UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549










Form
10-K







(Mark
One)





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





For
      The Fiscal Year Ended December 31,
2009




or




 ̈
              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
                incorporation
      or organization)
              (I.R.S.
      Employer
                Identification
      No.)





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


(Address
of principal executive offices including zip code)





(972)-437-6792


(Registrant’s
telephone number, including area code)





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


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





General and Limited
Partnership Interests


(Title of
Class)





Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.      Yes ̈Nox




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 ̈Nox




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.  YesxNo ̈




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




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




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





Large
      accelerated filer  ̈
                Accelerated
      filer  ̈
                Non-accelerated
      filer   ̈
                Smaller reporting
      companyx





Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act)           Yes ̈Nox




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




As of
March 31, 2010, 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







REEF GLOBAL ENERGY VII,
L.P.


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


TABLE OF
CONTENTS





Part IItem
      1.
                                                                                                                                                              Business
                                                                                                                                                              3Item
      1A.
                                                                                                                                                              Risk
      Factors
                                                                                                                                                              8Item
      1B.
                                                                                                                                                              Unresolved
      Staff Comments
                                                                                                                                                              12Item
      2.
                                                                                                                                                              Properties
                                                                                                                                                              12Item
      3.
                                                                                                                                                              Legal
      Proceedings
                                                                                                                                                              14Item
      4.
                                                                                                                                                              Reserved
                                                                                                                                                              16PART IIItem
      5.
                                                                                                                                                              Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
                                                                                                                                                              16Item
      6.
                                                                                                                                                              Selected
      Financial Data
                                                                                                                                                              17Item
      7.
                                                                                                                                                              Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                                                                                                                                                              18Item
      7A.
                                                                                                                                                              Quantitative
      and Qualitative Disclosure About Market Risk
                                                                                                                                                              24Item
      8.
                                                                                                                                                              Financial
      Statements and Supplementary Data
                                                                                                                                                              24Item
      9.
                                                                                                                                                              Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
                                                                                                                                                              24Item
      9A(T).
                                                                                                                                                              Controls
      and Procedures
                                                                                                                                                              25Item
      9B.
                                                                                                                                                              Other
      Information
                                                                                                                                                              25PART IIIItem
      10.
                                                                                                                                                              Directors,
      Executive Officers and Corporate Governance
                                                                                                                                                              25Item
      11.
                                                                                                                                                              Executive
      Compensation
                                                                                                                                                              27Item
      12.
                                                                                                                                                              Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                                                                                                                                                              28Item
      13.
                                                                                                                                                              Certain
      Relationships and Related Transactions, and Director
      Independence
                                                                                                                                                              29Item
      14.
                                                                                                                                                              Principal
      Accountant Fees and Services
                                                                                                                                                              2929PART IVItem
      15.
                                                                                                                                                              Exhibits
      and Financial Statement Schedules
                                                                                                                                                              29Signatures
                                                                                                                                                              31




2





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 drilled
twenty-one developmental wells. The Partnership purchased working interests in
seven exploratory prospects upon which it drilled 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 developmental and two exploratory Partnership
prospects. RELP operates eight successful wells located on one developmental
prospect and operates one successful developmental well drilled on one of the
Partnership’s exploratory prospects. 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 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.


3





Consulting
Agreements for Prospect Acquisitions





Reef
entered into two agreements (the CMI Agreements) with Challenger Minerals Inc.
(CMI), a subsidiary of GlobalSantaFe Corporation and a screener of oil and gas
prospects in the Gulf of Mexico and North Sea regions. Under the terms of these
agreements, Reef had the opportunity to review and selectively participate in
exploratory and developmental prospects either originated or previewed by CMI.
Reef paid CMI for the geological and geophysical services provided by CMI. The
agreements expired in January and November, 2006.





Reef also
entered into an agreement with Access Exploration Corp. (AEC), a screener of
domestic oil and gas prospects both onshore and in the Gulf of Mexico. This
agreement provided Reef the opportunity to review and selectively participate in
exploratory and developmental prospects previewed by AEC. Reef paid AEC an
annual fee for the geological and geophysical services provided by AEC. This
agreement expired in October 2007.





Prospects
approved for acquisition by Reef under these agreements could be assigned to
this Partnership as well as other limited partnerships formed as part of the
Program. Each partnership formed as a part of the Program paid Reef, on a pro
rata basis, a portion of the fees paid by Reef under these agreements during the
term of the Program. Total reimbursements to Reef by the partnerships formed as
a part of this Program were equal to the actual fees paid by Reef under these
agreements. The Partnership paid Reef $150,736 as its pro rata share of these
fees. This amount has been capitalized as geological and geophysical costs in
accordance with the full cost method of accounting for oil and gas
properties.





Drilling
and Completion Phase of Operations





RELP is
currently the operator of three developmental and two exploratory prospects, and
serves as operator of nine successful wells in which the Partnership has a
working interest. RELP also served as operator for ten unsuccessful Partnership
wells, including eight wells on the Sand Dunes prospect discussed in more detail
in Item 2 - Properties. 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.





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.  Eleven development wells and six exploratory wells
drilled by the Partnership were unsuccessful. Of the eleven unsuccessful
developmental wells, eight developmental wells on the Sand Dunes prospect in
which the Partnership participated have not been plugged and abandoned at this
time.





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 eleven successful developmental wells and one successful exploratory
well. The successful exploratory well ceased producing during 2007. Three
developmental and six exploratory wells were unsuccessful and have been plugged
and abandoned. Eight developmental wells on the Sand Dunes prospect in which the
Partnership participated and which were classified as unsuccessful during 2008
have not been plugged and abandoned.


4





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).





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."





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, 2009, two marketers and one
operator accounted for 33.4%, 39.4%, and 26.9% of the Partnership’s crude oil
and natural gas revenues, respectively.  During the year ended
December 31, 2008, two marketers and one operator accounted for 41.7%, 41.4%,
and 14.9% of the Partnership’s crude oil and natural gas revenues, respectively.
During the year ended December 31, 2007, two marketers accounted for 79.4% and
16.5% 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.


5





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.





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.





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.


6





Regulation





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





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





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





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





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





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


7





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."





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;


·
            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.


8





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 42.9% of the Partnership’s
estimated proved reserves were crude oil reserves and 57.1% were natural gas
reserves at December 31, 2009. 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
recent global economic downturn could have a material adverse impact on our
financial position, results of operations and cash flows.





The oil
and gas industry is cyclical and tends to reflect general economic conditions.
The United States and other countries around the world have experienced an
economic downturn which could impact the industry in 2010 and beyond. The
economic downturn has had an adverse impact on demand and pricing for crude oil
and natural gas. A continuation of the economic downturn could have a further
negative impact on crude oil and natural gas prices. The Partnership’s operating
cash flows and profitability will be significantly affected by declining crude
oil and natural gas prices. Further declines in crude oil and natural gas prices
may also impact the value of our crude oil and natural gas reserves, which could
result in future impairment charges to reduce the carrying value of the
Partnership’s oil and gas properties.





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.


9





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.





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, 2009 are based upon the 12-month un-weighted
arithmetic average of the first-day-of-the-month prices and costs in effect when
the estimate is made. Actual current prices, as well as future prices and costs,
may be materially higher or lower. Further, actual future net cash flows will be
affected by factors such as the amount and timing of actual production, supply
and demand for crude oil and natural gas, and changes in governmental
regulations and tax rates.





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





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





·
            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.





Drilling
exploratory wells is riskier than drilling developmental wells.





Drilling
exploratory wells involves greater risks of dry holes and loss of the partners'
investment than the drilling of developmental wells.  Drilling
developmental wells generally involves less risk of dry holes, although
sometimes developmental acreage is more expensive and subject to greater
royalties and other burdens on production. The Partnership purchased working
interests in seven exploratory prospects upon which seven exploratory wells and
one developmental well were drilled. Six exploratory wells were unsuccessful,
and one exploratory well was successful but ceased production during 2007. The
developmental well was successful and is currently producing crude oil and
natural gas.


10





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.





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.


11





The
Partnership may incur liability for liens against its
subcontractors.





Although
Reef will try to determine the financial condition of nonaffiliated
subcontractors, if subcontractors fail to timely pay for materials and services,
the properties of the Partnership could be subject to materialmen's and
workmen's liens.  In that event, the Partnership could incur excess
costs in discharging 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 drilled 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
drilled 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
cannot 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 a result, as of
December 31, 2008, the eight Sand Dunes wells were classified as unsuccessful,
and no crude oil and natural gas reserves for these wells were included in the
December 31, 2008 reserve information presented in this Annual
Report.





Beginning
with March 2009, oil sales prices increased from levels below $40 per barrel to
between $60 and $70 per barrel. 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 began in March 2010. Upon conversion of this
well to a salt water disposal well, three of the current Sand Dunes wells are
expected to be placed on full time production during the second quarter of 2010.
RELP believes, based upon testing already performed, that the disposal capacity
of the well to be converted will be such that only three Sand Dunes wells can be
placed on full time production. However, if possible, additional wells may be
placed on production. RELP will determine what actions to take regarding the
other Sand Dunes wells after a period of evaluation of this initial conversion.
The estimated cost of the well conversion to this Partnership is expected to be
approximately $89,200. This cost will be paid for by the Partnership by
retaining a portion of the funds normally paid out in distributions to the
partners. There are 6,000 BBL of crude oil and 9,930 MCF of natural gas reserves
for the three wells expected to be placed on full time productions included in
the December 31, 2009 reserve information presented in this Annual
Report.


12





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 based upon the eight already drilled wells being classified as
unsuccessful at December 31, 2008. The Partnership currently has no plans to
conduct any drilling operations on this acreage.





The
Partnership 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.





Eleven of
the twelve successful wells in which the Partnership participated drilling are
currently productive.





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 un-weighted arithmetic average of the
first-day-of-the-month commodity prices over the preceding 12-month period,
rather than end-of-period prices, and allows the use of reliable technologies to
estimate proved crude oil and natural gas reserves, if those technologies have
been demonstrated to result in reliable conclusions about reserves volumes.
Reserve and related information for 2009 is presented consistent with the
requirements of the new rule. The new rule does not allow prior-year reserve
information to be restated, so all information related to periods prior to 2009
is presented consistent with prior SEC rules for the estimation of proved
reserves. The effect of applying the new definition of reliable technology and
other non-price related aspects of the updated rules did not significantly
impact 2009 net proved reserve volumes.  All of the Partnership’s
reserves are located in the United States.





The
estimated net proved crude oil and natural gas reserves at December 31, 2009,
2008, and 2007 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, 2007
                  
                  
                  96,871
                  
                  
                  
                  755,717Net
      proved reserves as of December 31, 2008
                  
                  
                  33,393
                  
                  
                  
                  402,122Net
      proved reserves as of December 31, 2009
                  
                  
                  41,710
                  
                  
                  
                  188,020





The
standardized measure of discounted future net cash flows as of December 31, 2009
is computed by applying the 12-month average beginning-of-month price for the
year, costs, and legislated tax rates and a discount factor of 10% to net proved
reserves.  The standardized measure of discounted future net cash
flows as of December 31, 2008 and 2007 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.


13







Standardized
      measure of discounted future net cash flows as of December 31,
      2007
                  
                  $
                  7,199,362Standardized
      measure of discounted future net cash flows as of December 31,
      2008
                  
                  $
                  2,297,832Standardized
      measure of discounted future net cash flows as of December 31,
      2009
                  
                  $
                  1,323,360





During
the years ended December 31, 2009, 2008, and 2007, the Partnership recorded
property impairment costs of proved properties totaling $566,679, $4,118,218,
and $10,739,537 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, 2009
estimates of net proved crude oil and natural gas reserves.  FGA
estimated reserves for all of our properties as of December 31, 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 and 2007 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
GAAP.





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





Title
to Properties





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





The
Partnership is not, and has not been, a party to any legal
proceedings.


14





ITEM
      4.
            
            Reserved





PART
II





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





As of
December 31, 2009, the Partnership had one managing general partner, and 883
investor limited 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.





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 2009.





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, 2009, 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. As of December 31, 2009, the Partnership
had expended $21,574,409 on property acquisitions and $137,512 on general and
administrative expenses. Expenditures in excess of available capital
contributions were deducted from Partnership distributions during
2009.


16





ITEM
      6.
            
            SELECTED
      FINANCIAL DATA





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





As of and For the Years Ended December 31,
                
                
                Period
                  from
                  Inception
                  (December
                  29, 2005)
                  to
                  December
                  312009
                
                
                2008
                
                
                2007
                
                
                2006
                
                
                2005Revenue
                
                $
                1,417,297
                
                
                $
                2,861,452
                
                
                $
                1,517,970
                
                
                $
                —
                
                
                $
                —Interest
      income
                
                
                1,447
                
                
                
                8,577
                
                
                
                317,661
                
                
                
                691,667
                
                
                
                1,212Costs
      and expenses
                
                
                (1,784,765
                )
                
                
                (6,839,025
                )
                
                
                (12,187,144
                )
                
                
                (1,894,563
                )
                
                
                (50,475
                )Net
      loss
                
                
                (366,021
                )
                
                
                (3,968,996
                )
                
                
                (10,351,513
                )
                
                
                (1,202,896
                )
                
                
                (49,263
                )Allocation
      of net loss:Managing
      general partner
                
                
                29,970
                
                
                
                (80,234
                )
                
                
                (476,894
                )
                
                
                (12,240
                )
                
                
                (73
                )General
      partner units
                
                
                —
                
                
                
                243,801
                
                
                
                (7,920,794
                )
                
                
                (956,084
                )
                
                
                (38,450
                )Limited
      partner units
                
                
                (395,991
                )
                
                
                (4,132,563
                )
                
                
                (1,953,825
                )
                
                
                (234,572
                )
                
                
                (10,740
                )Net
      income (loss) per managing general partner unit
                
                
                616.41
                
                
                
                (1,650.23
                )
                
                
                (9,808.55
                )
                
                
                (251.74
                )
                
                
                (20.58
                )Net
      income ( loss) per general partner unit
                
                
                —
                
                
                
                329.01
                
                
                
                (10,689.32
                )
                
                
                (1,290.26
                )
                
                
                (729.60
                )Net
      loss per limited partner unit
                
                
                (428.66
                )
                
                
                (4,209.61
                )
                
                
                (10,689.32
                )
                
                
                (1,283.33
                )
                
                
                (719.23
                )Total
      assets
                
                
                1,704,660
                
                
                
                2,745,502
                
                
                
                8,620,722
                
                
                
                21,786,620
                
                
                
                1,594,304Distributions
      to managing general partner
                
                
                7,961
                
                
                
                270,190
                
                
                
                238,316
                
                
                
                45,578
                
                
                
                —Distributions
      to investor partners
                
                
                43,824
                
                
                
                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
                
                
                47.44
                
                
                
                1,600.61
                
                
                
                1,411.78
                
                
                
                270.00
                
                
                
                —Distributions
      per managing  general partner unit
                
                
                163.73
                
                
                
                5,557.18
                
                
                
                4,901.60
                
                
                
                937.43
                
                
                
                —Operating
      DataAnnual
      sales volume:Gas
      (MCF)
                
                
                140,623
                
                
                
                131,512
                
                
                
                48,301
                
                
                
                —
                
                
                
                —Oil
      (BBL)
                
                
                15,201
                
                
                
                16,045
                
                
                
                14,032
                
                
                
                —
                
                
                
                —Average
      sales price:Gas
      (per MCF)
                
                $
                4.20
                
                
                $
                9.66
                
                
                $
                8.59
                
                
                $
                —
                
                
                $
                —Oil
      (per BBL)
                
                $
                54.42
                
                
                $
                99.15
                
                
                $
                78.60
                
                
                $
                —
                
                
                $
                —


17




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





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





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





Critical
Accounting Policies





The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires us to make estimates
and assumptions that can affect the reporting of assets, liabilities, equity,
revenues, and expenses. We base our estimates on historical experience and
various other assumptions that are believed to be reasonable under the
circumstances. Actual results may differ from these estimates under different
assumptions or conditions. We are also required to select among alternative
acceptable accounting policies. See Note 2 to the financial statements for a
complete list of significant accounting policies.





Oil
and Gas Properties





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





In
applying the full cost method at December 31, 2009, we perform a quarterly
ceiling test on the capitalized costs of oil and gas properties, whereby the
capitalized costs of oil and gas properties are limited to the sum of the
estimated future net revenues from proved reserves using prices that are the
12-month un-weighted arithmetic average of the first-day-of-the-month price for
crude oil and natural gas held constant and discounted at 10%, plus the lower of
cost or estimated fair value of  unproved properties, if any, for
2009. If capitalized costs exceed the ceiling, an impairment loss is recognized
for the amount by which the capitalized costs exceed the ceiling, and is shown
as a reduction of oil and gas properties and as property impairment expense on
the Partnership’s statement of operations.  No gain or loss is
recognized upon sale or disposition of oil and gas properties, unless such a
sale would significantly alter the rate of depletion and amortization. During
the years ended December 31, 2009, 2008 and 2007, the Partnership recognized
property impairment expense of proved properties totaling $566,679, $4,118,218,
and $10,739,537 respectively.





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.





The
estimate of proved crude oil and natural gas reserves used to determine property
impairment expense, and also utilized in the Partnership’s disclosures of
supplemental information regarding oil and gas producing activities, including
the standardized measure of discounted cash flows, was prepared by an
independent petroleum engineer at December 31, 2009, 2008, and 2007, 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.


18





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, 2009,
2008, and 2007, the Partnership had depreciation, depletion, and amortization
expense totaling $606,787, $1,346,930, and 1,075,372, respectively.





Asset
retirement costs and liabilities associated with future site restoration and
abandonment of long-lived assets are initially measured at fair value which
approximates the cost a third party would incur in performing the tasks
necessary to retire such assets. The fair value is recognized in the financial
statements as the present value of expected future cash expenditures for site
restoration and abandonment. Subsequent to the initial measurement, the effect
of the passage of time on the liability for the net asset retirement obligation
(accretion expense) and the amortization of the asset retirement cost are
recognized in the results of operations. During the years ended December 31,
2009, 2008, and 2007, the Partnership recognized $0, $79,341, and $121,062 of
asset retirement obligations and additional capitalized cost in connection with
successful wells drilled by the Partnership.





Recognition
of Revenue





The
Partnership has entered into sales contracts for disposition of its share of
crude oil and natural gas production from productive wells. Revenue is
recognized based upon the metered volumes delivered to those purchasers each
month. Any significant over or under balanced gas positions are disclosed in the
financial statements. As of December 31, 2009, 2008 and 2007, the Partnership
had no material gas imbalance positions.





Recently Adopted Accounting
Pronouncements





Modernization
of Oil and Gas Reporting





In
January 2009, the SEC adopted new rules related to modernizing reserve
calculation and disclosure requirements for oil and gas companies, which became
effective prospectively for annual reporting periods ending on or after December
31, 2009. In addition to expanding the definition and disclosure requirements
for crude oil and natural gas reserves, the new rule changes the requirements
for determining quantities of crude oil and natural gas reserves. The new rule
also changes certain accounting requirements under the full cost method of
accounting for oil and gas activities. The amendments are designed to modernize
the requirements for the determination of crude oil and natural gas reserves,
aligning them with current practices and updating them for changes in
technology. The effect of applying the un-weighted arithmetic average of the
first-day-of-the-month commodity prices for the preceding 12-month period,
compared to the use of end-of-period prices and costs, decreased net proved
reserves by 10.7%. The standardized measure of discounted future net cash flows
for the year ended December 31, 2009 was lower by $888,180 as a result of using
the new rule as compared to amounts calculated using the previous rules. The
effect of applying the new rule resulted in additional depletion expense of
$7,480 and additional impairment expense of $197.





Accounting
Standards Codification




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


19


Fair
Value Measurement of Liabilities





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





Subsequent
Events





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





Recognition
and Presentation of Other-Than-Temporary Impairments





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





Interim
Reporting of Fair Value of Financial Instruments





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





Overview





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.


20


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 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 has drilled twenty-two
developmental and seven exploratory wells on these prospects as of December 31,
2009. Three wells were drilled during 2006, twenty-two were drilled during 2007,
and four were drilled during 2008. The Partnership drilled eleven successful
developmental wells, all of which are currently productive, and eleven
unsuccessful developmental wells. The Partnership drilled 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, 2009, 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 during 2009.





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 $305,527 at December 31, 2009. 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, 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.


21





The
Partnership’s year-end reserve report utilizes the un-weighted 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 $61.08 per barrel of crude 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 from this well during the fourth
quarter.





Lease
operating expenses decreased from $503,416 during the year ended December 31,
2008 to $231,022 during the year ended December 31, 2009, primarily due to the
Sand Dunes prospect, which incurred higher operating costs during 2008 due to
the costs of electricity, salt water disposal, equipment rental, and sub-surface
repairs and maintenance during the testing of the Sand Dunes wells in
2008.  In addition, 2008 production costs were impacted by the
expensed workover costs incurred to change bottom hole pumps on three
Partnership wells.   As a result of shutting in the eight Sand
Dunes wells in February 2009, lease operating costs declined from comparable
levels during 2008.





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.





The rapid
decline in crude oil and natural gas prices that occurred during the first half
of 2009 and the 2009 impairment of proved properties caused the Partnership to
have an overall net loss for 2009.  Due to rising average prices,
however, the Partnership had net income of $223,539 during the fourth quarter of
2009.  Average sales prices during the first quarter of 2010 have
continued to increase from 2009 levels. The Partnership expects that it will
continue to generate net income in 2010.





Year
ended December 31, 2008 compared to Year Ended December 31, 2007





During
2008, the Partnership incurred a net loss of $3,968,996, compared to a net loss
of $10,351,513 incurred during 2007. During 2008, the final successful
Partnership well began production operations in May. In addition, the
Partnership had a significant discovery which began production operations during
September 2007. Primarily as a result of these two successful wells, crude oil
and natural gas sales volumes increased during 2008 by 14.3% and 172.3%,
respectively. Average prices received from the sale of crude oil and natural gas
also increased by 26.1% and 12.1%, respectively. As a result of these two
factors, the cash flow from crude oil and natural gas sales revenues, less
operating expenses and production taxes, increased from $1,285,981 in 2007 to
$2,182,337 in 2008.


22


Impairment
expense totaled $10,937,537 during 2007. During the first half of 2007, the
Partnership recorded property impairment expense of $4,424,296 as a result of
the drilling of four unsuccessful wells. During the second half of 2007, the
Partnership drilled one additional unsuccessful well. In addition, the
Partnership reduced the estimated reserves it expects to recover from the eight
successful Cole Ranch prospect wells located in Glasscock County, Texas because
peak production from the wells was less than originally anticipated, leading to
an additional $6,315,241 of property impairment expense taken during the fourth
quarter of 2007. In comparison, property impairment expense for 2008 totaled
$4,290,665. Of this amount, $172,447 was impairment of unproved property
relating to the Partnership’s Sand Dunes prospect, and $4,118,218 was impairment
of proved properties. The entire $4,118,218 impairment of proved properties
resulted from a ceiling test writedown (see Note 2 to the Partnership’s
financial statements). The Partnership’s year-end reserve report utilizes
current year end prices and 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 $44.60 per barrel of oil and $5.71 per MCF of
natural gas at December 31, 2008, compared to $89.16 per barrel of oil and
$7.207 per MCF of natural gas at December 31, 2007.  The lower 2008
year-end prices directly affect the estimated economic lives and, therefore,
estimated reserves recoverable from Partnership wells. At December 31, 2008, the
estimated discounted future net cash flows of the Partnership totaled
$2,297,832, compared to $7,199,362 at December 31, 2007. The Partnership
recorded property impairment expense of proved properties totaling $4,118,218 in
order to reduce the proved property amount shown on the accompanying balance
sheet at December 31, 2008 to the estimated discounted future net cash flow from
wells at December 31, 2008.





As
production and sales volumes from the eight Cole Ranch wells have decreased,
operating costs on a barrels of oil equivalent (BOE) basis have risen, since
operating costs tend to increase as a property ages and production tends to
decline. During the year ended December 31, 2008, total production expenses for
all wells averaged $17.89 per BOE produced compared to $10.51 per BOE produced
during 2007.  The decline rate attributable to the eight Cole Ranch
wells has slowed significantly; however, the Partnership expects that natural
declines in production will cause 2009 quarterly sales volumes to begin to trend
downward from the level achieved during the fourth quarter of 2008, and that
operating costs per BOE will slowly increase.





During
2008, two Partnership wells accounted for 56.5% of Partnership crude oil and
natural gas sales revenues, and these two wells account for 85.0% of total
Partnership reserves at December 31, 2008.





General
and administrative costs increased from $135,603 in 2007 to $456,589 in 2008 as
a result of two primary factors. Reef implemented a new method for allocating
overhead that takes actual overhead and allocates it based upon the summation of
revenues, expenses, and capital costs incurred. Under the prior method of
allocating overhead, not all allocable general and administrative expenses were
charged to the Partnership during 2007. In addition, during the fourth quarter
expenses were incurred in connection with Sarbanes-Oxley compliance and
improvement of financial reporting. The Partnership expects to have continuing
costs during 2009 related to Sarbanes-Oxley compliance, as the Partnership is
required to be Sarbanes-Oxley compliant by December 31, 2009. Third party costs
in connection with improvement of financial reporting ended during January
2009.  The administrative overhead charge to the Partnership for the
year ended December 31, 2008 was $279,926, compared to $57,221 for the year
ended December 31, 2007.





The rapid
decline in crude oil and natural gas prices that occurred during the fourth
quarter of 2008, the impairment of proved properties and unproved properties,
and the significant increase in general and administrative costs incurred during
the fourth quarter of 2008 caused the Partnership’s to have a net loss of
$4,689,851for the fourth quarter. RELP and Reef are working to cut overhead
costs, and even with costs in connection with Sarbanes-Oxley compliance, the
Partnership expects to incur overall lower general and administrative costs
during 2009. Average sales prices during the first quarter of 2009 will continue
to decline from fourth quarter 2008 levels. The Partnership expects that prior
to depletion expense and any possible impairment charges it will continue to
generate net income. Nonetheless, 2009 results are expected to decline
significantly from 2008 results.





Off-Balance
Sheet Arrangements





The
Partnership does not participate in transactions that generate relationships
with unconsolidated entities or financial partnerships, such as entities often
referred to as structure finance or special purpose entities (SPEs), which would
have been established for the purpose of facilitating off-balance sheet
arrangements or other contractually narrow or limited purposes.  As of
December 31, 2009, 2008, and 2007 the Partnership was not involved in any
unconsolidated SPE transactions or any other off-balance sheet
arrangements.


23





Contractual
Obligations Table





Payment due by periodContractual
                      obligations
                    
                    Total
                    
                    
                    Less than 1
                      Year
                    
                    
                    1-3 Years
                    
                    
                    3-5 years
                    
                    
                    More than 5
                      YearsPurchase
      obligations *
                    
                    $
                    70,096
                    
                    
                    $
                    70,096
                    
                    
                    
                    —
                    
                    
                    
                    —
                    
                    
                    
                    —





* The 15%
management fee due Reef for organization and offering costs, including sales
commissions, is payable in two parts. Reef initially received an amount, not to
exceed 13.5%, to recover actual commissions and organization and offering costs.
As of December 31, 2009, the Partnership is obligated to pay Reef $70,096
representing the portion of the management fee in excess of actual commissions
and organization and offering costs, from the oil and gas cash flows available
for partner distributions at a rate not to exceed $1 million per year. The
Partnership completed payment of the remaining balance due in February
2010.





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.





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, 2009, a 10%
change in the price received for our crude oil would have had an approximate
$82,600 impact on our crude oil revenues, and a 10% change in the price received
for our natural gas would have had an approximate $59,700 impact on our natural
gas revenues.





ITEM
      8.
            
            FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA





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





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





None.


24




ITEM
      9A(T).
            
            CONTROLS
      AND PROCEDURES





Evaluation
of Disclosure Controls and Procedures





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





Management
Report on Internal Control Over Financial Reporting





Management
of the Partnership is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange
Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness
of our internal control over financial reporting based on the framework in
Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation under the
framework in Internal Control – Integrated Framework, management of the
Partnership concluded that the Partnership’s internal control over financial
reporting was effective as of December 31, 2009.





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





Changes
in Internal Controls





There
have not been any changes in the Partnership’s internal controls over financial
reporting during the fiscal quarter ended December 31, 2009 that have materially
affected, or are reasonably likely to materially affect, the Partnership’s
internal control over financial reporting.





ITEM
      9B.
            
            OTHER
      INFORMATION





None.





PART
III





ITEM
      10.
            
            DIRECTORS,
      EXECUTIVE OFFICERS, AND CORPORATE
GOVERNANCE





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





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





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


25





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





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





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





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





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





Daniel
C. Sibleybecame 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.


26


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





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





Audit
Committee and Nominating Committee





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





Code
of Ethics





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





ITEM
      11.
            
            EXECUTIVE
      COMPENSATION





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





Recipient
            
            Form of Compensation
            
            AmountManaging
      General Partner
            
            Partnership
      interest (excluding any partnership interest resulting from the purchase
      of units)
            
            10%
      interestManaging
      General Partner
            
            Management
      fee
            
            15%
      of subscriptionsManaging
      General Partner and its Affiliates
            
            Direct
      and administrative costs
            
            Reimbursement
      at costAffiliate
      of the Managing General Partner
            
            Operator's
      per-well charges
            
            Competitive
      pricesManaging
      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%.


27





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, $655,000 has been paid to Reef from net cash flow, and $70,096 has been
accrued at December 31, 2009 as an account payable to be paid to Reef from
future net cash flows of the Partnership. The Partnership completed payment of
the balance in February 2010.





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, 2009, 2008 and 2007, the Partnership reimbursed Reef $1,207,
$58,114, $945,521, respectively, for technical services costs which have been
capitalized as project costs, and $213,974, $279,926, and $57,221, 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, 2009, 2008 and 2007, the Partnership paid operator fees
totaling $44,473, $40,879, and $51,700 to RELP. RELP serves as operator for five
Partnership prospects upon which nine successful and ten unsuccessful wells have
been drilled, including the eight Sand Dunes wells classified as unsuccessful
that have not yet been plugged and abandoned.





Compensation
Committee





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





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





The
following table sets forth information as of December 31, 2009 concerning all
persons known by Reef to own beneficially more than 5% of the interests in the
Partnership. Unless expressly indicated otherwise, each partner exercises sole
voting and investment power with respect to the units beneficially
owned.





Person or Group
                  
                  Number of Units
                    Beneficially
                    Owned
                  
                  
                  Percent of Total
                    Partnership Units
                    Outstanding
                  
                  
                  Percentage of
                    Total Partnership
                    Interests
                    Beneficially
                    OwnedReef
      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% 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.


28





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





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





ITEM
      14.
            
            PRINCIPAL
      ACCOUNTANT FEES AND SERVICES





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





2009
                  
                  
                  2008Audit
      fees
                  
                  $
                  48,825
                  
                  
                  $
                  48,593Audit
      related fees
                  
                  
                  —
                  
                  
                  
                  —Tax  fees
                  
                  
                  —
                  
                  
                  
                  3,701All
      other fees
                  
                  
                  —
                  
                  
                  
                  —





Tax fees
are for review of the Partnership’s tax return.





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 StatementsReport
      of Independent Registered Public Accounting Firm
                          F-1Balance
      Sheets
                          F-2Statements
      of Operations
                          F-3Statements
      of Partnership Equity
                          F-4Statements
      of Cash Flows
                          F-5Notes
      to Financial Statements
                          F-62.
      Financial Statement Schedules
                          None3.
      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.


29


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:   April
      2, 2010
              REEF
      GLOBAL ENERGY VII, L.P.Reef
      Oil & Gas Partners, L.P.Managing
      General PartnerBy:
              Reef
      Oil & Gas Partners, GP, LLCBy:
              /s/ Michael
      J. MauceliMichael
      J. MauceliManager
      (principal executive
      officer)


30





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




Signature
            
            Title
            
            Date/s/ Michael
      J. Mauceli
            
            Manager
      and Member of the general partner of Reef
            
            April
      2, 2010Michael
      J. Mauceli
            
            Oil
      & Gas Partners, L.P. (principal
      executive officer)/s/ Daniel
      C. Sibley
            
            Chief
      Financial Officer
            
            April
      2, 2010Daniel
      C. Sibley
            
            Reef
      Exploration, L.P.(principal
      financial and accounting officer)


31


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 FileNo.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
      theReport on Form 10-K of Reef
      Global Energy Ventures as filed with the SEC on March 5,
      2002).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.










32


Reef
Global Energy VII, L.P.





Financial
Statements





Years
Ended December 31, 2009, 2008, and 2007




Contents





Report
      of Independent Registered Public Accounting Firm
              F-1Audited
      Financial StatementsBalance
      sheets
              F-2Statements
      of operations
              F-3Statements
      of partnership equity
              F-4Statements
      of cash flows
              F-5Notes
      to financial statements
              F-6





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, 2009 and 2008, and the related statements of operations,
partnership equity, and cash flows for each of the three years in the period
ended December 31, 2009. 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, 2009 and 2008, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2009, in conformity
with accounting principles generally accepted in the United States of
America.





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





BDO
Seidman, LLP





Dallas,
Texas


April 2,
2010


F-1


Reef
Global Energy VII, L.P.


Balance
Sheets





December 31,
                    
                    2009
                    
                    
                    2008AssetsCurrent
      assets:Cash
      and cash equivalents
                    
                    $
                    63,432
                    
                    
                    $
                    444,655Accounts
      receivable
                    
                    
                    3,471
                    
                    
                    
                    3,015Accounts
      receivable from affiliates
                    
                    
                    314,397
                    
                    
                    
                    —Total
      current assets
                    
                    
                    381,300
                    
                    
                    
                    447,670Oil
      and gas properties, full cost method of accounting:Proved
      properties, net of accumulated depletion of $20,279,005 and
      $19,105,539
                    
                    
                    1,323,360
                    
                    
                    
                    2,297,832Net
      oil and gas properties
                    
                    
                    1,323,360
                    
                    
                    
                    2,297,832Total
      assets
                    
                    $
                    1,704,660
                    
                    
                    $
                    2,745,502Liabilities
      and partnership equityCurrent
      liabilities:Accounts
      payable
                    
                    
                    5,677
                    
                    
                    
                    537Accounts
      payable to affiliates
                    
                    
                    70,096
                    
                    
                    
                    650,339Total
      current liabilities
                    
                    
                    75,773
                    
                    
                    
                    650,876Long-term
      liabilities:Asset
      retirement obligation
                    
                    
                    289,494
                    
                    
                    
                    270,772Accounts
      payable to affiliates
                    
                    
                    —
                    
                    
                    
                    70,096Total
      long-term liabilities
                    
                    
                    289,494
                    
                    
                    
                    340,868Commitments
      and Contingencies (Note 5)Partnership
      equityLimited
      partners
                    
                    
                    1,205,145
                    
                    
                    
                    1,644,959Managing
      general partner
                    
                    
                    134,248
                    
                    
                    
                    108,799Partnership
      equity
                    
                    
                    1,339,393
                    
                    
                    
                    1,753,758Total
      liabilities and partnership equity
                    
                    $
                    1,704,660
                    
                    
                    $
                    2,745,502


See
accompanying notes to financial statements.


F-2


Reef
Global Energy VII, L.P.


Statements
of Operations





For the Years Ended December 31,2009
                
                
                2008
                
                
                2007Revenues:
                
                $
                1,417,297
                
                
                
                2,861,452
                
                
                $
                1,517,970Costs
      and expenses:Lease
      operating expenses
                
                
                231,022
                
                
                
                503,416
                
                
                
                149,307Production
      taxes
                
                
                78,288
                
                
                
                175,699
                
                
                
                82,682Depreciation,
      depletion and amortization
                
                
                606,787
                
                
                
                1,346,930
                
                
                
                1,075,372Property
      impairment
                
                
                566,679
                
                
                
                4,290,665
                
                
                
                10,739,537Accretion
      of asset retirement obligation
                
                
                18,722
                
                
                
                65,726
                
                
                
                4,643General
      and administrative
                
                
                283,267
                
                
                
                456,589
                
                
                
                135,603Total
      costs and expenses
                
                
                1,784,765
                
                
                
                6,839,025
                
                
                
                12,187,144Loss
      from operations
                
                
                (367,468
                )
                
                
                (3,977,573
                )
                
                
                (10,669,174
                )Interest
      income
                
                
                1,447
                
                
                
                8,577
                
                
                
                317,661Net
      loss
                
                $
                (366,021
                )
                
                
                (3,968,996
                )
                
                $
                (10,351,513
                )Net
      income (loss) per general partner unit
                
                $
                —
                
                
                
                329.01
                
                
                $
                (10,689.32
                )Net
      loss per limited partner unit
                
                $
                (428.66
                )
                
                
                (4,209.61
                )
                
                $
                (10,689.32
                )Net
      income (loss) per managing general partner unit
                
                $
                616.41
                
                
                
                (1,650.23
                )
                
                $
                (9,808.55
                )




See
accompanying notes to financial statements.


F-3


Reef
Global Energy VII, L.P.


Statements
of Partnership Equity





General
      partners
                            
                            
                            Limited
      partners
                            
                            
                            Managing general partner
                            
                            
                            TotalUnits
                            
                            
                            Amount
                            
                            
                            Units
                            
                            
                            Amount
                            
                            
                            Units
                            
                            
                            Amount
                            
                            
                            Units
                            
                            
                            AmountBalance
      at December 31, 2006
                            
                            
                            741.001
                            
                            
                            $
                            14,591,765
                            
                            
                            
                            182.783
                            
                            
                            $
                            3,599,369
                            
                            
                            
                            48.620
                            
                            
                            $
                            1,024,528
                            
                            
                            
                            972.404
                            
                            
                            $
                            19,215,662Partner
      contributions
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            144,544
                            
                            
                            
                            —
                            
                            
                            
                            144,544Partner
      distributions
                            
                            
                            —
                            
                            
                            
                            (1,046,134
                            )
                            
                            
                            —
                            
                            
                            
                            (258,050
                            )
                            
                            
                            —
                            
                            
                            
                            (238,316
                            )
                            
                            
                            —
                            
                            
                            
                            (1,542,500
                            )Net
      income (loss)
                            
                            
                            —
                            
                            
                            
                            (7,920,793
                            )
                            
                            
                            —
                            
                            
                            
                            (1,953,826
                            )
                            
                            
                            —
                            
                            
                            
                            (476,894
                            )
                            
                            
                            —
                            
                            
                            
                            (10,351,513
                            )Balance
      at December 31, 2007
                            
                            
                            741.001
                            
                            
                            
                            5,624,838
                            
                            
                            
                            182.783
                            
                            
                            
                            1,387,493
                            
                            
                            
                            48.620
                            
                            
                            
                            453,862
                            
                            
                            
                            972.404
                            
                            
                            
                            7,466,193Distribution
      amount per partnership unit
                            
                            
                            
                            
                            
                            $
                            1,411.78
                            
                            
                            
                            
                            
                            
                            $
                            1,411.78
                            
                            
                            
                            
                            
                            
                            $
                            4,901.60Balance
      at December 31, 2007
                            
                            
                            741.001
                            
                            
                            
                            5,624,838
                            
                            
                            
                            182.783
                            
                            
                            
                            1,387,493
                            
                            
                            
                            48.620
                            
                            
                            
                            453,862
                            
                            
                            
                            972.404
                            
                            
                            
                            7,466,193Partner
      contributions
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            5,361
                            
                            
                            
                            —
                            
                            
                            
                            5,361Partner
      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
                            
                            
                            $
                            1,753,758Distribution
      amount per partnership unit
                            
                            
                            
                            
                            
                            $
                            703.38
                            
                            
                            
                            
                            
                            
                            $
                            1,600.61
                            
                            
                            
                            
                            
                            
                            $
                            5,557.18Balance
      at December 31, 2008
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            923.784
                            
                            
                            
                            1,644,959
                            
                            
                            
                            48.620
                            
                            
                            
                            108,799
                            
                            
                            
                            972.404
                            
                            
                            
                            1,753,758Partner
      contributions
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            —
                            
                            
                            
                            3,440
                            
                            
                            
                            —
                            
                            
                            
                            3,440Partner
      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
                            
                            
                            $
                            1,339,393Distribution
      amount per partnership unit
                            
                            
                            
                            
                            
                            $
                            —
                            
                            
                            
                            
                            
                            
                            $
                            47.44
                            
                            
                            
                            
                            
                            
                            $
                            163.73


See
accompanying notes to financial statements.


F-4


Reef
Global Energy VII, L.P.


Statements
of Cash Flows





For the Years Ended December 31,2009
                
                
                2008
                
                
                2007Operating
      ActivitiesNet
      loss
                
                $
                (366,021
                )
                
                
                (3,968,996
                )
                
                $
                (10,351,513
                )Adjustments
      to reconcile net loss to net cashprovided
      by operating activities:Adjustments
      for non-cash transactions:Depreciation,
      depletion and amortization
                
                
                606,787
                
                
                
                1,346,930
                
                
                
                1,075,372Property
      impairment
                
                
                566,679
                
                
                
                4,290,665
                
                
                
                10,739,537Accretion
      of asset retirement obligation
                
                
                18,722
                
                
                
                65,726
                
                
                
                4,643Changes
      in operating assets and liabilities:Accounts
      receivable
                
                
                (456
                )
                
                
                (3,015
                )
                
                
                —Accounts
      receivable from affiliates
                
                
                (314,397
                )
                
                
                —
                
                
                
                —Accounts
      payable
                
                
                5,140
                
                
                
                537
                
                
                
                —Accounts
      payable to affiliates
                
                
                (290,339
                )
                
                
                246,646
                
                
                
                21,118Net
      cash provided by operating activities
                
                
                226,115
                
                
                
                1,978,493
                
                
                
                1,489,157Investing
      ActivitiesProperty
      acquisition and development
                
                
                (198,994
                )
                
                
                (732,983
                )
                
                
                (13,162,379
                )Net
      cash used in investing activities
                
                
                (198,994
                )
                
                
                (732,983
                )
                
                
                (13,162,379
                )Financing
      ActivitiesPartner
      capital contributions
                
                
                3,440
                
                
                
                16,330
                
                
                
                174,012Offering
      costs
                
                
                (360,000
                )
                
                
                (330,000
                )
                
                
                (268,014
                )Partner
      distributions
                
                
                (51,784
                )
                
                
                (1,748,800
                )
                
                
                (1,542,500
                )Net
      cash used in financing activities
                
                
                (408,344
                )
                
                
                (2,062,470
                )
                
                
                (1,636,502
                )Net
      decrease in cash and cash equivalents
                
                
                (381,223
                )
                
                
                (816,960
                )
                
                
                (13,309,724
                )Cash
      and cash equivalents at beginning of period
                
                
                444,655
                
                
                
                1,261,615
                
                
                
                14,571,339Cash
      and cash equivalents at end of period
                
                $
                63,432
                
                
                
                444,655
                
                
                $
                1,261,615Non-cash
      investing transactionsProperty
      additions included in accounts payable to affiliates
                
                $
                —
                
                
                $
                22,575
                
                
                $
                247,610Property
      additions and asset retirement obligation
                
                $
                —
                
                
                $
                79,341
                
                
                $
                121,062Non-cash
      financing transactions:Managing
      partner contributions included in accounts receivable from
      affiliates
                
                $
                —
                
                
                $
                —
                
                
                $
                10,969Offering
      costs included in accounts payable to affiliates
                
                $
                70,096
                
                
                $
                360,000
                
                
                $
                330,000Offering
      costs included in non-current accounts payable to
    affiliates
                
                $
                —
                
                
                $
                70,096
                
                
                $
                430,096


See
accompanying notes to financial statements.





F-5




Reef
Global Energy VII, L.P.


Notes to
Financial Statements





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.





Pursuant
to the Partnership Agreement of the Partnership, all general partner units held
by investors other than the managing general partner were converted into limited
partner units. This conversion of general partner 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, and all income and expense items subsequent to the second
quarter of 2008 have been allocated between the managing general partner and the
limited partners.





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 partner 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.





2.
Summary of Accounting Policies





Use
of Estimates





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


F-6


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





Cash
and Cash Equivalents





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





Risks
and Uncertainties





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





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





Crude
Oil and Natural Gas Properties





The
Partnership follows the full cost method of accounting for 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, 2009, the Partnership performs a
quarterly ceiling test on the capitalized costs of oil and gas properties,
whereby the capitalized costs of oil and gas properties are limited to the sum
of the estimated future net revenues from proved reserves using prices that are
the 12-month un-weighted arithmetic average of the first-day-of-the-month price
for crude oil and natural gas held constant and discounted at 10%, plus the
lower of cost or estimated fair value of unproved properties, if any, for 2009.
If capitalized costs exceed the ceiling, an impairment loss is recognized for
the amount by which the capitalized costs exceed the ceiling, and is shown as a
reduction of oil and gas properties and as property impairment expense on the
Partnership’s statements of operations. No gain or loss is recognized upon sale
or disposition of crude oil and natural gas properties, unless such a sale would
significantly alter the rate of depletion and amortization. During the years
ended December 31, 2009, 2008 and 2007, the Partnership recognized property
impairment expense of proved properties totaling $566,679, $4,118,218, and
$10,739,537, respectively.





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.





Estimates
of Proved Oil and Gas Reserves





Estimates
of the Partnership’s proved reserves at December 31, 2009 have been prepared and
presented in accordance with new SEC rules and accounting standards. These new
rules are effective for fiscal years ending on or after December 31, 2009, and
require SEC reporting entities to prepare their reserve estimates using revised
reserve definitions and revised pricing based upon the un-weighted arithmetic
average of the first-day-of-the-month commodity prices over the preceding
12-month period and current costs. Estimates of the Partnership’s proved
reserves at December 31, 2008 and 2007 have been prepared and presented using
previous SEC rules and accounting standards that required pricing based upon
end-of-period commodity prices and costs. Future prices and costs may be
materially higher or lower than these prices and costs, which would impact the
estimate of reserves and future cash flows. Our proved reserve information
included in this report was based upon evaluations prepared by independent
petroleum engineers.


F-7


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





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.





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.





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




2009
                  
                  
                  2008Beginning
      asset retirement obligation
                  
                  $
                  270,772
                  
                  
                  $
                  125,705Additions
      related to new properties
                  
                  
                  —
                  
                  
                  
                  79,341Accretion
      expense
                  
                  
                  18,722
                  
                  
                  
                  65,726Ending
      asset retirement obligation
                  
                  $
                  289,494
                  
                  
                  $
                  270,772





Recognition
of Revenue





The
Partnership enters into sales contracts for disposition of its share of crude
oil and natural gas production from productive wells. Revenues are recognized
based upon the Partnership’s share of metered volumes delivered to its
purchasers each month. The Partnership had no material gas imbalances at
December 31, 2009, 2008, and 2007.





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.


F-8


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





As of
December 31, 2009, the tax basis of the Partnership’s assets exceeds the
financial reporting basis of the assets by approximately $4.69 million,
primarily due to the difference between property impairment costs deducted for
financial reporting purposes and intangible drilling costs deducted for income
tax purposes.





Accounting
for Uncertainty in Income Taxes





FASB
provides guidance on accounting for uncertainty in income taxes. This guidance
is intended to clarify the accounting for uncertainty in income taxes recognized
in a company’s financial statements and prescribes the recognition and
measurement of a tax position taken or expected to be taken in a tax return. It
also provides guidance on de-recognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition.





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





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





Based on
the Partnership’s assessment, there are no material uncertain tax positions as
of December 31, 2009.





Fair
Value of Financial Instruments





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





Recently
Adopted Accounting Pronouncements





Modernization
of Oil and Gas Reporting





In
January 2009, the SEC adopted new rules related to modernizing reserve
calculation and disclosure requirements for oil and gas companies, which became
effective prospectively for annual reporting periods ending on or after December
31, 2009. In addition to expanding the definition and disclosure requirements
for crude oil and natural gas reserves, the new rule changes the requirements
for determining quantities of crude oil and natural gas reserves. The new rule
requires disclosure of crude oil and natural gas proved reserves by geographical
area, using the un-weighted arithmetic average of first-day-of-the-month
commodity prices over the preceding 12-month period, rather than end-of-period
prices, and allows the use of reliable technologies to estimate proved crude oil
and natural gas reserves, if those technologies have been demonstrated to result
in reliable conclusions about reserve volumes.  In addition, in
January 2010, the FASB issued guidance relating to crude oil and natural gas
reserve estimation and disclosures to provide consistency with the new SEC
rules.  The Partnership adopted the new standards effective December
31, 2009. The new standards are applied prospectively as a change in estimate.
The effect of applying the un-weighted arithmetic average of
first-day-of-the-month commodity prices over the preceding 12-month period,
versus applying the 2009 end-of-period price, decreased net proved reserves by
10.7%. The standardized measure of discounted future net cash flows for the year
ended December 31, 2009 was lower by $888,180 using the new rule as compared to
amounts calculated using the previous rules.  The effect of applying
the new rule resulted in additional depletion expense of $7,480 and additional
impairment expense of $197.


F-9


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





Accounting
Standards Codification




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





Fair
Value Measurement of Liabilities




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





Subsequent
Events





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





Recognition
and Presentation of Other-Than-Temporary Impairments





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





Interim
Reporting of Fair Value of Financial Instruments





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


F-10


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





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, 2009, 2008,
and 2007 the Partnership incurred technical services and administrative costs
totaling $215,181, $338,040, and $1,002,742, respectively. Of these amounts,
$1,207, $58,114, and $945,521 represent technical services costs capitalized as
project costs, and $213,974, $279,926, and $57,221 represent administrative
costs included as general and administrative expenses.





Reef
contributes 1% of all leasehold, drilling, and completion costs when incurred.
During the years ended December 31, 2009, 2008, and 2007, this 1% obligation
totaled $3,440, $5,361, and $144,544. 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, 2009, RELP owed the partnership $314,397 for net
revenues processed in excess of joint interest and technical and administrative
charges.  At December 31, 2008, the Partnership owed RELP $290,339 for
joint interest and technical and administrative charges processed in excess of
net revenues. The Partnership settles its balances with Reef and RELP on a
quarterly basis.





Accounts
payable to affiliates as of December 31, 2009 and 2008 also includes $70,096 and
$430,096, respectively, for the unpaid portion of the 15% management fee due
Reef for organization and offering costs, including sales commissions. The
management fee is payable in two parts. Reef initially received an amount not to
exceed 13.5% to recover actual commissions and organization and offering costs.
The remaining portion of the management fee is paid to Reef from the oil and gas
cash flows available for partner distributions, at a rate not to exceed $1
million per year. During 2009, the Partnership reimbursed $360,000 of this
amount to Reef. The remaining $70,096 has been classified as a short term
liability to affiliates at December 31, 2009, and the Partnership completed
payment of the balance to Reef in February 2010.





If an
affiliate of Reef serves as operator of a Partnership prospect, then operator
fees are payable to the affiliate. Under such circumstances, such affiliate
receives fees at the competitive rate in the geographical area where the
prospect is located during the drilling and production phase of operations.
These fees are charged as a monthly fee per well as agreed to in an operating
agreement signed by the Partnership as well as outside third party working
interest owners in the well. During the years ended December 31, 2009, 2008, and
2007, the Partnership paid operating overhead fees totaling $44,473, $40,879,
and $23,302 to RELP, respectively.





4.
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, 2009, two marketers and one
operator accounted for 33.4%, 39.4%, and 26.9% of the Partnership’s crude oil
and natural gas revenues, respectively.  During the year ended
December 31, 2008, two marketers and one operator accounted for 41.7%, 41.4%,
and 14.9% of the Partnership’s crude oil and natural gas revenues, respectively.
During the year ended December 31, 2007, two marketers accounted for 79.4% and
16.5% 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.




5.
Commitments and Contingencies





The
Partnership is not currently involved in any legal proceedings.




F-11


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)


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
1% of all leasehold, drilling, and completion costs when incurred, in addition
to having paid its pro rata share (4.95%) of the 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,
2009.


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.





7.
Partnership Prospects





As of
December 31, 2009, the Partnership owns working interests in six developmental
prospects and seven exploratory prospects, upon which a total of twenty-nine
wells were drilled with the capital raised by the Partnership.





The
Partnership drilled eleven successful developmental wells and eleven
unsuccessful developmental wells, including the eight Sand Dunes wells described
below. The Partnership drilled one successful exploratory well, and six
unsuccessful exploratory wells. The successful exploratory well ceased
production during 2007.





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
cannot 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 a result, as of
December 31, 2008, the eight Sand Dunes wells were classified as unsuccessful,
and no crude oil and natural gas reserves for these wells were included in the
December 31, 2008 reserve information presented in this Annual
Report.





Beginning
with March 2009, oil sales prices increased from levels below $40 per barrel to
between $60 and $70 per barrel. 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 began in March 2010. Upon conversion of this
well to a salt water disposal well, three of the current Sand Dunes wells are
expected to be placed on full time production during the second quarter of 2010.
RELP believes, based upon testing already performed, that the disposal capacity
of the well to be converted will be such that only three Sand Dunes wells can be
placed on full time production. However, if possible, additional wells may be
placed on production. RELP will determine what actions to take regarding the
other Sand Dunes wells after a period of evaluation of this initial conversion.
The estimated cost of the well conversion to this Partnership is expected to be
approximately $89,200 (unaudited).  This cost will be paid for by the
Partnership by retaining a portion of the funds normally paid out in
distributions to the partners. There are 6,000 BBL of crude oil and 9,930 MCF of
natural gas reserves (unaudited) for the three wells expected to be placed on
full time production included in the December 31, 2009 reserve information
presented in this Annual Report.


F-12


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





The
Partnership also has unproved property consisting of un-drilled leasehold
interest (11 potential drilling locations) in the Sand Dunes prospect. The
Partnership has fully impaired this unproved property during the fourth quarter
of 2008 based upon the eight already drilled wells being classified as
unsuccessful at December 31, 2008. The Partnership currently has no plans to
conduct any drilling operations on this acreage.





8.
Supplemental Information on Oil & Natural Gas Exploration and Production
Activities


(unaudited)





Capitalized
Costs





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





December
      31,
                
                2009
                
                
                2008
                
                
                2007Oil
      and natural gas properties:Unproved
      properties
                
                $
                —
                
                
                $
                —
                
                
                $
                172,447Proved
      properties
                
                
                21,602,365
                
                
                
                21,403,371
                
                
                
                20,816,08221,602,365
                
                
                
                21,403,371
                
                
                
                20,988,529Less:Accumulated
      depreciation, depletion and amortization
                
                
                (3,029,089
                )
                
                
                (2,422,302
                )
                
                
                (1,075,372
                )Property
      impairment
                
                
                (17,249,916
                )
                
                
                (16,683,237
                )
                
                
                (12,565,019
                )Total
                
                $
                1,323,360
                
                
                $
                2,297,832
                
                
                $
                7,348,138





Costs
Incurred





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





2009
                
                
                2008
                
                
                2007Oil
      and natural gas properties:Exploration
                
                $
                59,641
                
                
                $
                (134,657
                )
                
                $
                3,691,736Development
                
                
                137,621
                
                
                
                721,946
                
                
                
                12,260,062Total
                
                $
                197,262
                
                
                $
                587,289
                
                
                $
                15,951,798





Results
of Operations





The
following table sets forth results of operations from oil and gas producing
activities for the years ended December 31, 2009, 2008, and 2007.


2009
                
                
                2008
                
                
                2007Oil
      and gas producing activities:Oil
      sales
                
                $
                827,273
                
                
                $
                1,590,912
                
                
                $
                1,102,915Natural
      gas sales
                
                
                590,024
                
                
                
                1,270,540
                
                
                
                415,055Production
      expenses
                
                
                (309,310
                )
                
                
                (679,115
                )
                
                
                (231,989
                )Accretion
      of asset retirement obligation
                
                
                (18,722
                )
                
                
                (65,726
                )
                
                
                (4,643
                )Depreciation
      , depletion and amortization
                
                
                (606,787
                )
                
                
                (1,346,930
                )
                
                
                (1,075,372
                )Property
      impairment expense
                
                
                (566,679
                )
                
                
                (4,118,218
                )
                
                
                (10,739,537
                )Results
      of operations from producing activities
                
                $
                (84,201
                )
                
                $
                (3,348,537
                )
                
                $
                (10,533,571
                )Depletion
      rate per BOE
                
                $
                15.70
                
                
                $
                35.48
                
                
                $
                48.70


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


F-13


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





Crude
Oil and Natural Gas Reserves





Recent
SEC and FASB Rule Making Activity





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





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





The new
rules resulted in the use of lower prices at December 31, 2009 for both crude
oil and natural gas than would have been used under the previous rules, and
resulted in a downward adjustment of approximately 8,770 BOE to our proved
reserves as of December 31, 2009, as compared to the old end-of-period prices
rule.





Net
Proved Developed Reserve Summary





The
reserve information presented below is based upon estimates of net proved
reserves that were prepared by the independent petroleum engineering firms
Forrest A. Garb & Associates, Inc., as of December 31, 2009, and by Gleason
Engineering as of December 31, 2008 and 2007.   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 December 31, 2009, all
of the Partnership’s reserves are classified as proved developed
reserves.  All of the Partnership’s reserves are located in the United
States.





The
following table sets forth changes in estimated net proved developed crude oil
and natural gas reserves for the years ended December 31, 2009, 2008, and
2007.





Oil
                        (BBL) (1)
                      
                      
                      Gas
                        (mcf)
                      
                      
                      BOE (2)Net
      proved reserves for properties owned by the PartnershipReserves
      at December 31, 2006
                      
                      
                      —
                      
                      
                      
                      —
                      
                      
                      
                      —New
      discoveries
                      
                      
                      110,903
                      
                      
                      
                      804,018
                      
                      
                      
                      244,906Production
                      
                      
                      (14,032
                      )
                      
                      
                      (48,301
                      )
                      
                      
                      (22,082
                      )Reserves
      at December 31, 2007
                      
                      
                      96,871
                      
                      
                      
                      755,717
                      
                      
                      
                      222,824Revisions
      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
                      
                      
                      
                      100,413Revisions
      of previous estimates
                      
                      
                      23,517
                      
                      
                      
                      (73,479
                      )
                      
                      
                      11,270Production
                      
                      
                      (15,200
                      )
                      
                      
                      (140,623
                      )
                      
                      
                      (38,637
                      )Reserves
      at December 31, 2009
                      
                      
                      41,710
                      
                      
                      
                      188,020
                      
                      
                      
                      73,046





(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.


F-14


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





Standardized
Measure of Discounted Future Net Cash Flows





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




For the
year ended December 31, 2009, future cash inflows are computed by applying the
new SEC pricing, which holds constant the 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, 2009, calculations were made using
average prices of $61.08 per barrel of crude oil and $3.83 per MCF of natural
gas. For the years ending December 31, 2008 and 2007, 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 $44.60 per barrel of oil and $5.71 per MCF of
natural gas.  During 2007, the calculations were made using average
prices of $89.16 per barrel of oil and $7.21 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 present worth. Further, actual future net cash flows will be affected by
factors such as the amount and timing of actual production, supply and demand
for crude oil and natural gas, and changes in governmental regulations and tax
rates. Sales prices of both crude oil and natural gas have fluctuated
significantly in recent years. Reef, as managing general partner, does not rely
upon the following information in making investment and operating decisions for
the Partnership.





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





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





December 31,
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Crude
      oil and natural gas properties owned by the Partnership:Future
      cash inflows
                  
                  $
                  3,245,780
                  
                  
                  $
                  3,959,364
                  
                  
                  $
                  13,857,388Future
      production costs
                  
                  
                  (1,600,550
                  )
                  
                  
                  (1,217,470
                  )
                  
                  
                  (4,277,881
                  )Future
      development costs
                  
                  
                  (89,200
                  )
                  
                  
                  —
                  
                  
                  
                  (274,087
                  )Future
      net cash flows
                  
                  
                  1,556,030
                  
                  
                  
                  2,741,894
                  
                  
                  
                  9,305,420Effect
      of discounting net cash flows at 10%
                  
                  
                  (232,670
                  )
                  
                  
                  (444,062
                  )
                  
                  
                  (2,106,058
                  )Discounted
      future net cash flows
                  
                  $
                  1,323,360
                  
                  
                  $
                  2,297,832
                  
                  
                  $
                  7,199,362


F-15


Reef
Global Energy VII, L.P.


Notes to
Financial Statements (continued)





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





December 31,
                  
                  2009
                  
                  
                  2008
                  
                  
                  2007Crude
      oil and natural gas properties owned by the Partnership:Standardized
      measure at beginning of period
                  
                  $
                  2,297,832
                  
                  
                  $
                  7,199,362
                  
                  
                  $
                  —Extensions
      and discoveries
                  
                  
                  
                  
                  
                  
                  —
                  
                  
                  
                  8,480,700Net
      change in sales price, net of production costs
                  
                  
                  (240,994
                  )
                  
                  
                  (1,471,634
                  )
                  
                  
                  —Revisions
      of quantity estimates
                  
                  
                  215,897
                  
                  
                  
                  (1,932,472
                  )
                  
                  
                  —Net
      changes in estimated future development costs
                  
                  
                  (75,862
                  )
                  
                  
                  (42,183
                  )
                  
                  
                  —Changes
      in production timing rates
                  
                  
                  (14,031
                  )
                  
                  
                  (58,566
                  )
                  
                  
                  —Accretion
      of discount
                  
                  
                  229,783
                  
                  
                  
                  719,936
                  
                  
                  
                  —Sales
      net of production costs
                  
                  
                  (1,089,265
                  )
                  
                  
                  (2,116,611
                  )
                  
                  
                  (1,281,338
                  )Net
      increase (decrease)
                  
                  
                  (974,472
                  )
                  
                  
                  (4,901,530
                  )
                  
                  
                  7,199,362Standardized
      measure at end of year
                  
                  $
                  1,323,360
                  
                  
                  $
                  2,297,832
                  
                  
                  $
                  7,199,362





9.
Supplementary Quarterly Financial Data (Unaudited)





Year ended December 31,
                  2008
                
                1st Qtr
                
                
                2nd Qtr
                
                
                3rd Qtr
                
                
                4th Qtr
                
                
                TotalsRevenues
                
                $
                663,141
                
                
                $
                913,165
                
                
                $
                788,934
                
                
                $
                496,212
                
                
                $
                2,861,452Income
      (loss) from operations
                
                
                97,056
                
                
                
                319,841
                
                
                
                295,956
                
                
                
                (4,690,426
                )
                
                
                (3,977,573
                )Net
      income (loss)
                
                
                103,252
                
                
                
                321,102
                
                
                
                296,501
                
                
                
                (4,689,851
                )
                
                
                (3,968,996
                )Net
      income (loss) per managing general partner unit
                
                
                930.03
                
                
                
                1,546.61
                
                
                
                1,547.84
                
                
                
                (5,674.71
                )
                
                
                (1,650.23
                )Net
      income per general partner unit
                
                
                62.82
                
                
                
                266.19
                
                
                
                —
                
                
                
                —
                
                
                
                329.01Net
      income (loss) per limited partner unit
                
                
                62.82
                
                
                
                266.19
                
                
                
                239.49
                
                
                
                (4,778.11
                )
                
                
                (4,209.61
                )





Property
impairment expense included in the 4thquarter
totaled $4,290,665.





Year ended December 31,
                  2009
                
                1st Qtr
                
                
                2nd Qtr
                
                
                3rd Qtr
                
                
                4th Qtr
                
                
                TotalsRevenues
                
                $
                312,574
                
                
                
                366,344
                
                
                
                336,209
                
                
                
                402,170
                
                
                
                1,417,297Income
      (loss) from operations
                
                
                (662,042
                )
                
                
                15,646
                
                
                
                55,478
                
                
                
                223,450
                
                
                
                (367,468
                )Net
      income (loss)
                
                
                (661,111
                )
                
                
                15,960
                
                
                
                55,591
                
                
                
                223,539
                
                
                
                (366,021
                )Net
      income (loss) per managing general partner unit
                
                
                (576.08
                )
                
                
                305.49
                
                
                
                176.65
                
                
                
                710.35
                
                
                
                616.41Net
      income (loss) per limited partner unit
                
                
                (685.34
                )
                
                
                1.20
                
                
                
                50.88
                
                
                
                204.60
                
                
                
                (428.66
                )





Property
impairment expense included in the 1st quarter
totaled $566,482.  Property impairment expense included in the 4th quarter
totaled $197. The fourth quarter information also includes the effects of
applying the new oil and gas rules.  See footnote 2, “Summary of
Accounting Policies,” for more information regarding the new oil and gas
rules.


F-16