Purchase and Sale Agreement among the Partnership, ~~participated~~Reef ~~drilling~~Exploration, ~~are~~L.P., ~~currently~~Reef ~~producing~~Global Energy VIII, ~~one~~L.P., ~~has~~and ~~been~~Reef ~~converted~~Global ~~into~~Energy aIX, ~~salt~~L.P., ~~water~~affiliates ~~disposal~~of ~~well~~the Partnership, as sellers, and ~~one~~with ~~ceased~~Energen ~~production~~as ~~during~~buyer. This ~~2007~~agreement includes the Cole Ranch Properties for an aggregate purchase price to the sellers of $10,000,000, subject to certain purchase price adjustments. The Partnership received approximately $4,438,400 of the purchase price, prior to purchase price adjustments. The Cole Ranch Properties were assigned directly to Energen at closing pursuant to an Assignment, Conveyance and Bill of Sale whereby Energen received all economic interests in the Cole Ranch Properties as if those properties had been transferred to Energen on July 1, 2011. Prior to the sale, RELP had served as the operator of the eight successful developmental wells located on the Cole Ranch Properties. Net proceeds received by the Partnership related to this sale were distributed to the partners in 2011.

Ten of the twenty successful wells in which the Partnership participated drilling are currently producing, the Partnership’s interests in eight of the successful wells were sold during 2011 (the Cole Ranch Properties), one was converted into a salt water disposal well during 2010, and one ceased production during 2007.

Proved 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 unweighted 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~~2011, ~~and~~ 2010 ~~is presented consistent with the requirements of the new rule. The new rule does not allow prior-year reserve information to be restated~~, soand ~~all information related to periods prior to December 31,~~ 2009 is presented consistent with ~~prior SEC rules for~~ the ~~estimation~~requirements 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~~rule. All of the Partnership’s reserves are located in the United States.

11The estimated net proved crude oil and natural gas reserves at December 31, 2011, 2010, and 2009 are summarized below. The estimated quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs

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The estimated net proved crude oil and natural gas reserves at December 31, 2010, 2009, and 2008 are summarized below. The estimated quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

	Oil (BBL)	Gas (MCF)
Net proved reserves as of December 31, 2008	33,393	402,122
Net proved reserves as of December 31, 2009	41,710	188,020
Net proved reserves as of December 31, 2010	47,700	231,180
Net proved reserves as of December 31, 2011	6,640	90,700

The standardized measure of discounted future net cash flows as of December 31, 2011, 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	$	2,297,832
Standardized measure of discounted future net cash flows as of December 31, 2009	$	1,323,360
Standardized measure of discounted future net cash flows as of December 31, 2010	$	2,097,800
Standardized measure of discounted future net cash flows as of December 31, 2011	$	655,210

During the years ended December 31, 2011 and 2010, ~~2009,~~the ~~and~~Partnership ~~2008~~recorded no property impairment costs of proved properties. During the year ended December 31, 2009, the Partnership recorded property impairment costs of proved properties totaling $~~0, $~~566,679, ~~and $4,118,218~~ as a result of the net capitalized costs of proved oil and gas properties exceeding the sum of estimated future net revenues from proved reserves, using the methodologies described above.

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

The Partnership used an independent petroleum consulting company, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2011, 2010, and 2009 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2011, 2010, and 2009. 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, Gleason Engineering, of Arlington, Texas, to prepare its December 31, 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 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. Bucky Pauling, Geological Engineering Analyst for RELP, is the technical person at RELP primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Pauling has over five years of industry experience in oil and gas operations and is an active member of the Petroleum Engineers Club of Dallas. Any significant reserve changes are approved by Mr. Daniel C. Sibley, Chief Executive Officer and General Counsel of RELP, and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

1214

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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

The Partnership’s interests in producing and non-producing acreage are in the form of assigned direct interests in leases held by the Partnership or by Reef on behalf of the Partnership. Such properties are subject to customary royalty interests and could be subject to liens incident to operating agreements, liens for current taxes and overriding royalty interests and other burdens. The Partnership believes that none of these burdens will materially interfere with the use of such properties in the operation of the Partnership’s business and that it has or will obtain satisfactory title to all of its leases. Title will be held by the Partnership or by Reef on behalf of the Partnership.

ITEM 3. LEGAL PROCEEDINGS

On August 26, 2010, Frank Stevenson (“Stevenson”) filed a lawsuit, styled Stevenson v. Wayne Kirk, Michael J. Mauceli, Reef Global Energy Ventures II, et al., Cause No. 10-10647, in the 191st Judicial District Court, Dallas County, Texas. The suit also names as defendants Reef Global Energy VII, L.P. and multiple other Reef-sponsored ventures and limited partnerships, as well as Reef Securities, Inc., among others (collectively, “Defendants”). On September 22, 2010, James and Carol Estle (the “Estles”) and Nancy Dykes Thurmond Antolic (“Antolic”) joined the suit as additional plaintiffs. On January 27, 2011, Donna Stevenson (Frank Stevenson’s spouse) and ~~Jaimie~~Jaime Davis (“Davis”) joined the suit as additional plaintiffs (Stevenson, Estles, Antolic, and Davis are collectively referred to as “Plaintiffs”). With respect to Davis’s claims, specifically, Reef Securities, Inc. did not offer or sell the interests in the Reef program that Davis purchased. Rather, she purchased her interests through an unaffiliated broker/dealer. In the ~~First~~Sixth Amended Petition, ~~plaintiffs~~Plaintiffs ~~alleged~~assert ~~that,~~claims ~~collectively, they were seeking in excess~~ of $1misrepresentations ~~million~~and inomissions ~~compensatory~~under ~~damages~~the asTexas ~~well~~Securities asAct ~~exemplary damages~~(“TSA”), ~~attorneys’~~control ~~fees,~~person ~~pre-~~ and ~~post-judgment~~aider ~~interest,~~ and ~~costs. In~~abettor ~~the~~liability ~~Second~~under ~~Amended~~the ~~Petition~~TSA, ~~plaintiffs seek an undisclosed~~fraud, ~~unspecified~~breach ~~amount~~ of ~~damages.~~fiduciary ~~Plaintiffs~~duty, ~~assert~~breach ~~claims~~ of ~~fraud~~contract, ~~rescission~~civil ~~under the Texas Securities Act~~theft, ~~control~~negligent ~~person liability under the Texas Securities Act~~misrepresentation, and ~~breach~~fraudulent ~~of fiduciary duty~~concealment. Plaintiff Davis asserts against defendant Reef Oil & Gas Income and Development Fund, L.P. a claim for tortious interference with an existing contract. Defendants believe ~~plaintiffs~~Plaintiffs’ claims are meritless, ~~and with respect to many of the Reef programs named in the petition~~because, ~~defendants~~among ~~believe~~other ~~that the claims for fraud are barred by limitations~~things, asin ~~are~~connection ~~any claims for rescission or breach of fiduciary duty~~ with ~~respect~~each ~~to those programs. In addition, with respect to all~~ Reef ~~programs~~program in which ~~plaintiffs~~Plaintiffs participated, each ~~plaintiff~~Plaintiff received offering documents that thoroughly disclosed all material facts and risks associated with participation in such programs, particularly the fact that no guarantees or promises could be made or relied upon. Plaintiffs also claim that Defendants misallocated costs, expenses and deductions among unidentified Reef-sponsored ventures and limited partnerships. Plaintiffs seek approximately $2.2 million as actual damages, $620,000 as exemplary damages, as well as attorneys’ fees, pre- and post-judgment interest, and costs. Defendants (including Reef Global Energy VII, L.P.) intend to vigorously defend the lawsuit and may seek damages from plaintiffs based upon, among other things, breaches of representations and warranties made by them as well as the indemnification provisions of the documents executed by each of them. Defendants have filed Motions for Partial Summary Judgment seeking the dismissal of certain of Plaintiffs Stevenson, Estles, and Antolic’s claims, and the parties are currently awaiting the Court’s entry of an order on said Motions. However, following Defendants’ filing of their Motions for Summary Judgment, by filing their Sixth Amended Petition, Plaintiffs dismissed their claims for rescission under the TSA for failure of Defendants to register under the TSA, control person liability under the TSA in connections with such registration claims, and a majority of Plaintiffs’ fraud claims under the TSA. As of this time, nodiscovery ~~substantive~~is ~~discovery~~ongoing, and trial has been ~~conducted~~set for December 10, ~~and~~2012. The noPartnership ~~trial~~is ~~date~~reimbursing to Reef its share of the costs of defending this lawsuit as incurred, and has ~~been~~reimbursed ~~set~~$11,124 and $8,621, respectively, during the years ended December 31, 2011 and 2010.

ITEM 4. ~~(Removed~~MINE ~~and~~SAFETY ~~Reserved)~~DISCLOSURES

13Not applicable.

~~Table~~PART ~~of Contents~~II

PART II

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

As of December 31, ~~2010~~2011, the Partnership had one managing general partner, and 883 non-Reef investor partners (“investor partners”). ~~Pursuant to the Partnership Agreement of the Partnership, all general partner units held by investor partners were converted into limited partner units during the 3rd quarter of 2008.~~ Reef holds a total of 48.620 general partner units and the investor partners hold 923.784 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. The Partnership has made cash distributions to the partners of interest income and crude oil and natural gas sales revenues, less operating, general and administrative, and other costs since August 2006. Cash distributions are distributed 15.45% to the managing general partner (based upon the 11% interest not represented by units and the 4.45% interest represented by Partnership units) and 84.55% to investor partners.

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.

The Partnership has adopted a unit repurchase program. Under the terms of the program, the managing general partner is obligated to purchase up to 5% of the units in the Partnership per year during the period set forth in the Partnership Agreement, unless changes in oil and gas pricing meet certain criteria specified in the prospectus supplement, dated November 15, 2005. However, the managing general partner’s obligation to purchase units is limited to $500,000 per year in the aggregate for all partnerships previously or subsequently organized by the managing general partner or its affiliates. The Partnership did not repurchase any units in ~~2010~~2011.

Use of Proceeds

In connection with the Registration Statement filed on form S-1 (No. 333-122935) and declared effective July 7, 2005, Reef filed a final prospectus for the Program on July 8, 2005. On November 15, 2005, Reef filed a prospectus supplement describing the Partnership and commenced the offering of units in the Partnership. All sales of Partnership units were made through the Program’s dealer-manager, Reef Securities, Inc., and a number of soliciting dealers. The offering terminated April 28, 2006. Under the terms of the offering, a minimum of 40 Partnership units at a price of $25,000 per unit were required to be sold in order to form the Partnership. Upon meeting this requirement, the Partnership was formed on December 29, 2005.

The Partnership registered a total of 240 units of limited partner interests and 960 units of general partner interests. The aggregate offering amount registered was $30,000,000. During the offering period that terminated on April 28, 2006, the Partnership sold 923.784 units to investor partners, consisting of 182.783 units of limited partner interest and 741.001 units of additional general partner interest. Reef purchased 48.620 general partner units, equaling 5.00% of the total Partnership units sold. The Partnership did not sell the remaining registered units. Total offering proceeds were $24,127,769. Reef also contributes 1% of all leasehold, drilling, and completion costs as incurred. At December 31, 2010, Reef had contributed $202,585 in connection with this obligation.

All units except those purchased by Reef paid a 15% management fee to Reef to pay for the Partnership organization and offering costs, including sales commissions. These costs totaled $3,464,188, leaving capital contributions of $20,866,166 available for Partnership oil and gas operations. The Partnership expended $21,574,409 on the drilling of 29 wells and $137,512 on general and administrative expenses incurred during the initial drilling phase of operations. Expenditures in excess of available capital contributions were deducted from Partnership distributions.

ITEM 6. SELECTED FINANCIAL DATA

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

	As of and For the Years Ended December 31,
	2011		2010			2009			2008			2007

Revenue	$	1,158,549	$	1,521,877		$	1,417,297		$	2,861,452		$	1,517,970
Interest income	84		204			1,447			8,577			317,661
Costs and expenses	3,357,719		(1,153,515		)	(1,784,765		)	(6,839,025		)	(12,187,144		)
Net income (loss)	4,516,352		368,566			(366,021		)	(3,968,996		)	(10,351,513		)

Allocation of net income (loss):
Managing general partner units	758,789		105,269			29,970			(80,234		)	(476,894		)
General partner units	––		––			––			243,801			(7,920,794		)
Limited partner units	3,757,563		263,297			(395,991		)	(4,132,563		)	(1,953,825		)
Net income (loss) per managing general partner unit	15,606.52		2,165.13			616.41			(1,650.23		)	(9,808.55		)
Net income (loss) per general partner unit	––		––			––			329.01			(10,689.32		)
Net income (loss) per limited partner unit	4,067.58		285.02			(428.66		)	(4,209.61		)	(10,689.32		)

Total assets	755,741		1,438,351			1,704,660			2,745,502			8,620,722
Distributions to managing general partner	779,657		91,741			7,961			270,190			238,316
Distributions to investor partners	4,266,669		502,052			43,823			1,478,610			1,304,184
Distributions per general partner unit	––		––			––			703.38			1,411.78
Distributions per limited partner unit	4,618.69		543.47			47.44			1,600.61			1,411.78
Distributions per managing general partner unit	16,035.73		1,886.89			163.73			5,557.18			4,901.60

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	As of and For the Years Ended December 31,
	2010			2009			2008			2007			2006
	2011			2010			2009			2008			2007
Revenue	$	1,521,877		$	1,417,297		$	2,861,452		$	1,517,970		$	—
Interest income	204			1,447			8,577			317,661			691,667
Costs and expenses	(1,153,515		)	(1,784,765		)	(6,839,025		)	(12,187,144		)	(1,894,563		)
Net income (loss)	368,566			(366,021		)	(3,968,996		)	(10,351,513		)	(1,202,896		)
Allocation of net income (loss):
Managing general partner	105,269			29,970			(80,234		)	(476,894		)	(12,240		)
General partner units	—			—			243,801			(7,920,794		)	(956,084		)
Limited partner units	263,297			(395,991		)	(4,132,563		)	(1,953,825		)	(234,572		)
Net income (loss) per managing general partner unit	2,165.13			616.41			(1,650.23		)	(9,808.55		)	(251.74		)
Net income (loss) per general partner unit	—			—			329.01			(10,689.32		)	(1,290.26		)
Net income (loss) per limited partner unit	285.02			(428.66		)	(4,209.61		)	(10,689.32		)	(1,283.33		)
Total assets	1,438,351			1,704,660			2,745,502			8,620,722			21,786,620
Distributions to managing general partner	91,741			7,961			270,190			238,316			45,578
Distributions to investor partners	502,052			43,823			1,478,610			1,304,184			249,422
Distributions per general partner unit	—			—			703.38			1,411.78			270.00
Distributions per limited partner unit	543.47			47.44			1,600.61			1,411.78			270.00
Distributions per managing general partner unit	1,886.89			163.73			5,557.18			4,901.60			937.43
Operating Data
Annual sales volume:
Gas (MCF)	9650,~~722~~796			~~140~~96,~~623~~722			~~131~~140,~~512~~623			48131,~~301~~512			—48,301
Oil (BBL)	1410,~~268~~056			1514,~~201~~268			1615,~~045~~201			1416,~~032~~045			—14,032
Average sales price:
Gas (per MCF)	$	54.0275		$	45.2002		$	94.6620		$	89.5966		$	—8.59
Oil (per BBL)	$	7291.6319		$	5472.4263		$	9954.1542		$	7899.6015		$	—78.60

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.

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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 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 unweighted 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, 2011 and 2010, ~~2009~~the ~~and~~Partnership ~~2008~~recognized no property impairment expense of proved properties. During the year ended December 31, 2009, the Partnership recognized property impairment expense of proved properties totaling $~~0, $~~566,679. During the year ended December 31, ~~and~~2011, the Partnership recognized gain of $4,~~118~~254,~~218~~098 related to the Partnership’s sale and disposition of all rights, ~~respectively~~title, and interest in the Cole Ranch Properties.

Unproved properties consist of undeveloped leasehold interest. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the year ended December 31, 2008, the Partnership fully impaired its unproved properties by recognizing $172,447 of property impairment expense.17

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 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 $540,316, $606,787, and $1,346,930, 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.

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~~The~~Unproved ~~following~~properties ~~table~~consist ~~summarizes~~of undeveloped leasehold interest in the ~~Partnership’s~~Sand ~~asset~~Dunes ~~retirement~~prospect ~~obligation~~that ~~for~~has ~~the~~been ~~years~~fully ~~ended~~impaired ~~December 31,~~in ~~2010~~prior years, and ~~2009~~upon which no further drilling activity is planned.

	2010		2009
Beginning asset retirement obligation	$	289,494	$	270,772
Additions related to well conversion	6,162		—
Accretion expense	16,448		18,722
Ending asset retirement obligation	$	312,104	$	289,494

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, 2011, 2010, and 2009, 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 following table summarizes the Partnership’s asset retirement obligation for the years ended December 31, 2011 and 2010.

	2011			2010
Beginning asset retirement obligation	$	312,104		$	289,494
Additions related to well conversion	—			6,162
Accretion expense	12,182			16,448
Retirement related to sale of proved properties	(205,026		)	—
Ending asset retirement obligation	$	119,260		$	312,104

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~~2011, ~~2009~~2010 and ~~2008~~2009, the Partnership had no material gas imbalance positions.

Recently Adopted Accounting Pronouncements

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 Global Energy VII, L.P. is a Nevada limited partnership formed to acquire, explore, develop, and produce crude oil, natural gas, and natural gas liquids for the benefit of its investor partners. The Partnership’s primary purposes are to generate revenues from the production of crude oil and natural gas, distribute cash flow to investors, and provide tax benefits to investors. The majority of the Partnership’s proceeds have been used to purchase prospects and drill oil and gas wells upon those prospects.

The Partnership raised capital from the sale of Partnership units to investor partners and Reef, and uses those funds for the purchase of working interests in prospects and for drilling and completion operations and administrative costs during its drilling phase of operations. The Partnership did not borrow funds during the drilling phase of operations, and interest income and crude oil and natural gas revenues from successful wells, net of expenses, are being distributed on at least a quarterly basis to the partners. The Partnership is allowed to borrow funds in accordance with the Partnership Agreement, or utilize cash flows from successful wells in order to conduct further development upon prospects initially purchased by and drilled on by the Partnership during the drilling phase of operations. The Partnership completed its drilling phase of operations during the first quarter of 2008. The ~~Partnership currently has no plans to drill additional wells on any Partnership prospect, or to acquire additional prospects.~~

The Partnership does not operate in any other industry segment. The Partnership expended approximately $1,977,000 for the purchase of working interests in six developmental prospects, and expended approximately18

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~~$701,000 for the purchase of working interests in seven exploratory prospects. The~~ Partnership currently has ~~seven~~no ~~prospects~~plans into ~~Texas,~~drill ~~four~~additional ~~in Louisiana, one in Wyoming, and one in New Mexico, all of which are located onshore. The Partnership participated in drilling twenty-two developmental and seven exploratory~~ wells on ~~these~~any ~~prospects during 2006 to 2008. The~~ Partnership ~~participated in drilling nineteen successful developmental wells and three unsuccessful developmental wells. Eighteen of these wells are currently producing~~prospect, ~~and~~or ~~one has been converted~~ to aacquire ~~salt~~additional ~~water disposal well~~prospects. ~~The Partnership participated in drilling one successful exploratory well and six unsuccessful exploratory wells. The successful exploratory well has ceased production.~~

The Partnership does not operate in any other industry segment. During the drilling and completion phase of operations, the Partnership expended approximately $1,977,000 for the purchase of working interests in six developmental prospects, and expended approximately $701,000 for the purchase of working interests in seven exploratory prospects. The Partnership has seven prospects in Texas, four in Louisiana, one in Wyoming, and one in New Mexico, all of which are located onshore. The Partnership participated in drilling twenty-two developmental and seven exploratory wells on these prospects during 2006 to 2008. The Partnership participated in drilling nineteen successful developmental wells and three unsuccessful developmental wells. Ten of these wells are currently producing, the Partnership’s interests in eight of the successful wells were sold during 2011, and one was converted into a salt water disposal well during 2010. The Partnership participated in drilling one successful exploratory well and six unsuccessful exploratory wells. The successful exploratory well has ceased production.

Should the Partnership elect to borrow monies for additional development activity on its prospects, it will be subject to the interest rate risk inherent in borrowing activities. The Partnership has no current plans for additional drilling. The Partnership is permitted but is not expected to engage in commodity futures trading or hedging activities, and therefore is subject to commodity price risk. See “Item 7A. - Quantitative and Qualitative Disclosure About Market Risk.”

Liquidity and Capital Resources

The Partnership was funded with initial capital contributions totaling $24,127,769. Investor partners purchased 741.001 general partner units and 182.783 limited partner units for $23,094,590. Reef purchased 48.620 general partner units, or 5% of the total units sold, for $1,033,179. As of December 31, 2010, Reef has also contributed $202,585 in connection with its obligation to pay 1% of all leasehold, drilling, and completion costs. Organization and offering costs totaled $3,464,188, leaving capital contributions of $20,866,166 available for Partnership activities. The Partnership was formed on December 29, 2005, and the last partner was admitted to the Partnership on April 28, 2006.

The Partnership did not borrow additional funds in accordance with limitations set forth in the Partnership Agreement during the drilling phase of operations. The Partnership expended $21,574,409 on the drilling of 29 wells and $137,512 on general and administrative expenses during its initial drilling phase of operations. Expenditures in excess of available capital contributions were deducted from Partnership distributions.

Please see Item 1A of this Annual Report for a list of risk factors that could impact the Partnership. The Partnership distributes to investors on at least a quarterly basis the net cash flow from interest income and crude oil and natural gas sales revenues from successful wells, less operating, general and administrative, and other costs. These funds are not available for drilling activities.

The Partnership had working capital of $~~265~~202,~~840~~859 at December 31, ~~2010~~2011. Subsequent to expending the initial available Partnership capital contributions on prospect acquisitions and drilling and completion costs of partnership wells, the Partnership’s working capital consists primarily of cash flows from productive properties utilized to pay cash distributions to investors.

Results of Operations

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

During the year ended December 31, 2011, the Partnership earned net income of $4,516,352 compared to net income of $368,566 incurred during the year ended December 31, 2010. Gain on the sale of the Cole Ranch Properties was the primary cause of the increase in net income. Excluding this gain, net income for the year ended December 31, 2011 was $262,254 compared to $368,566 for the year ended December 31, 2010.

On August 24, 2011, the Partnership completed the sale of the Cole Ranch Properties to Energen, effective July 1, 2011. The Partnership recognized a gain related to this transaction of $4,254,098 during the year ended December

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31, 2011. Although the Partnership follows the full cost method of accounting, due to the significance of the sale and its effect on the rate of depletion and amortization the Partnership recognized a gain related to this transaction. In addition, revenues and lease operating expenses for these properties decreased during the last half of 2011 due to the sale.

Partnership oil and gas sales volumes are declining due to natural production declines from existing Partnership wells, the sale of the eight Cole Ranch wells during the third quarter of 2011, and the fact that the Partnership is not drilling and has no plans to conduct additional drilling activity. The HBR A Big Gas Unit (“HBR A”) well experienced a 78.9% decline in gas volumes with the Partnership’s share of gas volumes declining from approximately 43,202 Mcf during the year ended December 31, 2010 to approximately 9,107 Mcf during the year ended December 31, 2011. The Partnership’s share of sales volumes from the two most significant wells in which the Partnership has an interest, the Rob L RA SUA CL&F #1 (“Gumbo II”) well and the HBR A well, totaled 7,040 barrels of crude oil and 43,585 Mcf of natural gas, or 70.0% of sales volume of crude oil and 85.8% of sales volume of natural gas for the year ended December 31, 2011, respectively. During the year ended December 31, 2010, the Partnership’s share of sales volumes from these two wells totaled 8,445 barrels of crude oil and 81,754 Mcf of natural gas, or 59.2% and 84.5% of the Partnership’s total sales volumes, respectively. In addition, sales volumes from the eight Cole Ranch wells declined by almost 8,000 Mcf due to the sale of the Partnership’s interests in these wells on August 24, 2011. The eight Cole Ranch wells provided approximately 34.1% of the Partnership’s oil volumes and 20.5% of the Partnership’s gas volumes during the first half of 2011. Production from existing Partnership wells will continue to decline in future quarters, and combined with the loss of production from the Cole Ranch wells will lead to continuing declines in sales volumes in future periods. Beginning in November 2011, production volumes from the Gumbo II well began declining as a result of increasing water production from the well. The economic life of the Partnership is dependent upon the lives of the most significant wells in which it participates. The current estimated reserve lives of the Gumbo II and HBR A wells are estimated to be approximately 5.83 and 1.14 years, respectively, using current prices and costs.

Sales prices for crude oil rose by 25.6%, to an average price of $91.19 per Bbl for the year ended December 31, 2011, compared to an average price of $72.63 for the year ended December 31, 2010. Sales prices for natural gas declined by 5.4%, to an average price of $4.75 per Mcf for the year ended December 31, 2011, compared to an average price of $5.02 for the year ended December 31, 2010. As a result of the decreased sales volumes, the decreased sales price of natural gas, and the sale of the Cole Ranch wells, sales revenues decreased by approximately $363,328, or 23.9% on a comparative basis, despite the increase in average oil sales prices. The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

Lease operating expenses decreased from $269,854 during the year ended December 31, 2010 to $263,003 during the year ended December 31, 2011. Decreased expenses related to the sale of the Partnership’s interest in the eight Cole Ranch wells were offset by increased marketing and gathering and legal expenses on the Gumbo II well. In addition, operating costs also increased as a result of returning seven Sand Dunes wells to production during the third and fourth quarters of 2010, following conversion of one of the Sand Dunes wells to a salt water disposal well that began disposal operations in August 2010. Several of the Sand Dunes wells required rod and tubing repairs during 2011, leading to increased workover expenses.

Production taxes increased during the year ended December 31, 2011 compared to the year ended December 31, 2010 due to a one time severance tax adjustment received from the operator of the Gumbo II well. During the second quarter of 2010, the Partnership received a large severance tax credit from the operator of the Gumbo II well, because the well obtained a severance tax exemption from the State of Louisiana for the period from inception through February 2010. This one-time tax adjustment resulted in the Partnership showing a negative amount for severance taxes during the second quarter of 2010, and skewed the production tax expense shown for the year ended December 31, 2010.

The Partnership incurred $313,136 of depletion, depreciation, and amortization expense during the year ended December 31, 2011 compared to $540,316 of depletion, depreciation, and amortization expense during the year

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ended December 31, 2010. This decrease is due to the reduced depletable basis of the Partnership and the combination of declining production and rising oil prices between the comparative periods, which have led to a reduced depletion rate applied to the remaining basis.

General and administrative costs decreased from $281,486 incurred during the year ended December 31, 2010 to $220,156 incurred during the year ended December 31, 2011, primarily due to decreased overhead charges from RELP. The allocation of RELP’s overhead to partnerships is the largest factor in general and administrative expenses, and is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. Primarily as a result of the sale of the Cole Ranch Properties, the Partnership’s percentage of activity compared to that of other partnerships is declining. The administrative overhead charge to the Partnership decreased from $169,724 for the year ended December 31, 2010 to $100,439 for the year ended December 31, 2011.

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

During the year ended December 31, 2010, the Partnership earned net income of $368,566 compared to a net loss of $366,021 incurred during the year ended December 31, 2009. The change in operating results is due to two primary factors. First, the Partnership saw significant increases in the 2010 average sales prices for its crude oil and natural gas compared to 2009, as discussed in more detail below. Second, the partnership had impairment of proved properties of $566,679 in during the year ended December 31, 2009, compared to no impairment of proved properties during the year ended December 31, 2010.

Due mainly to rising commodity prices during the year, no impairment of properties was necessary during 2010. The Partnership’s year-end reserve report utilizes the unweighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and current costs to compute estimated discounted future net cash flows from successful wells. The base year end prices used in the Partnership’s reserve studies were $79.79 per barrel of crude oil and $4.93 per MCF of natural gas at December 31, 2010, compared to $61.08 per barrel of crude oil and $3.83 per MCF of natural gas at December 31, 2009. The 2010 year-end prices directly affect the estimated economic lives and, therefore, estimated reserves recoverable from Partnership wells. At December 31, 2010, the estimated discounted future net cash flows of the Partnership totaled $2,097,800 compared to $1,323,360 at December 31, 2009.

18Overall, sales volumes decreased during the year ended December 31, 2010 compared to the year ended December 31, 2009. The Partnership has interests in two significant wells, the Gumbo II well and the HBR A well. During the year ended December 31, 2010, the HBR A and Gumbo II wells accounted for 59.2% and 84.5% of the Partnership’s crude oil and natural gas sales volumes, respectively. During the year ended December 31, 2009, the HBR A and the Gumbo II accounted for 56.9% and 88.5% of the Partnership’s crude oil and natural gas sales volumes, respectively. The operator of the Gumbo II well slowly increased production volumes from the well during 2010, resulting in increased volumes from this well during the year ended December 31, 2010. However, production volumes from the HBR A well have declined significantly during the past year. Production volumes from the HBR A well, net to the Partnership, were 1,257 Bbl and 43,202 MCF during the year ended December 31, 2010 compared to 3,214 Bbl and 95,885 MCF during the year ended December 31, 2009.

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economic lives and, therefore, estimated reserves recoverable from Partnership wells. At December 31, 2010, the estimated discounted future net cash flows of the Partnership totaled $2,097,800 compared to $1,323,360 at December 31, 2009.

Overall, sales volumes decreased during the year ended December 31, 2010 compared to the year ended December 31, 2009. The Partnership has interests in two significant wells, the Rob L RA SUA CL&F #1 (“Gumbo II”) well and the HBR A Big Gas Unit (“HBR A”) well. During the year ended December 31, 2010, the HBR A and Gumbo II wells accounted for 59.2% and 84.5% of the Partnership’s crude oil and natural gas sales volumes, respectively. During the year ended December 31, 2009, the HBR A and the Gumbo II accounted for 56.9% and 88.5% of the Partnership’s crude oil and natural gas sales volumes, respectively. The operator of the Gumbo II well slowly increased production volumes from the well during 2010, resulting in increased volumes from this well during the year ended December 31, 2010. However, production volumes from the HBR A well have declined significantly during the past year. Production volumes from the HBR A well, net to the Partnership, were 1,257 Bbl and 43,202 MCF during the year ended December 31, 2010 compared to 3,214 Bbl and 95,885 MCF during the year ended December 31, 2009.

While overall sales volumes decreased during the year ended December 31, 2010, sales prices received for the Partnership’s production increased. The average oil price received on a comparative basis increased from $54.42 per barrel of crude oil during the year ended December 31, 2009 to $72.63 per barrel during the year ended December 31, 2010, an increase of 33.5%. Natural gas prices also increased from an average price of $4.20 per Mcf of natural gas produced during the year ended December 31, 2009 to $5.02 per Mcf for the year ended December 31, 2010, an increase of 19.5%. Because of these large increases in average prices for crude oil and natural gas sales, the Partnership’s oil and gas sales revenues rose by $104,580, or 7.4% for the year ended December 31, 2010.

Lease operating expenses increased from $231,022 during the year ended December 31, 2009 to $269,854 during the year ended December 31, 2009, primarily due to timing of accruals related to the Cole Ranch wells. Production taxes decreased during the year ended December 31, 2010 compared to the year ended December 31, 2009 by $32,877, from $78,288 to $45,411. This was the result of an adjustment received from the operator of the Gumbo II well during the second quarter of 2010. The operator refunded prior production tax payments because the well ~~obtained a severance tax exemption from the state of Louisiana for the period from inception through February 2010.~~

General and administrative costs decreased from $283,267 incurred during the year ended December 31, 2009 to $281,486 incurred during the year ended December 31, 2010, primarily due to decreased overhead and direct technical charges from RELP. Since the beginning of the second quarter of 2009, RELP has gradually reduced its total overhead costs by approximately 25%, and as such, the total overhead charged to partnerships has decreased in 2010 from 2009 levels. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. Overall activity of this Partnership has begun to increase since the Sand Dunes wells began to be placed back on line during the third quarter of 2010, and accordingly, overhead charged by RELP increased during the fourth quarter of 2010 compared to the second quarter. Despite this increase due to Sand Dunes, total overhead declined overall in 2010 from 2009 levels. The administrative overhead charge to the Partnership decreased from $171,874 for the year ended December 31, 2009 to $169,724 for the year ended December 31, 2010. This decrease was partially offset by increased legal fees.21

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

During 2009, the Partnership incurred a net loss of $366,021 compared to a net loss of $3,968,996 incurred during 2008. The change in operating results is due to three primary factors. First, the Partnership saw significant decreases in the 2009 average sales prices for its crude oil of 45.1% and natural gas of 56.5% compared to 2008. The decreased prices caused overall sales revenues to fall from $2,861,452 in 2008 to $1,417,297 in 2009, a decrease of 50.5%. Second, the Partnership had impairment of proved properties of $566,679 in 2009, compared to impairment of proved properties of $4,118,218 and impairment of unproved properties of $172,447 in 2008. The Partnership also saw depreciation, depletion, and amortization fall from $1,346,930 in 2008 to $606,787 in 2009, as a result of the reduced property basis for 2009 which resulted from the large 2008 impairments.

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~~The~~obtained ~~Partnership’s~~a ~~year-end~~severance ~~reserve~~tax ~~report~~exemption ~~utilizes the unweighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and current costs to compute estimated discounted future net cash flows~~ from ~~successful wells. The base year end prices used in~~ the ~~Partnership’s~~state ~~reserve studies were $61.08 per barrel~~ of ~~crude~~Louisiana oil and $3.83 per MCF of natural gas at December 31, 2009, compared to $44.60 per barrel of crude oil and $5.71 per MCF of natural gas at December 31, 2008. The 2009 year-end prices directly affect the estimated economic lives and, therefore, estimated reserves recoverable from Partnership wells. At December 31, 2009, the estimated discounted future net cash flows of the Partnership totaled $1,323,360 compared to $2,297,832 at December 31, 2008. The Partnership recorded property impairment expense of proved properties totaling $566,482 during the first quarter of 2009, as a result of significant declines in commodity prices during the first part of 2009. In addition, the Partnership took another impairment of proved properties of $197 during the fourth quarter of 2009 due to changes in performance on one Partnership well. Production rates declined on this well at a rate greater than previously forecast. The resulting reduction of proved reserves and corresponding decrease in estimated future cash flows caused a reduction of approximately $675,000 in estimated discounted future net cash flows for the ~~Partnership~~period from ~~this~~inception ~~well~~through ~~during the fourth quarter~~February 2010.

~~Lease~~General ~~operating~~and ~~expenses~~administrative costs decreased from $~~503~~283,~~416~~267 incurred during the year ended December 31, ~~2008~~2009 to $~~231~~281,~~022~~486 incurred during the year ended December 31, ~~2009~~2010, primarily due to decreased overhead and direct technical charges from RELP. Since the ~~Sand~~beginning ~~Dunes~~of ~~prospect~~the second quarter of 2009, ~~which~~RELP ~~incurred~~has ~~higher~~gradually ~~operating~~reduced its total overhead costs ~~during~~by ~~2008~~approximately ~~due~~25%, toand as such, the ~~costs~~total overhead charged to partnerships has decreased in 2010 from 2009 levels. The allocation of ~~electricity,~~RELP’s ~~salt~~overhead ~~water~~to ~~disposal~~partnerships is based upon several factors, ~~equipment~~including ~~rental~~the level of drilling activity, revenues, and ~~sub-surface~~capital ~~repairs~~ and ~~maintenance~~operating ~~during~~expenditures of each partnership compared to the ~~testing~~total levels of all partnerships. Overall activity of this Partnership has begun to increase since the Sand Dunes wells inbegan ~~2008. In~~to ~~addition,~~be ~~2008~~placed ~~production~~back ~~costs~~on ~~were~~line ~~impacted~~during by the ~~expensed~~third ~~workover~~quarter ~~costs~~of ~~incurred~~2010, toand ~~change~~accordingly, ~~bottom~~overhead ~~hole~~charged ~~pumps~~by onRELP ~~three~~increased ~~Partnership~~during ~~wells. As~~the afourth ~~result~~quarter of ~~shutting~~2010 incompared to the ~~eight~~second quarter. Despite this increase due to Sand Dunes, ~~wells~~total overhead declined overall in ~~February~~2010 from 2009, ~~lease~~levels. ~~operating~~The ~~costs~~administrative ~~declined~~overhead charge to the Partnership decreased from ~~comparable~~$171,874 ~~levels~~for ~~during~~the ~~2008~~year ended December 31, 2009 to $169,724 for the year ended December 31, 2010. This decrease was partially offset by increased legal fees.

Production expenses decreased during 2009 primarily due to decreases in sales prices. As a result of the decreased sales prices received during 2009 as compared to 2008, production taxes decreased by $97,411 during 2009.

General and administrative costs incurred during the years ended December 31, 2009 and 2008 decreased from $456,589 in 2008 to $283,267 in 2009, primarily due to decreased legal fees and decreased overhead charges. Effective April 1, 2008, Reef implemented a new method for allocating overhead that takes actual overhead and allocates it based on the summation of revenues, expenses and actual capital costs incurred. The administrative overhead charge to the Partnership decreased from $275,250 during the year ended December 31, 2008 to $171,874 during the year ended December 31, 2009.

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~~2011 and ~~2009~~2010, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.

Contractual Obligations Table

The Partnership has no obligations under non-cancelable agreements as of December 31, ~~2010~~2011.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk

The Partnership has not borrowed any funds to date. The Partnership Agreement allows borrowings from banks or other financial sources of up to 25% of the aggregate capital contributions to the Partnership without investor approval, provided the lender agrees it will have no recourse against individual investor partners, and allows borrowings in excess of 25% of the aggregate capital contributions to the Partnership with the consent of investor partners. Should the Partnership elect to borrow monies for additional drilling activity on Partnership properties, it will be subject to the interest rate risk inherent in borrowing activities. Changes in interest rates could significantly affect the Partnership’s results of operations and the amount of net cash flow available for partner distributions. Also, to the extent that changes in interest rates affect general economic conditions, the Partnership will be affected by such changes.

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affect the Partnership’s results of operations and the amount of net cash flow available for partner distributions. Also, to the extent that changes in interest rates affect general economic conditions, the Partnership will be affected by such changes.

Commodity Price Risk

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

Assuming the production levels we attained during the year ended December 31, ~~2010~~2011, a 10% change in the price received for our crude oil would have had an approximate $~~103~~91,~~600~~700 impact on our crude oil revenues, and a 10% change in the price received for our natural gas would have had an approximate $4823,~~600~~900 impact on our natural gas ~~revenues.~~

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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.~~DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this Annual Report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial and accounting officer of the Partnership’s managing general partner, Reef Oil & Gas Partners, L.P., evaluated the effectiveness of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this Annual Report. Based on that evaluation, the principal executive officer and principal financial and accounting officer of our managing general partner have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial and accounting 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~~2011.

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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~~2011 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

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

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

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

Name	Age	Positions and Offices Held
Michael J. Mauceli	5455	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	60	Chief Financial Officer and General Counsel of RELP
Daniel C. Sibley	59	Chief Financial Officer and General Counsel of RELP
David M. Tierney	59	Chief Financial Reporting Officer and Treasurer 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 employed by several exploration and development firms in planning exploration and marketing feasibility of privately sponsored drilling programs.

HDaniel C. ~~Walt~~Sibley ~~Dunagin~~became isChief ~~Executive~~Financial ~~Vice~~Officer ~~President~~of RELP in March 2010 and ~~Land~~General ~~Manager~~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 ~~has~~also ~~held~~served ~~this~~as ~~position~~Chief ~~since~~Financial ~~January~~Officer for RELP from January 2006 until his appointment to General Counsel of RELP, and ~~has~~had served in this same position with ~~its~~RELP’s predecessor entity, OREI, since ~~1990~~1998. HeMr. Sibley iswas ~~responsible~~employed ~~for~~as ~~all~~a ~~contracts~~Certified ~~with~~Public ~~other~~Accountant ~~industry~~with ~~partners~~Grant ~~and~~Thornton ~~all~~from ~~land~~1977 ~~activities~~to ~~required~~1980. ~~for~~From ~~exploration,~~1980 ~~development~~to ~~and production~~1994, ~~including~~he ~~lease~~was ~~acquisition,~~involved ~~title~~in ~~opinions,~~the ~~curative,~~private ~~permitting,~~practice ~~unitization, rights-~~of~~-way~~ ~~and~~law. ~~environmental~~He ~~issues.~~received a B.B.A. ~~graduate~~in ofaccounting from the University of ~~Mississippi~~North Texas in ~~1969~~1973, ~~with~~ a ~~B.B.A.~~law degree, ~~Walt’s~~(J.D.) ~~career~~from ~~has~~the ~~also~~University ~~involved~~of ~~land~~Texas ~~work~~in ~~for ExxonMobil~~1977, ~~ChevronTexaco,~~and ~~UNOCAL,~~a ~~Santa~~Master Feof ~~Energy~~Laws-Taxation ~~and~~degree ~~Oryx Energy~~ (~~now Kerr-McGee)~~Ll.M.) ~~Walt~~from isSouthern aMethodist ~~member~~University ofin ~~the~~1984. Mr. Sibley ~~Dallas~~became ~~Association~~a ofcertified ~~Petroleum~~public ~~Landmen~~accountant in 1977, ~~the~~but ~~Association~~no oflonger ~~International~~maintains ~~Petroleum~~that ~~Negotiators,~~license. He ~~and~~is ~~the~~an ~~American~~active ~~Association~~member of ~~Professional~~the ~~Landmen~~Texas Bar Association.

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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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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 was dismissed on November 18, 2011. Mr. Guevara and his affiliates released all claims against the Defendants.

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.

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ITEM 11. EXECUTIVE COMPENSATION

The following table summarizes the items of compensation to be received by Reef as the managing general partner from the Partnership.

Recipient	Form of Compensation	Amount
Managing General Partner	Partnership interest (excluding any partnership interest resulting from the purchase of units)	10% interest
Managing General Partner	Management fee	15% of subscriptions
Managing General Partner and its Affiliates	Direct and administrative costs	Reimbursement at cost
Affiliate of the Managing General Partner	Operator’s per-well charges	Competitive prices
Managing General Partner and its Affiliates	Payment for equipment, supplies, marketing, and other services	Cost or competitive prices

Reef’s “partnership interest,” as described in the table above, refers only to its interest as managing general partner and does not include the interest Reef has as the result of its purchase of units in the Partnership, or the 1% interest Reef has as the result of its payment of 1% of all leasehold, drilling, and completion costs. Reef purchased 5.00% of the outstanding Partnership units. Reef received a 10% interest as managing general partner of the Partnership and a 1% interest as a result of Reef’s payment of 1% of all leasehold, drilling, and completion costs for a total of an 11% interest. This 11% interest is not represented by partnership units. Reef has a total interest in the Partnership of 15.45%.

Reef is entitled to receive a management fee equal to 15% of the Partnership subscriptions exclusive of the units purchased by Reef. From this amount Reef pays all of the Partnership’s organization and offering costs, including sales commissions. The management fee is payable to Reef in two parts. Reef initially received an amount not to exceed 13.5% to cover actual sales commissions and actual organization and offering costs. The remainder of the management fee is paid to Reef from the net cash flow available for partner distributions, at a rate not to exceed $1 million per year. The total management fee owed Reef is $3,464,188. The Partnership recorded $3,414,188 of this amount as offering costs, and $50,000 as organization costs. Of this amount, $2,689,092 has been paid to Reef to cover actual sales commissions and organization and offering costs and $725,096 has been paid to Reef from net cash flows of the Partnership.25

~~Reef~~Table ~~is reimbursed for direct costs and all documented out-~~of~~-pocket~~ expenses incurred on behalf of the Partnership, including administrative costs. During the years ended December 31, 2010, 2009 and 2008, the Partnership reimbursed Reef $11,836, $1,207, and $58,114, respectively, for technical services costs which have been capitalized as project costs, and $179,146, $213,974, and $279,926, respectively, for administrative costs included as general and administrative expenses.Contents

~~Operator~~Reef ~~fees~~is ~~are~~entitled ~~payable~~to receive a management fee equal to ~~RELP~~15% ~~for~~of the ~~wells~~Partnership onsubscriptions exclusive of the ~~five~~units ~~prospects~~purchased ~~where~~by ~~RELP~~Reef. ~~serves~~From asthis ~~operator. RELP~~amount ~~receives~~Reef ~~operator~~pays ~~fees~~all ~~during~~of the ~~drilling~~Partnership’s organization and ~~production~~offering ~~phase~~costs, ofincluding ~~each~~sales ~~well~~commissions. atThe ~~the~~management ~~competitive~~fee ~~rate~~is inpayable ~~the~~to ~~geographical~~Reef ~~area~~in ~~where~~two ~~the~~parts. ~~well~~Reef isinitially ~~located. These~~received ~~fees~~an ~~are~~amount ~~charged~~not asto aexceed ~~monthly~~13.5% ~~fee~~to ~~per~~cover ~~well~~actual assales ~~agreed~~commissions toand inactual anorganization ~~operating~~and ~~agreement~~offering ~~signed~~costs. byThe ~~the~~remainder ~~Partnership~~of ~~and~~the ~~participating~~management ~~third~~fee ~~party~~is ~~working~~paid ~~interest~~to ~~owners~~Reef infrom the ~~well.~~net ~~During~~cash ~~the~~flow ~~years~~available ~~ended~~for ~~December~~partner 31distributions, ~~2010,~~at ~~2009~~a ~~and~~rate ~~2008,~~not ~~the~~to ~~Partnership~~exceed ~~paid~~$1 ~~operator~~million ~~fees~~per ~~totaling~~year. The total management fee owed Reef is $463,~~536~~464,188. The Partnership recorded $443,~~473~~414,188 of this amount as offering costs, and $4050,~~879~~000 toas ~~RELP~~organization costs. ~~RELP~~Of ~~serves~~the amount recorded as ~~operator~~offering ~~for~~costs, ~~five~~$2,689,092 ~~Partnership~~has ~~prospects~~been ~~upon~~paid ~~which~~to ~~seventeen~~Reef ~~successful~~to cover actual sales commissions and ~~two~~organization ~~unsuccessful~~and ~~wells~~offering ~~have~~costs and $725,096 has been ~~drilled~~paid to Reef from net cash flows of the Partnership.

Reef is reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership, including administrative costs. During the years ended December 31, 2011, 2010 and 2009, the Partnership reimbursed Reef $0, $11,836, and $1,207, respectively, for technical services costs which have been capitalized as project costs, and $116,958, $179,146, and $213,974, respectively, for administrative costs included as general and administrative expenses.

Operator fees are payable to RELP for the wells on the five prospects where RELP serves as operator. RELP receives operator fees during the drilling and production phase of each well at the competitive rate in the geographical area where the well is located. These fees are charged as a monthly fee per well as agreed to in an operating agreement signed by the Partnership and participating third party working interest owners in the well. During the years ended December 31, 2011, 2010 and 2009, the Partnership paid operator fees totaling $35,004, $46,536, and $44,473 to RELP. As of December 31, 2011, RELP serves as operator for four Partnership prospects upon which nine successful and two unsuccessful wells have been drilled.

Compensation Committee

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

24ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

~~Table~~RELATED ofSTOCKHOLDER ~~Contents~~MATTERS

~~ITEM~~The 12following table sets forth information as of December 31, 2011 concerning all persons known by Reef to own beneficially more than 5% of the interests in the Partnership. ~~SECURITY~~Unless ~~OWNERSHIP~~expressly OFindicated ~~CERTAIN~~otherwise, ~~BENEFICIAL~~each ~~OWNERS~~partner ~~AND~~exercises ~~MANAGEMENT~~sole ~~AND~~voting ~~RELATED~~and ~~STOCKHOLDER~~investment ~~MATTERS~~power with respect to the units beneficially owned.

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.

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)	48.620	5.00	%	4.45	%
Reef Oil & Gas Partners, L.P. (1)	—	—		11.00	%

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)	48.620	5.00	%	4.45	%
Reef Oil & Gas Partners, L.P. (1)	—	—		11.00	%

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

(The managing general partner received a 10% interest in the Partnership as compensation for forming the Partnership, and also holds a 1)% ~~Reef~~interest ~~Oil~~in &the ~~Gas~~Partnership ~~Partners~~as a result of paying 1% of all leasehold, Ldrilling and completion costs.~~P.’s~~ ~~address~~In isaddition ~~1901~~to N.this ~~Central~~11% ~~Expressway~~interest not represented by Partnership units, ~~Suite~~Reef ~~300~~purchased 5% of the 972.404 Partnership units and, ~~Richardson~~therefore, ~~Texas~~holds ~~75080~~5% of the 89% interest in the Partnership (4.45%) held by the unit holders.

The managing general partner received a 10% interest in the Partnership as compensation for forming the Partnership, and also holds a 1% interest in the Partnership as a result of paying 1% of all leasehold, drilling and completion costs. In addition to this 11% interest not represented by Partnership units, Reef purchased 5% of the 972.404 Partnership units and, therefore, holds 5% of the 89% interest in the Partnership (4.45%) held by the unit holders.26

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

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

	2010		2009
	2011		2010
Audit fees	$	5250,~~968~~616	$	4952,~~745~~968
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—

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

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

(a)	1. Financial Statements

	Report of Independent Registered Public Accounting Firm	F-2
	Balance Sheets	F-3
	Statements of Operations	F-4
	Statements of Partnership Equity	F-5
	Statements of Cash Flows	F-6
	Notes to Financial Statements	F-7

	2. Financial Statement Schedules	None

	3. Exhibits

Table of Contents

		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.

2627

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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 to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 31, 2011	REEF GLOBAL ENERGY VII, L.P.
Date: March 27, 2012	REEF GLOBAL ENERGY VII, 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)

Table of Contents

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)	March 31, 2011
	Manager and Member of Reef Oil & Gas Partners, GP, LLC, the
Michael J. Mauceli
/s/ Michael J. Mauceli	general partner of Reef Oil & Gas Partners, L.P., the Managing	March 27, 2012
/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of Reef Exploration, L.P. (Principal Financial and Accounting Officer)	March 31, 2011
Michael J. Mauceli	General Partner of the Partnership
Daniel C. Sibley
	(Principal Executive Officer)
/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of Reef Exploration, L.P.	March 27, 2012
Daniel C. Sibley	(Principal Financial and Accounting Officer)

Table of Contents

EXHIBIT INDEX

3.1(a)(i)		Certificate of Limited Partnership (incorporated by reference to Exhibit 3.1 to Form 8-A, SEC File No. 000-52540, as filed with the SEC on March 30, 2007).
3.1(a)(ii)		Certificate of Amendment to the Certificate of Limited Partnership of Reef Global Energy VII, L.P., dated August 27, 2008 (incorporated by reference to Exhibit 3.1(i)(a) to Form 8-K, SEC File No. 000-52540, as filed with the SEC on September 3, 2008).
3.1(a)(iii)		Certificate of Amendment to the Certificate of Limited Partnership of Reef Global Energy VII, L.P., dated August 28, 2008 (incorporated by reference to Exhibit 3.1(i)(b) to Form 8-K, SEC File No. 000-52540, as filed with the SEC on September 3, 2008).
3.2		Form of Limited Partnership Agreement (incorporated by reference to Appendix A to the prospectus filed as part of Post-Effective Amendment No. 2 to Registration Statement on Form S-1, SEC File No.333-122935, filed with the SEC on July 7, 2006).
10.1		Letter Agreement, dated November 7, 2001, by and between Reef Partners LLC and Challenger Minerals Inc. (incorporated by reference to Exhibit 10.2 of the Report on Form 10-K of Reef Global Energy Ventures as filed with the SEC on March 5, 2002).
10.2	*	Purchase and Sale Agreement, dated August 24, 2011, among Reef Global Energy VIII, L.P., Reef Exploration, L.P., Reef Global Energy VIII, L.P., Reef Global Energy IX, L.P., and Energen Resources Corporation.
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.
101*		The following materials from this report, formatted in XBRL (eXtensible Business Reporting Language): (i) Balance Sheets as of December 31, 2011 and 2010, (ii) the Statements of Operations for the years ended December 31, 2011, 2010, and 2009, (iii) the Statements of Changes in Stockholders’ Equity for the years ended December 31, 2011, 2010 and 2009, (iv) the Statements of Cash Flows for the years ended December 31, 2011, 2010, and 2009, and (v) Notes to Financial Statements.

* ~~Attached~~Filed herewith

Table of Contents

Reef Global Energy VII, L.P.

Financial Statements

Years Ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009

Contents

Report of Independent Registered Public Accounting Firm	F-12
Audited Financial Statements
Balance sheets	F-23
Statements of operations	F-34
Statements of partnership equity	F-45
Statements of cash flows	F-56
Notes to financial statements	F-67

30F-1

Table of Contents

Report of Independent Registered Public Accounting Firm

The Partners

Reef Global Energy VII, L.P.

We have audited the accompanying balance sheets of Reef Global Energy VII, L.P. as of December 31, ~~2010~~2011 and ~~2009~~2010, and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, ~~2010~~2011. 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. An audit includes 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 Global Energy VII, L.P. at December 31, ~~2010~~2011 and ~~2009~~2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2010~~2011, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 21 to the financial statements, ~~effective~~the ~~December~~Partnership has two significant producing properties that are expected to account for a majority of future revenues. These two properties have limited estimated economic reserve lives as of December 31, ~~2009~~2011. Future cash flows generated from Partnership wells will be significantly impacted by actual prices received subsequent to December 31, 2011 and by actual production volumes from the Partnership’s ~~changed~~most ~~its~~significant ~~reserve~~wells. These ~~estimates~~ and ~~related~~other ~~disclosures~~factors raise substantial doubt about the Partnership’s ability to continue as a ~~result~~going ofconcern. ~~adopting~~The ~~new~~financial ~~oil~~statements ~~and~~do ~~gas~~not ~~reserve~~include ~~estimation~~any ~~and~~adjustments ~~disclosure~~that ~~requirements~~might result from the outcome of this uncertainty.

/Ss/ BDO USA, LLP Dallas, Texas March 3127, ~~2011~~2012

F-12

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Reef Global Energy VII, L.P.

Balance Sheets

December 31,	~~2010~~2011		~~2009~~2010
Assets
Current assets:
Cash and cash equivalents	$	63124,~~713~~643	$	63,~~432~~713
Accounts receivable	—18		~~3,471~~—
Accounts receivable from affiliates	~~214~~130,~~208~~487		~~314~~214,~~397~~208
Total current assets	~~277~~255,~~921~~148		~~381~~277,~~300~~921
Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $20,819,321 and $20,279,005	1,160,430		1,323,360
Proved properties, net of accumulated depletion of $12,745,522 and $20,819,321	500,593		1,160,430
Net oil and gas properties	1500,~~160,430~~593		1,~~323~~160,~~360~~430
Total assets	$	1755,~~438,351~~741	$	1,~~704~~438,~~660~~351
Liabilities and partnership equity
Current liabilities:
Accounts payable	1252,~~081~~289		512,~~677~~081
Accounts payable to affiliates	—		70,096
Total current liabilities	52,289		12,081
Total current liabilities	12,081		75,773
Long-term liabilities:
Asset retirement obligation	~~312~~119,~~104~~260		~~289~~312,~~494~~104
Total long-term liabilities	~~312~~119,~~104~~260		~~289~~312,~~494~~104
Commitments and Contingencies (Note 5)
Partnership equity
Limited partners	~~966~~457,~~390~~284		1966,~~205,145~~390
Managing general partner	~~147~~126,~~776~~908		~~134~~147,~~248~~776
Partnership equity	1584,~~114,166~~192		1,~~339~~114,~~393~~166
Total liabilities and partnership equity	$	1755,~~438,351~~741	$	1,~~704~~438,~~660~~351

See accompanying notes to financial statements.

F-23

Table of Contents

Reef Global Energy VII, L.P.

Statements of Operations

	For the Years Ended December 31,
	2010			2009			2008
	2011			2010			2009
Revenues:	$	1,521,877		$	1,417,297		$	2,861,452
Oil, gas and NGL sales:	$	1,158,549		$	1,521,877		$	1,417,297
Costs and expenses:
Lease operating expenses	~~269~~263,~~854~~003			~~231~~269,~~022~~854			~~503~~231,~~416~~022
Production taxes	4587,~~411~~902			7845,~~288~~411			~~175~~78,~~699~~288
Depreciation, depletion and amortization	~~540~~313,~~316~~136			~~606~~540,~~787~~316			1606,~~346,930~~787
Property impairment	—			~~566,679~~—			4566,~~290,665~~679
Accretion of asset retirement obligation	1612,~~448~~182			1816,~~722~~448			6518,~~726~~722
General and administrative	~~281~~220,~~486~~156			~~283~~281,~~267~~486			~~456~~283,~~589~~267
Total costs and expenses	1,153,515			1,784,765			6,839,025
Gain on sale of oil and gas properties	(4,254,098		)	—			—
Net income (loss) from operations	368,362			(367,468		)	(3,977,573		)
Total costs and expenses	(3,357,719		)	1,153,515			1,784,765
Interest income	204			1,447			8,577
Income (loss) from operations	4,516,268			368,362			(367,468		)
Net income (loss)	$	368,566		$	(366,021	)	$	(3,968,996	)
Interest income	84			204			1,447
Net income per general partner unit	$	—		$	—		$	329.01
Net income (loss)	$	4,516,352		$	368,566		$	(366,021	)
Net income (loss) per limited partner unit	$	~~285~~4,067.0258		$	~~(428~~285.6602	)	$	(~~4,209~~428.6166	)
Net income (loss) per managing general partner unit	$	2,165.13		$	616.41		$	(1,650.23	)
Net income per managing general partner unit	$	15,606.52		$	2,165.13		$	616.41

See accompanying notes to financial statements.

F-34

Table of Contents

Reef Global Energy VII, 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	741.001		5,624,838			182.783	1,387,493			48.620	453,862			972.404	7,466,193
Partner contributions	—		—			—	—			—	5,361			—	5,361
Partner distributions	—		(521,202		)	—	(957,408		)	—	(270,190		)	—	(1,748,800		)
Net income (loss)	—		243,801			—	(4,132,563		)	—	(80,234		)	—	(3,968,996		)
Conversion of general partner units into limited partner units (Note 1)	(741.001	)	(5,347,437		)	741.001	5,347,437			—	—			—	—
Balance at December 31, 2008	—		$	—		923.784	$	1,644,959		48.620	$	108,799		972.404	$	1,753,758
Distribution amount per partnership unit			$	703.38			$	1,600.61			$	5,557.18
Balance at December 31, 2008	—		—			923.784	1,644,959			48.620	108,799			972.404	1,753,758
Partner contributions	—		—			—	—			—	3,440			—	3,440
Partner distributions	—		—			—	(43,823		)	—	(7,961		)	—	(51,784		)
Net income (loss)	—		—			—	(395,991		)	—	29,970			—	(366,021		)
Balance at December 31, 2009	—		$	—		923.784	$	1,205,145		48.620	$	134,248		972.404	$	1,339,393
Distribution amount per partnership unit			$	—			$	47.44			$	163.73
Balance at December 31, 2009	—		—			923.784	1,205,145			48.620	134,248			972.404	1,339,393
Partner distributions	—		—			—	(502,052		)	—	(91,741		)	—	(593,793		)
Net income	—		—			—	263,297			—	105,269			—	368,566
Balance at December 31, 2010	—		$	—		923.784	$	966,390		48.620	$	147,776		972.404	$	1,114,166
Distribution amount per partnership unit			$	—			$	543.47			$	1,886.89
Balance at December 31, 2010	—		—			923.784	966,390			48.620	147,776			972.404	1,114,166
Partner distributions	—		—			—	(4,266,669		)	—	(779,657		)	—	(5,046,326		)
Net income	—		—			—	3,757,563			—	758,789			—	4,516,352
Balance at December 31, 2011	—		$	—		923.784	$	457,284		48.620	$	126,908		972.404	$	584,192
Distribution amount per partnership unit			$	—			$	4,618.69			$	16,035.73

See accompanying notes to financial statements.

F-45

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Reef Global Energy VII, L.P.

Statements of Cash Flows

	For the Years Ended December 31,
	2010			2009			2008
	2011			2010			2009
Operating Activities
Net income (loss)	$	~~368~~4,~~566~~516,352		$	~~(366~~368,~~021~~566	)	$	(3366,~~968,996~~021	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments for non-cash transactions:
Depreciation, depletion and amortization	~~540~~313,~~316~~136			~~606~~540,~~787~~316			1606,~~346,930~~787
Property impairment	—			~~566,679~~—			4566,~~290,665~~679
Accretion of asset retirement obligation	1612,~~448~~182			1816,~~722~~448			6518,~~726~~722
Gain on sale of oil and gas properties	(4,254,098		)	—			—
Changes in operating assets and liabilities:
Accounts receivable	~~3,471~~(18		)	~~(456~~3,471		)	(~~3,015~~456		)
Accounts receivable from affiliates	~~100~~83,~~189~~721			~~(314~~100,~~397~~189		)	—(314,397		)
Accounts payable	640,~~404~~208			56,~~140~~404			~~537~~5,140
Accounts payable to affiliates	~~(70,096~~—		)	(~~290~~70,~~339~~096		)	~~246~~(290,~~646~~339		)
Net cash provided by operating activities	~~965~~711,~~298~~483			~~226~~965,~~115~~298			1226,~~978,493~~115
Investing Activities
Property acquisition and development	(371,224		)	(198,994		)	(732,983		)
Proceeds from sale of oil and gas properties	4,429,474			—			—
Net cash used in investing activities	(371,224		)	(198,994		)	(732,983		)
Property acquisition and development	(33,701		)	(371,224		)	(198,994		)
Net cash provided by (used in) investing activities	4,395,773			(371,224		)	(198,994		)
Financing Activities
Partner capital contributions	—			~~3,440~~—			163,~~330~~440
Offering costs	—			~~(360,000~~—		)	(~~330~~360,000		)
Partner distributions	(~~593~~5,~~793~~046,326		)	(51593,~~784~~793		)	(151,~~748,800~~784		)
Net cash used in financing activities	(~~593~~5,~~793~~046,326		)	(~~408~~593,~~344~~793		)	(2408,~~062,470~~344		)
Net increase (decrease) in cash and cash equivalents	~~281~~60,930			~~(381,223~~281		)	(~~816~~381,~~960~~223		)
Cash and cash equivalents at beginning of period	63,~~432~~713			~~444~~63,~~655~~432			1444,~~261,615~~655
Cash and cash equivalents at end of period	$	63124,~~713~~643		$	63,~~432~~713		$	~~444~~63,~~655~~432
Non-cash investing transactions
Property additions included in accounts payable to affiliates	$	—		$	—		$	22,575
Property additions and asset retirement obligation	$	—		$	6,162		$	—
Property additions and asset retirement obligation	$	6,162		$	—		$	79,341
Asset retirement obligation reduction resulting from sale and disposition of proved properties	$	205,026		$	—		$	—
Non-cash financing transactions:
Offering costs included in accounts payable to affiliates	$	—		$	~~70,096~~—		$	~~360~~70,~~000~~096
Offering costs included in non-current accounts payable to affiliates	$	—		$	—		$	70,096

See accompanying notes to financial statements.

F-56

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Reef Global Energy VII, L.P.

Notes to Financial Statements (continued)

1. Organization and Basis of Presentation

Reef Global Energy VII, L.P. (the “Partnership”) is the second in a series of four Nevada limited partnerships comprising a program called Reef Global Energy Ventures II (the “Program”), pursuant to an S-1 Registration Statement declared effective by the Securities and Exchange Commission (the “SEC”) on July 7, 2005. In order to be formed, each partnership was required to sell a minimum of 40 partnership units at $25,000 per unit, including units purchased by the managing general partner. Each partnership formed as a part of the Program offered a minimum of 1,000 and a maximum of 2,000 units for sale. The Program was authorized to sell up to 1,600 limited partner units and 6,400 general partner units during the period beginning July 8, 2005 through July 7, 2007. The Partnership offered 1,200 units for sale ($30,000,000); consisting of up to 240 limited partner units and up to 960 general partner units. Investor funds were held in escrow and were subject to reimbursement with interest if the minimum number of units was not sold. The Program filed a prospectus supplement with the SEC on November 15, 2005 describing the Partnership, and commenced offering units in the Partnership. Upon reaching the minimum subscription level, the Partnership was formed on December 29, 2005. The Partnership offering closed April 28, 2006, with sales to outside investors totaling 741.001 general partner units and 182.783 limited partner units, and sales to the managing general partner totaling 48.620 general partner units.

The Partnership is a Nevada limited partnership formed under the Nevada Uniform Limited Partnership Act. Reef Oil & Gas Partners, L.P. (“Reef”) serves as the Partnership’s managing general partner. Partnership interests are held by the managing general partner and investor partners who are general and limited partners (“investor partners”). The managing general partner received a 10% interest in the Partnership as compensation for forming the Partnership, and also holds a 1% interest in the Partnership as a result of paying 1% of all leasehold, drilling and completion costs. This 11% interest is not represented by Partnership units. In addition, Reef purchased 5% of the Partnership units and, therefore, holds 5% of the 89% interest in the Partnership (4.45%) held by the unit holders. The Partnership purchased working interests in exploratory and developmental drilling prospects and drilled oil and gas wells located onshore in the continental United States. Other partnerships formed as a part of this Program, as well as other partnerships managed by Reef also own interests in some of the prospects purchased by this Partnership. In instances where Reef-affiliated entities own a majority working interest in a prospect, wells drilled on that prospect may be operated by Reef Exploration, L.P. (“RELP”), an affiliate of the managing general partner. The Partnership does not operate in any other industry segment.

~~Pursuant~~Upon tocompletion ~~the Partnership Agreement~~ of the Partnership’s drilling program, all general partner units held by investors other than the managing general partner were converted into limited partner units. ~~This~~The ~~conversion~~Partnership ofcurrently ~~general~~has ~~partner~~923.784 units ~~into limited partner units occurred during the 3rd quarter~~ of ~~2008. The general partner equity at June 30, 2008 was transferred to~~ limited partner ~~equity,~~interest and ~~all~~48.620 ~~income~~units ~~and expense items subsequent to the second quarter~~ of ~~2008 have been allocated between the managing~~ general partner ~~and~~interest ~~the limited partners~~outstanding.

Under the terms of the partnership agreement, certain income and expense items are allocated differently between the managing general partner and the investor partners. Allocations of income and expense to the managing general partner and investor partners are made quarterly based upon the number and type of partnership units held at the end of the quarter.

Organization and offering costs are allocated 100% to investor partners, as the managing general partner purchases its units net of the 15% fee for organization and offering costs. Quarterly cash distributions to partners are based upon the number and type of partnership units held at the close of the prior quarter. Cash distributions to partners of the net cash flow from interest income and crude oil and natural gas sales revenues, less operating, general and administrative, and other costs are distributed 15.45% to the managing general partner (based upon the 11% interest not represented by units and the 4.45% interest represented by Partnership units) and 84.55% to investor partners.

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Reef Global Energy VII, L.P.

Notes to Financial Statements (continued)

Going Concern

The accompanying financial statements have been prepared assuming the Partnership is a going concern, which assumption contemplates the realization of assets and satisfaction of liabilities in the normal course of business.

During 2011, the Partnership sold its interest in the Cole Ranch Properties (eight productive wells). As a result of this sale, the Partnership has two significant producing properties that are expected to account for over 90% of future Partnership revenues. These two properties have estimated economic reserve lives of 1.14 and 5.83 years, respectively, utilizing current prices, costs, and projected production volumes at December 31, 2011. The Partnership distributed the Cole Ranch sales proceeds to investors, and has no plans to drill additional wells. The Partnership also has no plans to engage in commodity futures trading or hedging activities. Finally, the estimated economic reserve life of Partnership wells is computed based upon operating revenues and costs and does not consider Partnership general and administrative costs. Future cash flows generated from Partnership wells will be significantly impacted by actual prices received subsequent to December 31, 2011, and by actual production volumes from the Partnership’s most significant wells. While management believes that the Partnership will generate positive cash flows during 2012, variations in pricing and production volumes could lead to rapidly declining cash flows from operations and Partnership losses. These conditions raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Partnership be unable to continue as a going concern.

2. Summary of Accounting Policies

Use of Estimates

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

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

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 crude oil and natural 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 crude oil and natural gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves, as determined by independent petroleum engineers. For these purposes, proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method 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 12F-month unweighted 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 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 $0, $566,679, and $4,118,218, respectively.8

Unproved properties consist of undeveloped leasehold interests. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. During the year ended December 31, 2008, the Partnership fully impaired its unproved properties by recognizing $172,447 of property impairment expense.

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Notes to Financial Statements (continued)

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. No gain or loss is recognized upon sale or disposition of crude oil and natural gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the years ended December 31, 2011 and 2010, the Partnership recognized no property impairment expense of proved properties. During the year ended December 31, 2009, the Partnership recognized property impairment expense of proved properties totaling $566,679. During the year ended December 31, 2011, the Partnership recognized gain of $4,254,098 related to the Partnership’s sale and disposition of all rights, title, and interest in leases, lands, and wells located in Glasscock County, Texas (“Cole Ranch Properties”).

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at December 31, 2011, 2010, and 2009 have been prepared and presented in accordance with ~~new~~ SEC rules and accounting standards. ~~These~~which ~~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 unweighted 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. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by independent petroleum engineers.

Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.

The adoption of the new SEC rules and accounting standards at December 31, 2009 resulted in a downward adjustment of $888,180 to the estimated discounted future cash flows from proved reserves, and in a reduction of 8,770 BOE equivalent of proved reserves. Additionally, the change resulted in increases of $7,480 and $197 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.

The following table summarizes the Partnership’s asset retirement obligation for the years ended December 31, ~~2010~~2011 and ~~2009~~2010.

	2010		2009
Beginning asset retirement obligation	$	289,494	$	270,772
Additions related to well conversion	6,162		—
Accretion expense	16,448		18,722
Ending asset retirement obligation	$	312,104	$	289,494

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Notes to Financial Statements (continued)

	2011			2010
Beginning asset retirement obligation	$	312,104		$	289,494
Additions related to well conversion	—			6,162
Accretion expense	12,182			16,448
Retirement related to sale of proved properties	(205,026		)	—
Ending asset retirement obligation	$	119,260		$	312,104

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~~2011, ~~2009~~2010, and ~~2008~~2009.

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~~2011, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $4.7580 million, primarily due to the difference between property impairment costs deducted for financial reporting purposes and intangible drilling costs deducted for income tax purposes.

Accounting for Uncertainty in Income Taxes

The Financial Accounting Standards Board (“FASB”) provides guidance on accounting for uncertainty in income taxes. This guidance is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s 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, 2011 and 2010. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2011 and 2010. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature.

~~Recently Adopted Accounting Pronouncements~~F-10

Modernization of Oil and Gas Reporting

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Notes to Financial Statements (continued)

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.

3. Transactions with Affiliates

The Partnership has no employees. 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. During the years ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009 the Partnership incurred technical services and administrative costs totaling $~~190~~116,~~982~~958, $~~215~~190,~~181~~982, and $~~338~~215,~~040~~181, respectively. Of these amounts, $110,~~836,~~ $111,~~207~~836, and $581,~~114~~207 represent technical services costs capitalized as project costs, and $~~179~~116,~~146~~958, $~~213~~179,~~974~~146, and $~~279~~213,~~926~~974 represent administrative costs included as general and administrative expenses.

Reef ~~contributes~~contributed 1% of all leasehold, drilling, and completion costs when incurred. During the years ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009, this 1% obligation totaled $0, $30,~~440,~~ and $53,~~361~~440. Reef also purchased 5% of the Partnership units and pays 5% of the 99% of these costs paid by the unit holders (4.95%).

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At December 31, ~~2010~~2011 and ~~2009~~2010, RELP owed the partnership $~~214~~130,~~208~~487 and $~~314~~214,~~397~~208, respectively, for net revenues processed in excess of joint interest and technical and administrative charges. The Partnership settles its balances with Reef and RELP on at least a quarterly basis.

~~Accounts~~If ~~payable~~an toaffiliate ~~affiliates as~~ of ~~December 31,~~Reef ~~2010~~serves ~~and~~as ~~2009~~operator ~~also~~of ~~includes~~a $0Partnership ~~and $70~~prospect,~~096,~~ ~~respectively,~~then ~~for~~operator ~~the~~fees ~~unpaid~~are ~~portion~~payable ofto the ~~15%~~affiliate. ~~management~~Under ~~fee~~such ~~due Reef for organization and offering costs~~circumstances, ~~including~~such ~~sales~~affiliate ~~commissions.~~receives ~~The~~fees ~~management~~at ~~fee~~the iscompetitive ~~payable~~rate in ~~two~~the ~~parts.~~geographical ~~Reef~~area ~~initially~~where ~~received~~the anprospect ~~amount~~is ~~not~~located toduring ~~exceed~~the ~~13.5%~~drilling ~~to recover actual commissions~~ and ~~organization~~production ~~and~~phase ~~offering~~of ~~costs~~operations. ~~The~~These ~~remaining~~fees ~~portion~~are ofcharged ~~the~~as ~~management~~a monthly fee isper ~~paid~~well toas ~~Reef~~agreed ~~from~~to ~~the~~in ~~oil~~an ~~and~~operating ~~gas~~agreement ~~cash~~signed ~~flows~~by ~~available~~the ~~for~~Partnership ~~partner~~as ~~distributions,~~well atas aoutside ~~rate~~third ~~not~~party toworking ~~exceed~~interest $1owners ~~million~~in ~~per~~the ~~year~~well. During ~~2009,~~ the ~~Partnership~~years ~~reimbursed~~ended ~~$360~~December 31,~~000~~ of2011, ~~this~~2010, ~~amount~~and ~~to Reef. The remaining $70~~2009,~~096~~ ~~was~~the ~~classified~~Partnership aspaid aoperating ~~short~~overhead ~~term~~fees ~~liability~~totaling ~~to affiliates at December 31~~$35,004, ~~2009~~$46,536, and ~~the~~$44,473 ~~Partnership completed payment of the balance~~ to ~~Reef~~RELP, ~~in February 2010~~respectively.

IfThe anPartnership ~~affiliate~~reimbursed ofto Reef ~~serves~~legal asfees ~~operator~~totaling of$11,124 aand ~~Partnership~~$8,621, ~~prospect~~respectively, ~~then~~during ~~operator fees are payable to~~ the ~~affiliate.~~years ~~Under~~ended ~~such~~December ~~circumstances~~31, ~~such~~2011 ~~affiliate~~and ~~receives~~2010 ~~fees~~pertaining atto the ~~competitive~~lawsuit ~~rate~~described in ~~the~~Note ~~geographical~~5 ~~area~~below. The ~~where~~partners ~~the~~who ~~prospect~~brought ~~is located during~~ the ~~drilling~~lawsuit ~~and~~are ~~production~~partners ~~phase~~in ofseveral ~~operations.~~Reef ~~These~~affiliates, ~~fees~~including ~~are~~this ~~charged~~Partnership, asand atheir ~~monthly~~claims ~~fee~~involve ~~per~~their ~~well~~participation ~~as agreed to~~ in anthese ~~operating~~partnerships, ~~agreement~~including ~~signed~~this byPartnership. Pursuant to the Partnership asAgreement ~~well~~of asthe ~~outside~~Partnership, ~~third~~Reef ~~party~~is ~~working~~indemnified ~~interest~~against ~~owners~~litigation insuch ~~the~~as ~~well.~~this, ~~During~~and the ~~years~~associated ~~ended~~legal ~~December 31,~~fees ~~2010,~~are ~~2009,~~being ~~and~~reimbursed ~~2008,~~to ~~the~~Reef ~~Partnership~~by ~~paid~~each ~~operating~~of ~~overhead~~the ~~fees~~partnerships ~~totaling~~involved ~~$46,536,~~on ~~$44,473,~~a ~~and~~quarterly ~~$40,879 to RELP, respectively~~basis.

4. Major Customers

~~F-10~~5. Commitments and Contingencies

On August 26, 2010, Frank Stevenson (“Stevenson”) filed a lawsuit, styled Stevenson v. Wayne Kirk, Michael J. Mauceli, Reef Global Energy Ventures II, et al., Cause No. 10-10647, in the 191st Judicial District Court, Dallas County, Texas. The suit also names as defendants Reef Global Energy VII, L.P. and multiple other Reef-sponsored ventures and limited partnerships, as well as Reef Securities, Inc., among others (collectively, “Defendants”). On September 22, 2010, James and Carol Estle (the “Estles”) and Nancy Dykes Thurmond Antolic (“Antolic”) joined the suit as additional plaintiffs. On January 27, 2011, Donna Stevenson (Frank Stevenson’s spouse) and Jaime Davis (“Davis”) joined the suit as additional plaintiffs (Stevenson, Estles, Antolic, and Davis are collectively referred to as “Plaintiffs”). With respect to Davis’s claims, specifically, Reef Securities, Inc. did not offer or sell the interests in the Reef program that Davis purchased. Rather, she purchased her interests through an unaffiliated broker/dealer.

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Notes to Financial Statements (continued)

5In the Sixth Amended Petition, Plaintiffs assert claims of misrepresentations and omissions under the Texas Securities Act (“TSA”), control person and aider and abettor liability under the TSA, fraud, breach of fiduciary duty, breach of contract, civil theft, negligent misrepresentation, and fraudulent concealment. ~~Commitments~~Plaintiff Davis asserts against defendant Reef Oil & Gas Income and ~~Contingencies~~Development Fund, L.P. a claim for tortious interference with an existing contract. Defendants believe Plaintiffs’ claims are meritless because, among other things, in connection with each Reef program in which Plaintiffs participated, each Plaintiff received offering documents that thoroughly disclosed all material facts and risks associated with participation in such programs, particularly the fact that no guarantees or promises could be made or relied upon. Plaintiffs also claim that Defendants misallocated costs, expenses and deductions among unidentified Reef-sponsored ventures and limited partnerships. Plaintiffs seek approximately $2.2 million as actual damages, $620,000 as exemplary damages, as well as attorneys’ fees, pre- and post-judgment interest, and costs. Defendants (including Reef Global Energy VII, L.P.) intend to vigorously defend the lawsuit and may seek damages from plaintiffs based upon, among other things, breaches of representations and warranties made by them as well as the indemnification provisions of the documents executed by each of them. Defendants have filed Motions for Partial Summary Judgment seeking the dismissal of certain of Plaintiffs Stevenson, Estles, and Antolic’s claims, and the parties are currently awaiting the Court’s entry of an order on said Motions. However, following Defendants’ filing of their Motions for Summary Judgment, by filing their Sixth Amended Petition, Plaintiffs dismissed their claims for rescission under the TSA for failure of Defendants to register under the TSA, control person liability under the TSA in connections with such registration claims, and a majority of Plaintiffs’ fraud claims under the TSA. As of this time, discovery is ongoing, and trial has been set for December 10, 2012. The Partnership is reimbursing to Reef its share of the costs of defending this lawsuit as incurred, and has reimbursed $11,124 and $8,621, respectively, during the years ended December 31, 2011 and 2010.

6. Partnership Equity

Sales of Partnership units began on November 15, 2005. Proceeds received were placed into an interest bearing escrow account until the Partnership reached the minimum subscription level of 40 units. The Partnership was formed on December 29, 2005 and the sale of Partnership units was closed on April 28, 2006. The Partnership raised $23,094,590 from the sale of 923.784 Partnership units to investor partners. Reef purchased 48.620 units (5%) for $1,033,179. Reef also ~~contributes~~contributed ~~1% of all leasehold~~$202,585 ~~drilling, and completion costs when incurred,~~ in ~~addition~~connection towith ~~having paid~~ its ~~pro~~obligation ~~rata~~to ~~share~~pay ~~(4.95~~1%) of ~~the~~all leasehold, drilling, and completion costs ~~paid by the Partnership~~. ~~In connection with this obligation, Reef has contributed $202,585 to the Partnership at December 31, 2010.~~

All units, except those purchased by Reef, paid a 15% management fee to Reef to pay for Partnership organization and offering costs, including sales commissions. These costs totaled $3,464,188, leaving net capital contributions of $20,866,166 available for Partnership oil & gas activities. Of the $3,464,188 management fee, offering costs were $3,414,188 and organization costs were $50,000. The Partnership drilled twenty-nine wells and completed drilling operations with the capital raised by the Partnership in 2008.

Reef exclusively manages and controls all aspects of the business of the Partnership. The Partnership agreement prohibits participation by investor partners in the Partnership’s day-to-day business decisions.

87. 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 each of the years indicated:

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Notes to Financial Statements (continued)

December 31,	~~2010~~2011			~~2009~~2010			~~2008~~2009
Oil and natural gas properties:
Proved properties	$	2113,~~979~~246,~~751~~115		$	21,~~602~~979,~~365~~751		$	21,~~403~~602,~~371~~365
	21,979,751			21,602,365			21,403,371
	13,246,115			21,979,751			21,602,365
Less:
Accumulated depreciation, depletion and amortization	(32,~~569~~463,~~405~~179		)	(3,~~029~~569,~~089~~405		)	(23,~~422~~029,~~302~~089		)
Property impairment	(1710,~~249~~282,~~916~~343		)	(17,249,916		)	(1617,~~683~~249,~~237~~916		)
Total	$	1500,~~160,430~~593		$	1,~~323~~160,~~360~~430		$	21,~~297~~323,~~832~~360

Costs Incurred

The following table sets forth costs incurred in oil and gas exploration and development activities during the years ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009:

	2010			2009		2008
	2011			2010		2009
Oil and natural gas properties:
Exploration	$	9(1,~~200~~809	)	$	599,~~641~~200	$	~~(134~~59,~~657~~641	)
Development	~~368~~35,~~185~~510			~~137~~368,~~621~~185		~~721~~137,~~946~~621
Total	$	~~377~~33,~~385~~701		$	~~197~~377,~~262~~385	$	~~587~~197,~~289~~262

Results of Operations

The following table sets forth results of operations from oil and gas producing activities for the years ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009.

	2010			2009			2008
	2011			2010			2009
Oil and gas producing activities:
Oil sales	$	1917,~~036,282~~019		$	~~827~~1,~~273~~036,282		$	1827,~~590,912~~273
Natural gas sales	~~485~~241,~~595~~530			~~590~~485,~~024~~595			1590,~~270,540~~024
Production expenses	(~~315~~350,~~265~~905		)	(~~309~~315,~~310~~265		)	(~~679~~309,~~115~~310		)
Accretion of asset retirement obligation	(1612,~~448~~182		)	(1816,~~722~~448		)	(6518,~~726~~722		)
Depreciation , depletion and amortization	(~~540~~313,~~316~~136		)	(~~606~~540,~~787~~316		)	(1606,~~346,930~~787		)
Property impairment expense	—			~~(566,679~~—		)	(4566,~~118,218~~679		)
Results of operations from producing activities	$	~~649~~482,~~847~~326		$	~~(84~~649,~~201~~848	)	$	(384,~~348,537~~201	)
Depletion rate per BOE	$	1716.7891		$	1517.7078		$	3515.4870

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 firms Forrest A. Garb & Associates, Inc., as of December 31, 2011, 2010 and 2009~~, and by Gleason Engineering as of December 31, 2008~~. A copy of the Forrest A. Garb & Associates summary reserve report is included as Exhibit 99.1 to this Annual Report. Proved crude oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. At

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Notes to Financial Statements (continued)

~~and operating methods. At~~ December 31, ~~2010~~2011, 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 table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, ~~2010~~2011, ~~2009~~2010, and ~~2008~~2009.

	Oil (BBL) (1)		Gas (mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2007	96,871		755,717		222,824
Revisions of previous estimates	(47,433	)	(222,083	)	(84,447	)
Production	(16,045	)	(131,512	)	(37,964	)
Reserves at December 31, 2008	33,393		402,122		100,413
Revisions of previous estimates	23,517		(73,479	)	11,270
Production	(15,200	)	(140,623	)	(38,637	)
Reserves at December 31, 2009	41,710		188,020		73,046
Revisions of previous estimates	20,258		139,882		43,572
Production	(14,268	)	(96,722	)	(30,388	)
Reserves at December 31, 2010	47,700		231,180		86,230
Reserves sold	(32,473	)	(74,438	)	(44,880	)
Revisions of previous estimates	1,469		(15,246	)	(1,071	)
Production	(10,056	)	(50,796	)	(18,522	)
Reserves at December 31, 2011	6,640		90,700		21,757

(1) Oil includes both oil and natural gas liquids

(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.

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

Standardized Measure of Discounted Future Net Cash Flows

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

For the years ended December 31, 2010 and 2009, future cash inflows are computed by applying the new SEC pricing, which holds constant the unweighted 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~~2011, calculations were made using average prices of $7995.7984 per barrel of crude oil and $4.3915 per MCF of natural gas. For the year ended December 31, ~~2009~~2010, calculations were made using average prices of $6179.0879 per barrel of crude oil and $34.8339 per MCF of natural gas. For the year ~~ending~~ended December 31, ~~2008~~2009, 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 $4461.6008 per barrel of crude oil and $53.7183 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.

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~~the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.

~~does~~Future ~~not~~development ~~rely~~and ~~upon~~production costs are computed by estimating the ~~following~~expenditures ~~information~~to be incurred in ~~making~~developing ~~investment~~and producing the proved crude oil and ~~operating~~natural ~~decisions~~gas ~~for~~reserves at the ~~Partnership~~end of the year, based on year-end costs and assuming continuation of existing economic conditions.

~~F-13~~A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.

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Notes to Financial Statements (continued)

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.

December 31,	2011			2010			2009
Crude oil and natural gas properties owned by the Partnership:
Future cash inflows	$	1,076,880		$	4,998,080		$	3,245,780
Future production costs	(324,970		)	(2,355,900		)	(1,600,550		)
Future development costs	—			—			(89,200		)
Future net cash flows	751,910			2,642,180			1,556,030
Effect of discounting net cash flows at 10%	(96,690		)	(544,380		)	(232,670		)
Discounted future net cash flows	$	655,220		$	2,097,800		$	1,323,360

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

December 31,	2010			2009			2008
Crude oil and natural gas properties owned by the Partnership:
Future cash inflows	$	4,998,080		$	3,245,780		$	3,959,364
Future production costs	(2,355,900		)	(1,600,550		)	(1,217,470		)
Future development costs	—			(89,200		)	—
Future net cash flows	2,642,180			1,556,030			2,741,894
Effect of discounting net cash flows at 10%	(544,380		)	(232,670		)	(444,062		)
Discounted future net cash flows	$	2,097,800		$	1,323,360		$	2,297,832

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

December 31,	~~2010~~2011			~~2009~~2010			~~2008~~2009
Crude oil and natural gas properties owned by the Partnership:
Standardized measure at beginning of period	$	12,~~323~~097,~~360~~800		$	21,~~297~~323,~~832~~360		$	72,~~199~~297,~~362~~832
Extensions and discoveries							—
Net change in sales price, net of production costs	~~599~~171,~~658~~135			~~(240~~599,~~994~~658		)	(1240,~~471,634~~994		)
Revisions of quantity estimates	1(28,~~060,019~~147		)	~~215~~1,~~897~~060,019			(1215,~~932,472~~897		)
Net changes in estimated future development costs	—			~~(75,862~~—		)	(4275,~~183~~862		)
Changes in production timing rates	~~172~~(92,~~591~~615		)	~~(14~~172,~~031~~591		)	(5814,~~566~~031		)
Accretion of discount	~~132~~209,~~336~~780			~~229~~132,~~783~~336			~~719~~229,~~936~~783
Sales net of production costs	(1795,~~190,164~~462		)	(1,~~089~~190,~~265~~164		)	(21,~~116~~089,~~611~~265		)
Net increase (decrease)	774,440			(974,472		)	(4,901,530		)
Sales of minerals in place	(907,271		)	—			—
Standardized measure at end of year	$	2,097,800		$	1,323,360		$	2,297,832
Net increase (decrease)	(1,442,580		)	774,440			(974,472		)
Standardized measure at end of year	$	655,220		$	2,097,800		$	1,323,360

F-1415

Filing Compare · Reef Global Energy VII, L.P.