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 000-53795





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


(Exact
name of registrant as specified in its charter)





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





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


(Address
of principal executive offices including zip code)





(972)-437-6792


(Registrant’s
telephone number, including area code)





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


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





General and Limited
Partnership Interests


(Title of
Class)





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




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




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




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




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




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





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





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




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




As of
March 31, 2010, the registrant had 490.9827 units of general partner interest
outstanding, 8.9697 units of general partner interest held by the managing
general partner, and 397.0172 units of limited partner interest
outstanding.




Documents
incorporated by reference:  None





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


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


TABLE OF
CONTENTS





Part IItem
      1.
                Business
                3Item
      1A.
                Risk
      Factors
                11Item
      1B.
                Unresolved
      Staff Comments
                16Item
      2.
                Properties
                16Item
      3.
                Legal
      Proceedings
                19Item
      4.
                Reserved
                19PART IIItem
      5.
                Market
      for Registrant’s Common Equity, Related Stockholder Matters and Issuer
      Purchases of Equity Securities
                19Item
      6.
                Selected
      Financial Data
                20Item
      7.
                Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
                21Item
      7A.
                Quantitative
      and Qualitative Disclosure About Market Risk
                27Item
      8.
                Financial
      Statements and Supplementary Data
                28Item
      9.
                Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure
                28Item
      9A(T).
                Controls
      and Procedures
                28Item
      9B.
                Other
      Information
                29PART IIIItem
      10.
                Directors,
      Executive Officers and Corporate Governance
                29Item
      11.
                Executive
      Compensation
                31Item
      12.
                Security
      Ownership of Certain Beneficial Owners and Management and Related
      Stockholder Matters
                34Item
      13.
                Certain
      Relationships and Related Transactions, and Director
      Independence
                34Item
      14.
                Principal
      Accountant Fees and Services
                35PART IVItem
      15.
                Exhibits
      and Financial Statement Schedules
                35Signatures
                36


2


PART
I


ITEM
      1.
              BUSINESS





Introduction





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





The
Partnership purchased a working interest in a producing oil property located in
the Slaughter Field in Cochran County, Texas, approximately 50 miles southwest
of Lubbock, Texas (the "Slaughter Dean Project"), in January
2008.  The Partnership is developing the Slaughter Dean Project as
detailed in the section below entitled “Property Acquisition and
Development”.  On properties purchased by the Partnership, the
Partnership plans to produce existing proved reserves and develop any proved
undeveloped reserves, but does not expect to engage in exploratory drilling for
unproved reserves, should acreage purchased by the Partnership be deemed to
contain unproved drilling locations.  Drilling locations for unproved
reserves, if any, may be farmed out or sold to third parties or other
partnerships formed by Reef.





The
management of the operations and other business of the Partnership is the
responsibility of Reef.  Reef Exploration, L.P., an affiliate of Reef
("RELP"), serves as the operator of the Partnership’s interests in the Slaughter
Dean Project (as more fully described under “Property Acquisition and
Development” below).
This relationship with the Partnership is governed by two operating
agreements.  One operating agreement (the "Sierra-Dean Operating
Agreement") is between the Partnership, RELP and Sierra-Dean Production Company,
LP (referred to herein as "Sierra-Dean" or "Seller").  The other
operating agreement (the "Davric Operating Agreement") is between the
Partnership, RELP and Davric Corporation ("Davric").  For further
information on each of these operating agreements, see "Summary of Material
Contracts – Operating Agreements" below.





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





Property
Acquisition and Development





The
Slaughter Dean Project consists of approximately 6,700 acres and produces from
the San Andres formation at depths from 5,000 to 5,500 feet.  The
major portions of the Slaughter Dean Project were previously unitized for
waterflood operations. The Partnership has utilized waterflood operations in an
attempt to increase production from existing wells and optimize production from
new wells drilled by the Partnership.  The Slaughter Dean Project is
divided into two units and one non-unitized lease known as (i) the Dean Unit,
(ii) the Dean "B" Unit, and (iii) the Dean "K" lease,
respectively.  The Partnership has focused most of its development
activities in the Dean "B" Unit. The Partnership is developing its properties in
the Slaughter Dean Project by drilling and completing new production wells, and
by increasing waterflood injection activity through the drilling and completing
of new waterflood injection wells, restoring inactive waterflood injection wells
and converting marginal producing wells to waterflood injection
wells.


3


In
January 2008, the Partnership purchased an initial 41% working interest from
Sierra-Dean in the Slaughter Dean Project.  Under the terms of the
purchase agreement (the "Slaughter Dean Purchase Agreement"), each month the
Partnership purchases additional working interest based on the amount the
Partnership spends developing the Slaughter Dean Project through January
2013.  In general, the Slaughter Dean Purchase Agreement requires the
Partnership to pay 82% of all drilling, development and repair costs (including
amounts allocable to the 41% working interest initially retained by the Seller),
and the Seller conveys additional working interest to the Partnership each month
as payment of its share of such costs.  See "Summary of Material Contracts
– Slaughter Dean Purchase Agreement" below for additional
information.  In a separate transaction in May 2008, the Partnership
purchased an 11% working interest in the Slaughter Dean Project from another
working interest owner.  See "Summary of Material Contracts
- Davric Assignment" below for additional information.





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





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





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





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





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





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


4


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





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





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





Major
Customers





The
Partnership may sell crude oil and natural gas on credit terms to refiners,
pipelines, marketers, and other users of petroleum commodities. Revenues can be
received directly from these parties or, in certain circumstances, paid to the
operator of the property who disburses to the Partnership its percentage share
of the revenues. Prior to December 31, 2007, the Partnership had no crude oil
and natural gas production and, therefore, had no customers.  During
the years ended December 31, 2009 and 2008, one marketer accounted for all of
the Partnership’s crude oil revenues, and one marketer accounted for all of the
Partnership’s natural gas revenues. During 2008 and 2009, the Partnership’s only
oil and gas property was the Slaughter Dean Project located in Cochran County,
Texas. Reef has chosen to sell the Partnership’s crude oil and natural gas to
two subsidiaries of a large international oil and gas company because of the
amount of payment, the promptness of payment, and their credit worthiness
indicated by their publicly filed financial statements.  There are other
large companies (or subsidiaries thereof) active in purchasing crude oil and
natural gas in the area of the Slaughter Dean Project, including Exxon, Royal
Dutch Shell, Plains All American Pipeline, Conoco-Phillips, Genesis Energy, and
Holly Energy.  There are also several smaller companies that purchase
and re-sell crude oil.  Due to the competitive nature of the market
for purchase of crude oil and natural gas, the Partnership does not believe that
the loss of the current purchaser would have a material adverse impact on the
Partnership.





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





Insurance





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


5


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





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





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





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





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





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





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





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





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





Reef will
notify all non-Reef general partners of the Partnership at least 30 days prior
to any material change in the amount of the Partnership's insurance coverage.
Within this 30-day period, non-Reef general partners have the right to convert
their units into units of limited partnership interest by giving Reef written
notice. Non-Reef general partners will have limited liability as a limited
partner for any Partnership operations conducted after their conversion date,
effective upon the filing of an amendment to the Certificate of Limited
Partnership of the Partnership. At any time during this 30-day period, upon
receipt of the required written notice from the non-Reef general partner of his
intent to convert, Reef will amend the partnership agreement and will file the
amendment with the State of Texas prior to the effective date of the change in
insurance coverage. This amendment to the partnership agreement will effectuate
the conversion of the interest of the former non-Reef general partner to that of
a limited partner. Effecting conversion is subject to the express requirement
that the conversion will not cause a termination of the partnership for federal
income tax purposes. However, even after an election of conversion, a non-Reef
general partner will continue to have unlimited liability regarding partnership
activities while he was a non-Reef general partner.


6


Competition





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





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





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





Markets





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





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


·
            The
      amount of crude oil and natural gas
imports;


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


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


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


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





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





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





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





Governmental
Regulation





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


7


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





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





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





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





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


8


Employees





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





Summary
of Material Contracts





Operating
Agreements.





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





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





Slaughter
Dean Purchase Agreement.





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





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





Subsequent
to its initial purchase of working interests in the Slaughter Dean Project, the
Partnership has acquired substantial additional interests in the Project
pursuant to the Slaughter Dean Purchase Agreement by advancing the funds
necessary to pay the Seller’s share of certain costs.  In effect, the
Partnership pays these costs on behalf of the Seller, and the Seller conveys
additional working interests in the Slaughter Dean project to the
Partnership.  The acquisition of additional working interests in the
Dean Unit and the Dean "B" unit is based upon the following
formula:





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




9


The above
written formula gives the total amount of working interest held by the
Partnership in the two largest units comprising the Slaughter Dean Project, the
Dean Unit and the Dean "B" Unit.  It is recalculated each month based
on the Partnership's expenditures, and the Partnership's working interest is
accordingly adjusted monthly.  As the Partnership develops the
Slaughter Dean Project, its working interest increases and the Seller's working
interest decreases.  To determine the additional working interest
acquired by the Partnership in the Dean "K" Lease, the fraction is multiplied by
100%, instead of 82%.





Davric
Assignment.





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





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





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





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





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





RCWI
Agreement





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





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





Other
Contracts





The
Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN
Associates whereby the Partnership agreed to assign a one percent (1%)
overriding royalty interest, proportionately reduced to the Partnership’s
working interest, to William R. Dixon in exchange for Dixon’s agreement to
“review and evaluate exploration, exploitation, and development drilling
opportunities." This overriding royalty interest burdens the Partnerships
working interest in the Slaughter Dean Field.


10


FORWARD
LOOKING STATEMENTS





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





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





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





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





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





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





·
            any
      statements of other than historical
fact.





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





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





ITEM
      1A.
              RISK
      FACTORS





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


11


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





Although
the Slaughter Dean Project included approximately 70 wells producing or capable
of producing crude oil at the time of the Partnership’s acquisition, the
estimated plan for the development of the Slaughter Dean Project (which has been
adjusted from time to time depending on information learned during the
implementation of the work plan) was to (i) drill a total of approximately 30
new oil wells, (ii) convert approximately 23 of the already-producing oil wells
to waterflood injection wells to support the new, denser waterflood pattern,
(iii) drill approximately 5 new waterflood injection wells, (iv) workover or
clean out approximately 5 of the already-producing wells to improve their
operation, and (v) repair and enhance the pumps and water injection system to
increase its capacity and resume water injection operations.  During
2008, the Partnership (a) drilled 25 new oil wells, (b) drilled 3 new injectors,
and (c) worked over 4 already-producing oil wells.  During 2009, the
Partnership (1) drilled 5 new oil wells, (2) converted 22 oil wells to
waterflood injection wells, (3) drilled 2 new waterflood injection wells, and
(4) worked over 1 already-producing well.  As planned, the work
program has been revised from time to time, and based upon the information
learned through December 31, 2009, RELP and the Partnership have paused in the
drilling of new oil wells while the waterflood operations are completed and
implemented.  As is common with waterflood operations, it can take
many months to determine the effectiveness and results from the implementation
or expansion of a waterflood.





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





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





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





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





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


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





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





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




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




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


12


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





The
Partnership holds title to its interests in the Slaughter Dean Project in its
own name, and it is anticipated that the Partnership will hold any additional
interests in properties it may purchase in the future in its own
name.  Additionally, the Partnership is and will continue to be a
joint working interest owner with other parties.  It has not been
clearly established whether joint working interest owners have several liability
or joint and several liability with respect to obligations relating to the
working interest. Although the operating agreements relating to properties
ordinarily specify that the liabilities of joint working interest owners will be
several, if the Partnership and other working interest owners are determined to
have joint and several liability, the Partnership could be responsible for the
obligations of these other parties relating to the entire working
interest.  The Partnership was advised that Davric, who is unrelated
to Reef and owns a 7% working interest in the Dean Unit and the Dean "B" unit,
was unable to pay immediately $851,129 of its share of the development costs
already incurred as of June 30, 2009.  Davric agreed to pay $100,000
per week toward these costs and has completed payment of the $851,129; however,
as of December 31, 2009, Davric is currently in default for $538,443 of costs
incurred subsequent to June 30, 2009.  If Davric is unable to pay all
of these costs, then pursuant to the Davric Operating Agreement, the Partnership
will be entitled to recover these costs from Davric’s share of future revenues,
plus penalties ranging from 300% to 450% of the amount in
default.  Sierra-Dean, at its option, may pay a pro rata share of the
costs in default and share in the reimbursement and collection of applicable
penalties from future revenues of the Slaughter Dean Project.





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





Reef
estimates that the net proceeds from the sale of units in the Partnership will
be sufficient to finance the Partnership's share of the costs of acquiring
interests in the Slaughter Dean Project, operating existing wells and executing
the revised work plan to conduct waterflood operations, including drilling new
oil wells within the Slaughter Dean Project and providing necessary production
equipment and facilities to service such oil and gas
wells.  Subsequent to December 31, 2009, certain properties were
acquired by the Partnership from RCWI using approximately $13,182,171 out of the
net proceeds remaining. For further information, see “Summary of Material
Contracts – RCWI Agreement” below.  Although there are no plans at
this time to do so, certain costs of operations may also be financed through
partnership borrowings and through utilization of partnership revenues obtained
from production, the sale of producing or non-producing reserves, the sale of
net profits interests or other operating or non-operating interests in
properties, or other methods of financing.  If these methods of
financing should prove to be unavailable or insufficient to maintain the desired
level of operations for the Partnership, operations could be continued through
farmout arrangements with third parties (including affiliated partnerships) or
the sale of net profits interests or other operated or non-operating interests
in properties.  This could result in the Partnership giving up a
substantial interest in crude oil and natural gas reserves.  If the
Partnership sells net profits interests in properties, the Partnership will
incur costs that it cannot recover from the holders of the net profits
interests, except from future revenues, if any, relating to such
properties.  The effect of borrowing or other financing could be to
increase funds available to the Partnership, but also could be to reduce cash
available for distributions to the extent cash is used to repay borrowings, or
to reduce reserves if properties are farmed out or interests in the properties
are sold.





The
Partnership’s insurance coverage may be inadequate.





The
Partnership's operations will be subject to all of the operating risks normally
associated with producing crude oil and natural gas, such as blow-outs and
pollution, which could result in the Partnership incurring substantial
liabilities or losses, although the chance of incurring a blow-out while
drilling new oil wells within a mature waterflood project are believed by Reef
to be small.  Although the Partnership Agreement provides for the
securing of such insurance as Reef deems necessary and appropriate, certain
risks are uninsurable and others may be either uninsured or only partially
insured because of high premium costs or other reasons.  In the event
the Partnership incurs uninsured losses or liabilities, the Partnership's funds
available for Partnership purposes may be substantially reduced or lost
completely, and non-Reef general partners may be jointly and severally liable
for such amounts.


13


Oil
and natural gas investments are risky.





Although
the Partnership will not engage in any exploratory drilling, the acquisition,
development and operation of oil and gas properties, including the Slaughter
Dean Project, is not an exact science and involves a high degree of
risk.  The risks of acquiring and operating producing properties, such
as the Slaughter Dean Project, are generally less than those associated with the
drilling of wells.  Developmental drilling may result in dry holes or
wells that do not produce crude oil or natural gas in sufficient quantities to
make them commercially profitable to complete.  The acquired producing
portions of the Slaughter Dean Project, or other properties that may be acquired
by the Partnership, may not produce sufficient quantities of crude oil or
natural gas to enable a partner to obtain any certain projected rate of return
on his or her investment, and it is possible that partners may lose
money.  Also, Reef may receive information regarding the Slaughter
Dean Project that may indicate that less crude oil and natural gas reserves
exist than thought at the time of the acquisition of the Slaughter Dean
Project.  Oil and gas wells sometimes experience production decline
that is rapid and irregular.  Initial production from the wells of the
Slaughter Dean Project does not accurately indicate any consistent level of
production to be derived therefrom.





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





Prices
of crude oil and natural gas are volatile.





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





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





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





Competition
and market conditions may adversely affect the Partnership.





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


14


Government regulation may adversely
impact the Partnership's profitability.





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





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





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





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





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





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





There are
numerous natural hazards involved in the drilling and operation of oil and gas
wells, including unexpected or unusual formations, pressures, blowouts involving
possible damages to property and third parties, surface damages, bodily
injuries, damage to and loss of equipment, reservoir damage and loss of
reserves.  There are also hazards involved in the transportation of
crude oil and natural gas from our wells to market.  Such hazards
include pipeline leakage and risks associated with the spilling of crude oil
transported via barge instead of pipeline, both of which could result in
liabilities associated with environmental cleanup.  Uninsured
liabilities would reduce the funds available to the Partnership, may result in
the loss of Partnership properties and may create liability for non-Reef general
partners.  Although the Partnership will maintain insurance coverage
in amounts Reef deems appropriate, it is possible that insurance coverage may be
insufficient.  In that event, Partnership assets would be utilized to
pay personal injury and property damage claims and the costs of controlling
blowouts or replacing destroyed equipment rather than for additional drilling
and development activities.


The
Partnership may incur liability for liens against its
subcontractors.





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


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





Title to
the Partnership’s interest in the leases for the Slaughter Dean Project is held
in the name of the Partnership.  Under certain circumstances, title to
Partnership properties could be held by Reef on the Partnership's
behalf.  In other instances, title may not be transferred to Reef or
the Partnership until after a well has been completed.  When this is
the case, the Partnership runs the risk that the transfer of title could be set
aside in the event of the bankruptcy of the party holding title.  In
this event, title to the leases and the wells would revert to the creditors or
trustee, and the Partnership would either recover nothing or only the amount
paid for the leases and the cost of drilling the wells.  Assigning the
leases to the Partnership after the wells are drilled and completed, however,
will not affect the availability of the tax deductions for intangible drilling
costs since the Partnership will have an economic interest in the wells under
the drilling and operating agreement before the wells are
drilled.  See "ITEM 2.  PROPERTIES – Title to
Properties."


15


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





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





ITEM
      1B.
              UNRESOLVED
      STAFF COMMENTS





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





ITEM
      2.
              PROPERTIES





Drilling,
Waterflood Development Activities and Productive Wells





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





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





The
Slaughter Dean Project included approximately 70 wells producing or capable of
producing crude oil at the time of the Partnership’s acquisition in January
2008.  The initial plan for the development and expansion of the
waterflood on the Slaughter Dean Project (which has been adjusted from time to
time depending on information learned during the implementation of the work
plan) was to (i) drill approximately 30 new oil wells, (ii) convert
approximately 23 of the already-producing oil wells to waterflood injection
wells to support the new, denser waterflood pattern, (iii) drill approximately 5
new waterflood injection wells, (iv) workover or clean out approximately 5 of
the already-producing wells to improve their operation, , and (v) repair and
enhance the pumps and water injection system to increase its capacity and resume
water injection operations.  During 2008, the Partnership (a) drilled
25 new oil wells, (b) drilled 3 new injectors, and (c) worked over four
already-producing oil wells.  During 2009, the Partnership (1) drilled
five new oil wells, (2) converted 22 previously productive oil wells to
waterflood injection wells, (3) drilled 2 new waterflood injection wells, and
(4) worked over 1 already-producing well.  The Partnership has also
repaired, replaced, and expanded water pumping and injection facilities and
capacity during 2008 and 2009, and such work is continuing into 2010 with the
addition of a new injection pump during March 2010.  As planned, the
work program has been revised from time to time, and based upon the information
learned through December 31, 2009, RELP and the Partnership have paused in the
drilling of new oil wells while the enhancements to the waterflood operations
are completed and implemented.


16


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





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





In
January 2010, the Partnership entered into the RCWI Agreement with RCWI to
purchase certain working interests in oil and gas properties, represented by
leases, covering more than 400 properties, including more than 1,400 wells,
located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota,
Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas.The largest property
(THUMS Long Beach) in the package, is a long life water-flood project in the
Wilmington Field, located underneath the Long Beach Harbor in southern
California. THUMS Long Beach has produced more than 930 million barrels of oil
equivalent (natural gas production is converted to equivalent barrels of oil at
a rate of 6 MCF to 1 barrel of oil) from the Wilmington Field, and an estimated
100 million barrels of oil equivalent remains to be produced. THUMS Long Beach
derived its name from the property’s original shareholders, Texaco, Humble,
Union, Mobil and Shell. THUMS Long Beach has been an agent of Occidental Long
Beach, a subsidiary of Occidental Petroleum, since it was acquired in
2000.





Proved
Oil and Gas Reserves





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





As of
December 31, 2009 and 2008, proved reserves do not include any reserves
associated with the redevelopment and enhancement of the
waterflood.  There is not yet sufficient reservoir response to permit
performance based estimates of the amount and timing of additional
reserves.  Costs associated with the implementation of the waterflood
development process have been capitalized and categorized as unproved prior to
the time at which a reservoir response to the development work is
noticed.  The quantities of proved oil and gas reserves discussed in
this section include only the amounts which the Partnership reasonably expects
to recover in the future from known oil and gas reservoirs under the current
economic and operating conditions, without the enhanced production, if any, from
waterflood operations. Proved reserves include only quantities that the
Partnership expects to recover commercially using current prices, costs,
existing regulatory practices, and technology. Therefore, any changes in future
prices, costs, regulations, technology or other unforeseen factors could
materially increase or decrease the proved reserve estimates. The Partnership
had no proved reserves at December 31, 2007. The estimated net proved crude oil
and natural gas reserves at December 31, 2009 and 2008 are summarized
below.


17





Oil
      (BBL)
                  
                  
                  Gas
      (MCF)Net
      proved reserves as of December 31, 2008
                  
                  
                  308,302
                  
                  
                  
                  220,109Net
      proved reserves as of December 31, 2009
                  
                  
                  114,400
                  
                  
                  
                  66,060





The
standardized measure of discounted future net cash flows as of December 31, 2009
is computed by applying the 12-month average beginning-of-month price for the
year, costs, and legislated tax rates and a discount factor of 10% to net proved
reserves.  The standardized measure of discounted future net cash
flows as of December 31, 2008 is computed by applying year-end prices, costs,
and legislated tax rates and a discount factor of 10% to net proved reserves.
The standardized measure of discounted future net cash flows does not purport to
present the fair value of our crude oil and natural gas reserves.





Standardized
      measure of discounted future net cash flows as of December 31,
      2008
                  
                  $
                  4,483,742Standardized
      measure of discounted future net cash flows as of December 31,
      2009
                  
                  $
                  2,372,800





During
the years ended December 31, 2009 and 2008, the Partnership recorded property
impairment costs of proved properties totaling $668,430 and $0 as a result of
the net capitalized costs of proved oil and gas properties exceeding the sum of
estimated future net revenues from proved reserves, using the methodologies
described above.





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





The
Partnership used an independent petroleum consulting company, William M. Cobb
& Associates (“WCA”) of Dallas, Texas, to prepare its December 31, 2009 and
2008 reserve estimates of net proved crude oil and natural gas
reserves.  WCA estimated reserves for all of our properties as of
December 31, 2009 and 2008.  The technical personnel responsible for
preparing the reserve estimates at WCA meet the requirements regarding
qualifications, independence, objectivity, and confidentiality set forth in the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers.  WCA is
an independent firm of petroleum engineers and geologists.  They do
not own an interest in any of our properties, and are not employed on a
contingent fee basis.  WCA’s report was developed utilizing state
reporting records and published production data purchased from third parties,
and data provided by Reef.  Their reserve summary, which contains
further discussions of the reserve estimates and evaluations, as well as the
qualifications of WCA’s technical personnel responsible for overseeing their
estimates and evaluations, is included as Exhibit 99.1 to this Annual
Report.





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





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


18


Title
to Properties





Title to
the Slaughter Dean Project properties is held in the name of the
Partnership.  Under the RCWI Agreement, title to the properties is
held in the name of RCWI.  Currently RCWI holds record title to 84.76%
of the properties, based on their value.  RCWI is currently in the
process of having the remaining titles transferred to itself from the
seller.  When the Partnership acquires additional properties, title to
those properties may be held temporarily in Reef’s name or in the name of one or
more of Reef’s affiliates as nominee for the Partnership in order to facilitate
the acquisition of properties by the Partnership and for other valid
purposes.  Otherwise, record title to the Partnership properties will
be held in the name of the Partnership.





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





ITEM 3.
              LEGAL
      PROCEEDINGS





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





ITEM
      4.
              Reserved





PART
II





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





As of
December 31, 2009, the Partnership had one managing general partner, 779
non-Reef general partners, and 663 investor limited partners. Reef holds a total
of 8.9697 general partner units, and the non-Reef partners hold 490.9827 general
partner units and 397.0172 limited partner units. No established trading market
exists for the units.





Cash
which, in the sole judgment of the managing general partner, is not required to
meet the Partnership’s obligations is distributed to the partners at least
quarterly in accordance with the Partnership Agreement. Cash distributions paid
during 2009, 2008, and 2007 were $411,181, $1,791,295 and $16,801
respectively.





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


19


Use
of Proceeds





Units of
limited and general partner interests in the Partnership were offered at
$100,000 each (with a minimum investment of 1⁄4 unit at ($25,000)) to accredited
investors in a private placement pursuant to Section 4(2) of the Securities Act
of 1933 and Regulation D promulgated thereunder, with a maximum offering amount
of $90,000,00 (900 units).  Reef Securities, Inc., an affiliate of
Reef, served as the dealer manager for the private placement.  An
amount equal to 15% of the proceeds realized from the sale of interests to
investors was paid to Reef as a management fee.  A percentage of the
management fee (8.5% of the total amount raised by the Partnership) was then
used by Reef to pay sales commissions and marketing fees.  The
remaining 85% of the proceeds has been or will be used for operations on the
Slaughter Dean Project and other properties purchased by the Partnership, and to
pay any additional fees owed to Reef as a result of such
activities.  On May 31, 2008, the offering of general and limited
partnership interests was closed.  A total of $88,648,094 was raised
by the Partnership, net of adjustments for sales to brokers for their own
accounts, who were permitted to buy Units at a price net of the commission that
they would normally earn on sales of Units, of which $48,984,933 were sold to
accredited investors as general partner interests and $39,663,161 were sold to
accredited investors as limited partnership interests.  As managing
general partner, Reef contributed $762,425 (approximately one percent (1%) of
the total contributions of the non-Reef general partners and limited partners)
to the Partnership in exchange for 8.9697 units of general partner interest,
resulting in a total capitalization of the Partnership of $89,410,519 before
organization and offering costs.





All units
except those purchased by Reef paid a 15% ($13,320,000, less $151,906 of unpaid
net asset values) management fee to Reef to pay for Partnership organization and
offering costs, including sales commissions. These costs totaled $13,168,094,
leaving capital contributions of $76,242,425 available for Partnership oil and
gas operations. As of December 31, 2009, the Partnership had expended
$55,369,408 on acquisition and development of the Slaughter Dean
Project.  The remaining capital will be used for future acquisition
and development costs of oil and gas properties outside of the Slaughter Dean
Project to the extent such capital is not used on further development of the
Slaughter Dean Project.





In
January 2010, the Partnership entered into the RCWI Agreement with RCWI to
purchase certain working interests in oil and gas properties, represented by
leases, covering more than 400 properties, including more than 1,400 wells,
located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota,
Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas for approximately
$13,182,171 in cash, subject to post closing adjustments.





ITEM
      6.
              SELECTED
      FINANCIAL DATA





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





As of and For the Years Ended December 31,
                      
                      
                      Period from
                        Inception
                        (November
                        27,2007) to
                        December 31,2009
                      
                      
                      2008
                      
                      
                      2007Revenue
                      
                      $
                      1,655,812
                      
                      
                      $
                      2,012,489
                      
                      
                      $
                      —Interest
      income
                      
                      
                      140,471
                      
                      
                      
                      706,243
                      
                      
                      
                      28,208Costs
      and expenses
                      
                      
                      (3,343,360
                      )
                      
                      
                      (1,781,499
                      )
                      
                      
                      (30,353
                      )Net
      income (loss)
                      
                      
                      (1,547,077
                      )
                      
                      
                      937,233
                      
                      
                      
                      (2,144
                      )Allocation
      of net income (loss):Managing
      general partner
                      
                      
                      (70,841
                      )
                      
                      
                      128,050
                      
                      
                      
                      3,064General
      partner units
                      
                      
                      (816,223
                      )
                      
                      
                      447,404
                      
                      
                      
                      (2,252
                      )Limited
      partner units
                      
                      
                      (660,013
                      )
                      
                      
                      361,779
                      
                      
                      
                      (2,956
                      )Net
      income (loss) per managing partner unit
                      
                      
                      (7,897.79
                      )
                      
                      
                      14,275.84
                      
                      
                      
                      2,266.11Net
      income (loss) per general partner unit
                      
                      
                      (1,662.43
                      )
                      
                      
                      911.25
                      
                      
                      
                      (38.91
                      )Net
      income (loss) per limited partner unit
                      
                      
                      (1,662.43
                      )
                      
                      
                      911.25
                      
                      
                      
                      (38.91
                      )Total
      assets
                      
                      
                      74,855,409
                      
                      
                      
                      79,860,893
                      
                      
                      
                      11,663,508Distributions
      to managing general partner
                      
                      
                      49,050
                      
                      
                      
                      195,938
                      
                      
                      
                      168Distributions
      to investor partners
                      
                      
                      362,131
                      
                      
                      
                      1,595,357
                      
                      
                      
                      16,633Distributions
      per general partner unit
                      
                      
                      407.81
                      
                      
                      
                      1,796.57
                      
                      
                      
                      124.25Distributions
      per limited partner unit
                      
                      
                      407.81
                      
                      
                      
                      1,796.57
                      
                      
                      
                      124.25Distributions
      per managing  general partner unit
                      
                      
                      5,468.41
                      
                      
                      
                      21,844.32
                      
                      
                      
                      124.25Operating
      DataAnnual
      sales volume:Gas
      (MCF)
                      
                      
                      7,204
                      
                      
                      
                      21,466
                      
                      
                      
                      —Oil
      (BBL)
                      
                      
                      33,235
                      
                      
                      
                      23,060
                      
                      
                      
                      —Average
      sales price:Gas
      (per MCF)
                      
                      $
                      1.49
                      
                      
                      $
                      2.94
                      
                      
                      $
                      —Oil
      (per BBL)
                      
                      $
                      49.50
                      
                      
                      $
                      84.53
                      
                      
                      $
                      —




20




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





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





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





Critical
Accounting Policies





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





Oil
and Gas Properties





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





In
applying the full cost method at December 31, 2009, we perform a quarterly
ceiling test on the capitalized costs of oil and gas properties, whereby the
capitalized costs of oil and gas properties are limited to the sum of the
estimated future net revenues from proved reserves using prices that are the
12-month un-weighted arithmetic average of the first-day-of-the-month price for
crude oil and natural gas held constant and discounted at 10%, plus the lower of
cost or estimated fair value of unproved properties, if any, for 2009. If
capitalized costs exceed the ceiling, an impairment loss is recognized for the
amount by which the capitalized costs exceed the ceiling, and is shown as a
reduction of oil and gas properties and as property impairment expense on the
Partnership’s statement of operations. No gain or loss is recognized upon sale
or disposition of oil and gas properties, unless such a sale would significantly
alter the rate of depletion and amortization. During the years ended December
31, 2009 and 2008, the Partnership recognized property impairment expense of
proved properties totaling $668,430 and $0, respectively. The Partnership had no
proved property during the period from inception (November 27, 2007) to December
31, 2007.


21


Unproved
property consists of the capitalized costs associated with the development and
enhancement of waterflood operations in the Slaughter Dean
Project.  The costs associated with the development and waterflood
enhancement project are considered unproved pending an initial reservoir
production response. Investments in unproved properties are not depleted pending
determination of the existence of proved reserves. Unproved properties are
assessed for impairment quarterly as of the balance sheet date by considering
the data obtained from the operations of the Slaughter Dean Property. Any
impairment resulting from this quarterly assessment is reported as property
impairment expense in the current period, as appropriate. During the years ended
December 31, 2009 and 2008, the Partnership recognized no property impairment
expense of unproved properties. The partnership had no unproved property during
the period from inception (November 27, 2007) to December 31, 2007.





The
estimate of proved crude oil and natural gas reserves used to determine property
impairment expense, and also utilized in the Partnership’s disclosures of
supplemental information regarding oil and gas producing activities, including
the standardized measure of discounted cash flows, was prepared by an
independent petroleum engineer at December 31, 2009 and 2008, utilizing prices
and costs as promulgated by the SEC. The Partnership had no proved reserves at
December 31, 2007. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of crude oil and natural gas that cannot be
measured in an exact manner, and is based upon assumptions that may vary
considerably from actual results. Accordingly, reserve estimates may be subject
to upward or downward adjustments. Actual production, revenues and expenditures
with respect to reserves will likely vary from estimates, and such variances
could be material.





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





Asset
retirement costs and liabilities associated with future site restoration and
abandonment of long-lived assets are initially measured at fair value which
approximates the cost a third party would incur in performing the tasks
necessary to retire such assets. The fair value is recognized in the financial
statements as the present value of expected future cash expenditures for site
restoration and abandonment. Subsequent to the initial measurement, the effect
of the passage of time on the liability for the net asset retirement obligation
(accretion expense) and the amortization of the asset retirement cost are
recognized in the results of operations. During the years ended December 31,
2009 and 2008 and the period from inception (November 27, 2007) to December 31,
2007, the Partnership recognized $0, $213,365, and $0 of asset retirement
obligations and additional capitalized cost in connection with successful wells
drilled by the Partnership.





Recognition
of Revenue





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





Recently Adopted Accounting
Pronouncements





Modernization
of Oil and Gas Reporting





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


22


Accounting
Standards Codification




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





Fair
Value Measurement of Liabilities




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





Subsequent
Events





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





Recognition
and Presentation of Other-Than-Temporary Impairments





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


23


Interim
Reporting of Fair Value of Financial Instruments





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





Overview





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




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





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





The
Partnership has not borrowed funds during the development and waterflood
enhancement of the Slaughter Dean Project. Interest income and oil and gas
revenues, net of expenses, are being distributed to the partners.  The
Partnership Agreement allows borrowings from banks or other financial sources of
up to 30% of the aggregate capital contributions to the Partnership with the
consent of the Investor Partners.  The Partnership is also allowed to
utilize cash flows from successful wells in order to drill additional
development wells and construct facilities on properties purchased by the
Partnership. The Partnership has no plans at this time to borrow
funds.





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





Liquidity
and Capital Resources





The
Partnership was funded with initial capital contributions totaling $89,410,519
from both non-Reef partners and Reef, net of adjustments for sales to brokers
for their own accounts, who were permitted to buy Units at a price net of the
commission that they would normally earn on sales of Units.  Non-Reef
partners purchased 490.9827 general partner units and 397.0173 limited partner
units for $88,648,094, net of adjustments for sales to brokers for their own
accounts, who were permitted to buy Units at a price net of the commission that
they would normally earn on sales of Units. Reef contributed $762,425 for the
purchase of 8.9697 general partner units at a price of $85,000 per unit, which
is net of all offering costs. Organization and offering costs totaled
$13,168,094, leaving capital contributions of $76,242,425 available for
Partnership activities. The Partnership was formed on November 27, 2007, and the
last partner was admitted to the Partnership on May 31, 2008.


24


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





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





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





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





Leasehold Costs
                  
                  
                  Drilling and
                    Facilities Costs
                  
                  
                  Workovers
                  
                  
                  Total CostsPurchase
      Existing Wells
                  
                  $
                  15,371,780
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  15,371,780New
      WellsProducing
      Wells
                  
                  
                  76
                  
                  
                  
                  22,364,049
                  
                  
                  
                  -
                  
                  
                  
                  22,364,125Waterflood
      Injector Wells
                  
                  
                  -
                  
                  
                  
                  3,020,777
                  
                  
                  
                  -
                  
                  
                  
                  3,020,777Existing
      Wells
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1,184,966
                  
                  
                  
                  1,184,966$
                  15,371,856
                  
                  
                  $
                  25,384,826
                  
                  
                  $
                  1,184,966
                  
                  
                  $
                  41,941,648





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


25





Leasehold Costs
                  
                  
                  Drilling and
                    Facilities Costs
                  
                  
                  Workovers
                  
                  
                  Total CostsPurchase
      Existing Wells
                  
                  $
                  15,817,019
                  
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  15,817,019New
      WellsProducing
      Wells
                  
                  
                  74
                  
                  
                  
                  26,889,237
                  
                  
                  
                  -
                  
                  
                  
                  26,889,311Waterflood
      Injector Wells
                  
                  
                  -
                  
                  
                  
                  5,149,620
                  
                  
                  
                  -
                  
                  
                  
                  5,149,620Facilities
                  
                  
                  -
                  
                  
                  
                  1,495,913
                  
                  
                  
                  -
                  
                  
                  
                  1,495,913Existing
      Wells
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  6,017,545
                  
                  
                  
                  6,017,545$
                  15,817,093
                  
                  
                  $
                  33,534,770
                  
                  
                  $
                  6,017,545
                  
                  
                  $
                  55,369,408





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





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





Results
of Operations





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





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





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





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


26


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




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




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





Off-Balance
Sheet Arrangements





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





Contractual
Obligations Table





Payment due by periodContractual
                  obligations
                
                Total
                
                
                Less than 1
                  Year
                
                
                1-3 Years
                
                
                3-5 years
                
                
                More than 5
                  YearsConsulting
      agreement *
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —
                
                
                
                —





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





ITEM
      7A.
              QUANTITATIVE
      AND QUALITATIVE DISCLOSURE ABOUT MARKET
RISK





Interest
Rate Risk





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


27


Commodity
Price Risk





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





Assuming
the production levels the Partnership attained during the year ended
December 31, 2009, a 10% change in the price received for our crude oil
would have had an approximate $165,000 impact on the Partnership’s oil revenues,
and a 10% change in the price received for the Partnership’s natural gas would
have had an approximate$1,000 impact on
our natural gas revenues.





ITEM 8.
              FINANCIAL
      STATEMENTS AND SUPPLEMENTARY
DATA





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





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





None.




ITEM
      9A(T).
              CONTROLS
      AND PROCEDURES





Evaluation
of Disclosure Controls and Procedures





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





Management
Report on Internal Control Over Financial Reporting





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





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


28


Changes
in Internal Controls





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





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





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





ITEM
      9B.
              OTHER
      INFORMATION





None.





PART
III





ITEM
      10.
              DIRECTORS,
      EXECUTIVE OFFICERS, AND CORPORATE
GOVERNANCE





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





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





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





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


29





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 Officer and Treasurer of
  RELP





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





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





Byron H. (Howard) 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.


30


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





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





Audit
Committee and Nominating Committee





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





Code
of Ethics





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





ITEM
      11.
              EXECUTIVE
      COMPENSATION





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





Recipient
              
              Form ofCompensation
              
              AmountManaging
      General Partner
              
              Partnership
      interest
              
              10%
      carried interest in the Partnership, out of which the economic equivalent
      of a 3% carried interest is allowed to the broker/dealers who were
      involved in the offering of units.Managing
      General Partner
              
              Management
      fee
              
              15%
      of subscriptions, less organization and offering costs to be paid by Reef
      (non-recurring). For the years ended December 31, 2009 and 2008, the
      Partnership paid a management fee of $0 and $13,320,000
      respectively.Managing
      General Partner and its Affiliates
              
              Monthly
      administrative fee
              
              1/12th
      of 1% of all capital raised ($89,410,518), payable monthly until the
      Partnership is dissolved.  For the years ended December 31, 2009
      and 2008, the Partnership paid administrative fees of $896,880 and
      $700,706 respectively.


31





Recipient
              
              Form ofCompensation
              
              AmountManaging
      General Partner or its Affiliates
              
              Drilling
      compensation
              
              When
      Reef or an affiliate of Reef serves as operator of a Partnership property,
      then Reef or such affiliate, as the case may be, will receive drilling
      compensation equal to 15% of the total well costs, excluding lease
      acquisition costs.  Total well costs include the costs
      associated with all developmental activities on a well, such as drilling,
      completing, reworking, working over, deepening, sidetracking, or
      fracturing a well.  Because RELP will serve as operator of the
      Slaughter Dean Project, such drilling compensation payable to RELP may
      amount to approximately 9% total partnership subscriptions, depending on
      the level of developmental operations conducted by Reef or
      RELP.
                
                If
      neither Reef nor an affiliate of Reef serves as operator of a Partnership
      well, then Reef will receive drilling compensation equal to 5% of the
      total well costs, excluding lease acquisition costs, for our services as
      managing general partner.  As a result, such drilling
      compensation payable to Reef may amount to approximately 1% to 3% of total
      partnership subscriptions, depending on the level of developmental
      operations conducted by operators not affiliated with Reef.
                
                For
      the years ended December 31, 2009 and 2008, the Partnership paid a
      drilling compensation fee of $1,544,858 and $3,388,264
      respectively.Managing
      General Partner and its Affiliates
              
              Direct
      costs
              
              Reimbursement
      at cost.  For the years ended December 31, 2009 and 2008, the
      Partnership paid direct costs of $475,747 and $0
    respectively.Managing
      General Partner and its Affiliates
              
              Payment
      for equipment, supplies, marketing, and other services
              
              Competitive
      prices.  For the years ended December 31, 2009 and 2008, the
      Partnership paid no payments for equipment, supplies, marketing and other
      services.




32





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





Reef
received a payment equal to 15% ($13,320,000, less $151,906 of the unpaid net
asset values) of the Partnership's subscriptions, as adjusted for sale of Units
to brokers for their own accounts, who were permitted to buy Units at a price
net of the commission that they would normally earn on sales of
Units.  From this payment, Reef paid organization and offering costs
of the Partnership, including commissions.  Because the organization
and offering costs were less than 15% of the aggregate subscriptions to the
Partnership, Reef kept the difference ($5,688,668) as a one-time management
fee.





Reef also
receives an 11% interest in the Partnership in regard to which it bought 1% of
all Units issued by the Partnership; the additional 10% is "carried" by the
Investor Partners and for which Reef will pay no related
expenses.  During the years ended December 31, 2009 and 2008 and
during the period from inception (November 27, 2007) to December 31, 2007, Reef
has received $49,050, $195,938 and $168, respectively, in distributions related
to such 11% interest.





In
addition, when Reef, or an affiliate of Reef, such as RELP, serves as operator
of a Partnership well, then Reef or such affiliate of Reef, as the case may be,
will receive drilling compensation in an amount equal to 15% of the total well
costs paid from the funds of the Partnership.  RELP currently serves
as the operator of the Slaughter Dean Project.  As a result, such
drilling compensation payable to us or RELP may amount to approximately 9% of
total partnership subscriptions, depending on the level of developmental
operations conducted by Reef or RELP.Total well costs include
all drilling and equipment costs, including intangible well costs, tangible
costs of drilling and completing the well, costs of storage and other surface
facilities, and the tangible costs of gathering pipelines necessary to connect
the well to the nearest appropriate sales point or delivery point.  In
addition, total well costs also include the costs of all developmental
activities on a well, such as reworking, working over, deepening, sidetracking,
fracturing a producing well, installing pipeline for a well or any other
activity incident to the operations of a well, excluding ordinary well operating
costs after completion.  Total well costs do not include costs
relating to lease acquisitions for purposes of calculating drilling
compensation.  During the year ended December 31, 2009, RELP received
$1,544,858 in drilling compensation.  During the year ended December
31, 2008, RELP received $3,388,264 in drilling compensation.  During
the period from inception (November 27, 2007) to December 31, 2007, neither Reef
nor RELP received any drilling compensation. If neither Reef nor an affiliate of
Reef serves as operator of a Partnership well, then Reef will receive drilling
compensation equal to 5% of the total well costs, excluding lease acquisition
costs, for Reef’s services as managing general partner. Drilling compensation is
included in oil and gas properties in the financial statements.





Additionally,
Reef and its affiliates are reimbursed for direct costs and all documented
out-of-pocket expenses incurred on behalf of the Partnership. During the year
ended December 31, 2009, Reef and its affiliates received total reimbursements
for direct costs and other documented out-of-pocket expenses of $475,747 and
$38,208, respectively.  However, during the year ended December 31,
2008 and the period from inception (November 27, 2007) to December 31, 2007, no
reimbursements were made to Reef and its affiliates for direct and all
documented out-of-pocket costs. Reef also receives an administrative fee to
cover all general and administrative costs in an amount equal to 1/12th of 1%
of all capital raised (payable monthly until the partnership is
dissolved).  During the years ended December 31, 2009 and 2008, Reef
received $896,880 and $700,706, respectively, in administrative
fees.  Reef did not receive any administrative fees during the period
from inception (November 27, 2007) to December 31,
2007.  Administrative fees paid to Reef and its affiliates are
included in general and administrative expenses in the financial statements.
Reef’s general and administrative costs include all customary and routine
expenses, accounting, office rent, telephone, secretarial, salaries and other
incidental expenses incurred by Reef or its affiliates that are necessary to the
conduct of the partnership's business, whether generated by Reef, its affiliates
or by third parties, but excluding direct costs and operating
costs.


33


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





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





Compensation
Committee





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





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





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





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





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





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





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





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


34


In
January 2010, the Partnership entered into the RCWI Agreement with RCWI to
purchase certain working interests in oil and gas properties, represented by
leases, covering more than 400 properties, including more than 1,400 wells,
located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota,
Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas for approximately
$13,182,171 in cash, subject to post closing adjustments.





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
                  
                  $
                  126,250
                  
                  
                  $
                  164,543Audit
      related fees
                  
                  
                  —
                  
                  
                  
                  —Tax
      fees
                  
                  
                  —
                  
                  
                  
                  —All
      other fees
                  
                  
                  —
                  
                  
                  
                  —





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





PART
IV





ITEM
      15.
              EXHIBITS
      AND FINANCIAL STATEMENT
SCHEDULES





(a)
                    1.
      Financial 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.


35


SIGNATURES





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





Date:   April
2, 2010





REEF
      OIL & GAS INCOMEAND
      DEVELOPMENT FUND III, L.P.By:
                        Reef
      Oil & Gas Partners, L.P.Managing
      General PartnerBy:
                        Reef
      Oil & Gas Partners, GP, LLCBy:
                        /s/
      Michael J. MauceliMichael
      J. MauceliManager
      (principal executive
      officer)


36





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
                      
                      of
      Reef Exploration, L.P.(principal financial and
      accounting officer)


37


EXHIBIT
INDEX
 
 3.1
                  
                  Certificate
      of Formation of Reef Oil & Gas Income and Development Fund III, L.P.
      dated November 27, 2007 (incorporated by reference to Exhibit 3.1 to Form
      10, SEC File No. 000-53795, as filed with the SEC on October 2,
      2009).4.1
                  
                  Second
      Amended and Restated Agreement of Limited Partnership of Reef Oil &
      Gas Income and Development Fund III, L.P., dated June 4, 2008
      (incorporated by reference to Exhibit 4.1 to Form 10, SEC File No.
      000-53795, as filed with the SEC on October 2, 2009).10.1
                  
                  Operating
      Agreement dated January 7, 2008, by and among Reef Exploration, L.P., Reef
      Oil & Gas Income and Development Fund III, L.P. and Davric Corporation
      (incorporated by reference to Exhibit 10.1 to Form 10, SEC File No.
      000-53795, as filed with the SEC on October 2, 2009).10.2
                  
                  Operating
      Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef Oil
      & Gas Income and Development Fund III, L.P. and Davric Corporation
      (incorporated by reference to Exhibit 10.2 to Form 10, SEC File No.
      000-53795, as filed with the SEC on October 2, 2009).10.3
                  
                  Purchase
      and Sale Agreement dated January 7, 2008, by and among Sierra-Dean
      Production Company L.P., Reef Oil & Gas Income and Development Fund
      III, L.P., Reef Exploration, L.P. and SPI Operations LLC, as amended on
      January 8, 2008 (incorporated by reference to Exhibit 10.3 to Form 10, SEC
      File No. 000-53795, as filed with the SEC on October 2,
    2009).10.4
                  
                  Assignment,
      dated May 1, 2008, by and between Davric Corporation and Reef Oil &
      Gas Income and Development Fund III, L.P. (incorporated by reference to
      Exhibit 10.4 to Form 10, SEC File No. 000-53795, as filed with the SEC on
      October 2, 2009).10.5
                  
                  Crude
      Oil Contract, dated March 13, 2008, by and between Reef Exploration, L.P.
      and Occidental Energy Marketing, Inc., as amended by Amendment No. 1,
      dated June 24, 2008, by and between Reef Exploration, L.P. and Occidental
      Energy Marketing, Inc. (incorporated by reference to Exhibit 10.5 to Form
      10, SEC File No. 000-53795, as filed with the SEC on October 2,
      2009).10.6
                  
                  Consulting
      Agreement, dated September 1, 2006, by and between Reef Exploration, L.P.
      and William R. Dixon (incorporated by reference to Exhibit 10.6 to Form
      10, SEC File No. 000-53795, as filed with the SEC on October 2,
      2009).10.7
                  
                  Casinghead
      Gas Sales Contract, dated January 1, 1978, by and between Amoco Production
      Company and Amoco Production Company (incorporated by reference to Exhibit
      10.7 to Form 10, SEC File No. 000-53795, as filed with the SEC on October
      2, 2009).10.8
                  
                  Purchase
      and Sale Agreement, dated January 19, 2010, by and between Azalea
      Properties Ltd. And RCWI, L.P. (incorporated by reference to Exhibit 10.1
      to the Partnership's Form 8-K, as filed with the SEC on January 22,
      2010).10.9
                  
                  Purchase
      and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P., and
      Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by
      reference to Exhibit 10.2 to the Partnership's Form 8-K, as filed with the
      SEC on January 22, 2010).10.10
                  
                  Side
      Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea
      Properties Ltd. regarding Post Closing PUDs (incorporated by reference to
      Exhibit 10.3to the Partnership's Form 8-K, as filed with the SEC on
      January 22, 2010).10.11
                  
                  Side
      Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea
      Properties Ltd. Regarding Post Closing Properties/Title Defect Notice
      (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K,
      as filed with the SEC on January 22, 2010).10.12
                  
                  Side
      Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea
      Properties Ltd. Regarding Third Party Consents (incorporated by reference
      to Exhibit 10.5 to the Partnership's Form 8-K, as filed with the SEC on
      January 22, 2010).23.2
                  
                  Consent
      of William M. Cobb & Associates, Inc.*31.1
                  
                  Certification
      of Principal Executive Officer pursuant to Rule 13a-14(a) under the
      Securities Exchange Act of 1934.*31.2
                  
                  Certification
      of Principal Financial Officer pursuant to Rule 13a-14(a) under the
      Securities Exchange Act of 1934.*32.1
                  
                  Certification
      of Principal Executive Officer pursuant to 18 U.S.C.
    §1350.*32.2
                  
                  Certification
      of Principal Financial Officer pursuant to 18 U.S.C.
    §1350.*99.1
                  
                  Summary
      Reserve Report of William M. Cobb & Associates,
  Inc.*
 
 
 *  Attached
herewith





38





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





Financial
Statements





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


December
31, 2007




Contents





Report
      of Independent Registered Public Accounting Firm
                F-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


39


Report of
Independent Registered Public Accounting Firm





Partners


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


Dallas,
TX





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





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





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





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





Dallas,
Texas


April 2,
2010


F-1


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





Balance
Sheets





December
      31,
                
                2009
                
                
                2008AssetsCurrent
      assets:Cash
      and cash equivalents
                
                $
                18,243,848
                
                
                $
                34,549,487Accounts
      receivable
                
                
                736,161
                
                
                
                671,889Accounts
      receivable from affiliates
                
                
                1,500,000
                
                
                
                2,209,300Prepaids
      and other current assets
                
                
                -
                
                
                
                507,640Total
      current assets
                
                
                20,480,009
                
                
                
                37,938,316Oil
      and gas properties, full cost method of accounting:Accounting:Proved
      properties, net of accumulated depletion of $1,207,373 and
      $232,436
                
                
                2,364,672
                
                
                
                3,339,609Unproved
      properties
                
                
                52,010,728
                
                
                
                38,582,968Net
      oil and natural gas properties
                
                
                54,375,400
                
                
                
                41,922,577Total
      assets
                
                $
                74,855,409
                
                
                $
                79,860,893Liabilities
      and partnership equityCurrent
      liabilities:Accounts
      payable
                
                $
                571,154
                
                
                $
                1,330,079Accounts
      payable to affiliates
                
                
                223,515
                
                
                
                -Accrued
      liabilities
                
                
                245,090
                
                
                
                2,775,346Total
      current liabilities
                
                
                1,039,759
                
                
                
                4,105,425Long
      term liabilities:Asset
      retirement obligation
                
                
                248,912
                
                
                
                230,472Total
      long term liabilities
                
                
                248,912
                
                
                
                230,472Commitments
      and contingencies (Note 5)Partnership
      equityGeneral
      partners
                
                
                40,609,693
                
                
                
                41,626,140Limited
      partners
                
                
                32,253,928
                
                
                
                33,075,848Managing
      general partner
                
                
                703,117
                
                
                
                823,008Total
      partnership equity
                
                
                73,566,738
                
                
                
                75,524,996Total
      liabilities and partnership equity
                
                $
                74,855,409
                
                
                $
                79,860,893





See
accompanying notes to financial statements.


F-2


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





Statements
of Operations





As of and For the Years Ended December
                  31,
                
                
                Period from
                  inception
                  (November 27, 2007)
                  to December 31,2009
                
                
                2008
                
                
                2007)Revenues
                
                $
                1,655,812
                
                
                $
                2,012,489
                
                
                $
                -Costs
      and expenses:Lease
      operating expenses
                
                
                1,297,997
                
                
                
                1,190,395
                
                
                
                -Production
      taxes
                
                
                78,127
                
                
                
                94,106
                
                
                
                -Depreciation,
      depletion and amortization
                
                
                306,507
                
                
                
                232,436
                
                
                
                -Accretion
      of asset retirement obligation
                
                
                18,440
                
                
                
                17,107
                
                
                
                -Property
      impairment
                
                
                668,430
                
                
                
                -
                
                
                
                -General
      and administrative
                
                
                973,859
                
                
                
                247,455
                
                
                
                30,353Total
      costs and expenses
                
                
                3,343,360
                
                
                
                1,781,499
                
                
                
                30,353Income
      (loss) from operations
                
                
                (1,687,548
                )
                
                
                230,990
                
                
                
                (30,353
                )Other
      incomeInterest
      income
                
                
                140,471
                
                
                
                706,243
                
                
                
                28,208Total
      other income
                
                
                140,471
                
                
                
                706,243
                
                
                
                28,208Net
      income (loss)
                
                $
                (1,547,077
                )
                
                $
                937,233
                
                
                $
                (2,144
                )Net
      income (loss) per general partner unit
                
                $
                (1,662.43
                )
                
                $
                911.25
                
                
                $
                (38.91
                )Net
      income (loss) per limited partner unit
                
                $
                (1,662.43
                )
                
                $
                911.25
                
                
                $
                (38.91
                )Net
      income (loss) per managing general partner unit
                
                $
                (7,897.79
                )
                
                $
                14,275.84
                
                
                $
                2,266.11





See
accompanying notes to financial statements.


F-3


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





Statements
of Partnership Equity





General Partners
                        
                        
                        Limited Partners
                        
                        
                        Managing General Partner
                        
                        
                        TotalUnits
                        
                        
                        Amount
                        
                        
                        Units
                        
                        
                        Amount
                        
                        
                        Units
                        
                        
                        Amount
                        
                        
                        Units
                        
                        
                        AmountPartner
      contributions
                        
                        
                        57.8753
                        
                        
                        $
                        4,933,466
                        
                        
                        
                        75.9892
                        
                        
                        $
                        6,474,736
                        
                        
                        
                        1.3522
                        
                        
                        $
                        137,530
                        
                        
                        
                        135.2167
                        
                        
                        $
                        11,545,732Partner
      distributions
                        
                        
                        -
                        
                        
                        
                        (7,191
                        )
                        
                        
                        -
                        
                        
                        
                        (9,442
                        )
                        
                        
                        -
                        
                        
                        
                        (168
                        )
                        
                        
                        -
                        
                        
                        
                        (16,802
                        )Net
      loss
                        
                        
                        -
                        
                        
                        
                        (2,252
                        )
                        
                        
                        -
                        
                        
                        
                        (2,956
                        )
                        
                        
                        -
                        
                        
                        
                        3,064
                        
                        
                        
                        -
                        
                        
                        
                        (2,144
                        )Balance
      at December 31, 2007
                        
                        
                        57.8753
                        
                        
                        $
                        4,924,023
                        
                        
                        
                        75.9892
                        
                        
                        $
                        6,462,338
                        
                        
                        
                        1.3522
                        
                        
                        $
                        140,426
                        
                        
                        
                        135.2167
                        
                        
                        $
                        11,526,786Distribution
      amount per partnership unit
                        
                        
                        
                        
                        
                        $
                        124.25
                        
                        
                        
                        
                        
                        
                        $
                        124.25
                        
                        
                        
                        
                        
                        
                        $
                        124.24Balance
      at December 31, 2007
                        
                        
                        57.8753
                        
                        
                        $
                        4,924,023
                        
                        
                        
                        75.9892
                        
                        
                        $
                        6,462,338
                        
                        
                        
                        1.3522
                        
                        
                        $
                        140,426
                        
                        
                        
                        135.2167
                        
                        
                        $
                        11,526,786Partner
      contributions
                        
                        
                        433.1074
                        
                        
                        
                        37,136,799
                        
                        
                        
                        321.0280
                        
                        
                        
                        26,965,003
                        
                        
                        
                        7.6175
                        
                        
                        
                        750,470
                        
                        
                        
                        761.7529
                        
                        
                        
                        64,852,272Partner
      distributions
                        
                        
                        -
                        
                        
                        
                        (882,086
                        )
                        
                        
                        -
                        
                        
                        
                        (713,271
                        )
                        
                        
                        -
                        
                        
                        
                        (195,938
                        )
                        
                        
                        -
                        
                        
                        
                        (1,791,295
                        )Net
      loss
                        
                        
                        -
                        
                        
                        
                        447,404
                        
                        
                        
                        -
                        
                        
                        
                        361,779
                        
                        
                        
                        -
                        
                        
                        
                        128,050
                        
                        
                        
                        -
                        
                        
                        
                        937,233Balance
      at December 31, 2008
                        
                        
                        490.9827
                        
                        
                        $
                        41,626,140
                        
                        
                        
                        397.0172
                        
                        
                        $
                        33,075,848
                        
                        
                        
                        8.9697
                        
                        
                        $
                        823,008
                        
                        
                        
                        896.9696
                        
                        
                        $
                        75,524,996Distribution
      amount per partnership unit
                        
                        
                        
                        
                        
                        $
                        1,796.57
                        
                        
                        
                        
                        
                        
                        $
                        1,796.57
                        
                        
                        
                        
                        
                        
                        $
                        21,844.43Balance
      at December 31, 2008
                        
                        
                        490.9827
                        
                        
                        $
                        41,626,140
                        
                        
                        
                        397.0172
                        
                        
                        $
                        33,075,848
                        
                        
                        
                        8.9697
                        
                        
                        $
                        823,008
                        
                        
                        
                        896.9696
                        
                        
                        $
                        75,524,996Partner
      distributions
                        
                        
                        -
                        
                        
                        
                        (200,224
                        )
                        
                        
                        -
                        
                        
                        
                        (161,907
                        )
                        
                        
                        -
                        
                        
                        
                        (49,050
                        )
                        
                        
                        -
                        
                        
                        
                        (411,181
                        )Net
      loss
                        
                        
                        -
                        
                        
                        
                        (816,223
                        )
                        
                        
                        -
                        
                        
                        
                        (660,013
                        )
                        
                        
                        -
                        
                        
                        
                        (70,841
                        )
                        
                        
                        -
                        
                        
                        
                        (1,547,077
                        )Balance
      at December 31, 2009
                        
                        
                        490.9827
                        
                        
                        $
                        40,609,693
                        
                        
                        
                        397.0172
                        
                        
                        $
                        32,253,928
                        
                        
                        
                        8.9697
                        
                        
                        $
                        703,117
                        
                        
                        
                        896.9696
                        
                        
                        $
                        73,566,738Distribution
      amount per partnership unit
                        
                        
                        
                        
                        
                        $
                        407.79
                        
                        
                        
                        
                        
                        
                        $
                        407.81
                        
                        
                        
                        
                        
                        
                        $
                        5,468.41





See
accompanying notes to financial statements.


F-4


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





Statements
of Cash Flows





For the Years Ended December 31,
                
                
                Period from
                  inception
                  (November 27,
                  2007) to December2009
                
                
                2008
                
                
                31, 2007Operating
      activitiesNet
      income (loss)
                
                $
                (1,547,077
                )
                
                $
                937,233
                
                
                $
                (2,144
                )Adjustments
      to reconcile net income (loss) to net cash provided by (used in)
      operating activities:Depletion,
      depreciation and amortization
                
                
                306,507
                
                
                
                232,436
                
                
                
                -Accretion
      of asset retirement obligation
                
                
                18,440
                
                
                
                17,107
                
                
                
                -Property
      impairment
                
                
                668,430
                
                
                
                -
                
                
                
                -Changes
      in operating assets and liabilitiesAccounts
      receivable
                
                
                (64,272
                )
                
                
                (671,889
                )
                
                
                -Accounts
      receivable from affiliates
                
                
                709,300
                
                
                
                (2,209,300
                )
                
                
                -Prepaid
      expenses
                
                
                507,640
                
                
                
                (507,640
                )
                
                
                -Accounts
      payable
                
                
                (900,104
                )
                
                
                277,948
                
                
                
                16,802Accounts
      payable to affiliates
                
                
                154,790
                
                
                
                (119,920
                )
                
                
                119,920Accrued
      liabilities
                
                
                (2,636,425
                )
                
                
                104,492
                
                
                
                -Net
      cash provided by (used in) operating activities
                
                
                (2,782,771
                )
                
                
                (1,939,533
                )
                
                
                134,578Investing
      activities:Purchase
      of oil & gas properties
                
                
                (80,758
                )
                
                
                (15,260,041
                )
                
                
                -Property
      development
                
                
                (12,951,445
                )
                
                
                (22,943,170
                )
                
                
                (111,739
                )Net
      cash used in investing activities
                
                
                (13,032,203
                )
                
                
                (38,203,211
                )
                
                
                (111,739
                )Financing
      activities:Proceeds
      from the sale of partnership interest
                
                
                -
                
                
                
                76,109,019
                
                
                
                13,578,985Distributions
      to partners
                
                
                (490,665
                )
                
                
                (1,711,811
                )
                
                
                (16,802
                )Syndication
      costs
                
                
                -
                
                
                
                (11,256,747
                )
                
                
                (2,033,253
                )Net
      cash provided by (used in) investing activities
                
                
                (490,665
                )
                
                
                63,140,461
                
                
                
                11,528,930Net
      increase (decrease) in cash and cash equivalents
                
                
                (16,305,639
                )
                
                
                22,997,717
                
                
                
                11,551,769Cash
      and cash equivalents, beginning of year
                
                
                34,549,487
                
                
                
                11,551,769
                
                
                
                -Cash
      and cash equivalents, end of year
                
                $
                18,243,848
                
                
                $
                34,549,487
                
                
                $
                11,551,769Supplemental
      disclosure of non-cash investing transactionsProperty
      additions included in accounts payable
                
                $
                (141,179
                )
                
                $
                (1,035,331
                )
                
                $
                -Property
      additions included in accounts payable to affiliates
                
                $
                (68,725
                )
                
                $
                0
                
                
                $
                -Property
      additions included in accrued liabilities
                
                $
                (185,653
                )
                
                $
                (2,821,842
                )
                
                $
                -Supplemental
      disclosure of non-cash financing transactionsDistributions
      included in accrued liabilities
                
                $
                -
                
                
                $
                79,484
                
                
                $
                -





See
accompanying notes to financial statements.


F-5


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


Notes to
Financial Statements





1.
Organization and Basis of Presentation





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





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





The
Partnership engages primarily in oil and gas development and production in a
producing oil property located in the Slaughter Field in Cochran County, Texas,
approximately 50 miles southwest of Lubbock, Texas (the “Slaughter Dean
Project”), and is not involved in any other industry segment.  The
Partnership will participate in developmental drilling and not exploratory
drilling. To the extent any acreage the Partnership acquires contains unproved
reserves, such acreage may be farmed out or sold to third parties or other
partnerships formed by Reef for exploratory drilling.





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





In
January 2008, the Partnership purchased an initial 41% working interest from
Sierra-Dean Production Company LP, (“Sierra Dean”) in a producing oil property
located in the Slaughter Dean Project and under the terms of the acquisition
agreement, each month thereafter purchases additional working interests based on
the amount the Partnership spends developing the project through January
2013.  Under the acquisition agreement the Partnership generally pays
82% of all drilling, development and repair costs (including amounts allocable
to the working interest initially retained by Sierra Dean), and Sierra Dean
conveys additional working interests to the Partnership each month in payment of
its share of such costs. In a separate transaction in May 2008, the Partnership
purchased an 11% working interest in the Slaughter Dean Project from Davric
Corporation.





2.
Summary of Accounting Policies





Use
of Estimates





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


F-6


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


Notes to
Financial Statements (continued)





Cash
and Cash Equivalents





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





Risks
and Uncertainties





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





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





Crude
Oil and Natural Gas Properties





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





In
applying the full cost method at December 31, 2009, the Partnership performs a
quarterly ceiling test on the capitalized costs of oil and gas properties,
whereby the capitalized costs of oil and gas properties are limited to the sum
of the estimated future net revenues from proved reserves using prices that are
the 12-month un-weighted arithmetic average of the first-day-of-the-month price
for crude oil and natural gas held constant and discounted at 10%, plus the
lower of cost or estimated fair value of  unproved properties, if any,
for 2009. If capitalized costs exceed the ceiling, an impairment loss is
recognized for the amount by which the capitalized costs exceed the ceiling, and
is shown as a reduction of oil and gas properties and as property impairment
expense on the Partnership’s statements of operations. No gain or loss is
recognized upon sale or disposition of crude oil and natural gas properties,
unless such a sale would significantly alter the rate of depletion and
amortization. During the years ended December 31, 2009 and 2008, the Partnership
recognized property impairment expense of proved properties of $668,430 and $0,
respectively. The Partnership had no proved property at December 31,
2007.





Unproved
property consists of the capitalized costs associated with the development and
enhancement of waterflood operations in the Slaughter Dean Project. The costs
associated with the development and waterflood enhancement project are
considered unproved pending an initial reservoir production response.
Investments in unproved properties are not depleted pending determination of the
existence of proved reserves. Unproved properties are assessed for impairment
quarterly as of the balance sheet date by considering the data obtained from the
waterflood operations of the Slaughter Dean Property. Any impairment resulting
from this quarterly assessment is reported as property impairment expense in the
current period, as appropriate. During the years ended December 31, 2009 and
2008, the Partnership recognized no property impairment expense of unproved
properties. The Partnership had no unproved property at December 31,
2007.


F-7


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


Notes to
Financial Statements (continued)





Estimates
of Proved Oil and Gas Reserves





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




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




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





Restoration,
Removal, and Environmental Liabilities





The
Partnership is subject to extensive Federal, state and local environmental laws
and regulations. These laws regulate the discharge of materials into the
environment and may require the Partnership to remove or mitigate the
environmental effects of the disposal or release of petroleum substances at
various sites. Environmental expenditures are expensed or capitalized depending
on their future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future economic benefit are
expensed.





Liabilities
for expenditures of a non-capital nature are recorded when environmental
assessments and/or remediation is probable, and the costs can be reasonably
estimated. Such liabilities are generally undiscounted values unless the timing
of cash payments for the liability or component is fixed or reliably
determinable.





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





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


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





Recognition
of Revenue





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


F-8


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


Notes to
Financial Statements (continued)





Income
Taxes





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





As of
December 31, 2009, the financial reporting basis of the Partnership’s assets
exceeds the tax basis of the assets by approximately $23.5 million, primarily
due to the difference between property impairment costs deducted for financial
reporting purposes and intangible drilling costs deducted for income tax
purposes.





Accounting
for Uncertainty in Income Taxes





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





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





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





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





Fair
Value of Financial Instruments





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





Recently
Adopted Accounting Pronouncements





Modernization
of Oil and Gas Reporting





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


F-9


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


Notes to
Financial Statements (continued)





Accounting
Standards Codification




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





Fair
Value Measurement of Liabilities




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





Subsequent
Events





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





Recognition
and Presentation of Other-Than-Temporary Impairments





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


F-10


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


Notes to
Financial Statements (continued)





Interim
Reporting of Fair Value of Financial Instruments





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.





3.
Transactions with Affiliates





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





Reef also
received an 11% interest in the Partnership for which it pays 1% of all costs
related to the Partnership; the additional 10% is "carried" by the Investor
Partners and for which Reef will pay no related expenses.  During the
years ended December 31, 2009 and 2008 and the period from inception (November
27, 2007) to December 31, 2007, Reef received $49,050, $195,938 and $168,
respectively, in distributions related to the 11% interest. From funds generated
by its carried interest and management fee, Reef paid to specific FINRA-licensed
broker-dealers a monthly fee in the amount equal to the maximum of the economic
equivalent of a 3% carried interest in the Partnership as additional
compensation for the sale of units.  This was recorded as a commission
expense by Reef.





RELP
currently serves as the operator of the Slaughter Dean Project and receives
drilling compensation in an amount equal to 15% of the total well costs paid by
the development Partnership.    Total well costs include all
drilling and equipment costs, including intangible development
costs,  surface facilities, and costs of pipelines necessary to
connect the well to the nearest appropriate or delivery point.  In
addition, total well costs also include the costs of all developmental
activities on a well, such as reworking, working over, deepening, sidetracking,
fracturing a producing well, installing pipeline for a well or any other
activity incident to the operations of a well, excluding ordinary well operating
costs after completion.  Total well costs do not include costs
relating to lease acquisitions.  During the years ended December 31,
2009 and 2008 and the period from inception (November 27, 2007) to December 31,
2007, RELP has received $1,544,858, $3,388,264 and $0, respectively, in drilling
compensation.  Drilling compensation is included in oil and gas
properties in the financial statements.





RELP
receives an administrative fee to cover all general and administrative costs in
an amount equal to 1/12th of 1%
of all capital raised payable monthly.  During the years ended
December 31, 2009 and 2008 and the period from inception (November 27, 2007) to
December 31, 2007, Reef has received $896,880, $700,706 and $0, respectively, in
administrative fees. Administrative fees are included in general and
administrative expense in the financial statements. Reef’s general and
administrative costs include all customary and routine expenses, accounting,
office rent, telephone, secretarial, salaries and other incidental expenses
incurred by Reef or its affiliates that are necessary to the conduct of the
Partnership's business, whether generated by Reef, its affiliates or by third
parties, but excluding direct costs and operating costs.





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





Reef and
its affiliates may enter into other transactions with the Partnership for
services, supplies and equipment, and will be entitled to compensation at
competitive prices and terms as determined by reference to charges of
unaffiliated companies providing similar services, supplies and
equipment.


F-11


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


Notes to
Financial Statements (continued)





4.
Major Customers





The
Partnership may sell crude oil and natural gas on credit terms to refiners,
pipelines, marketers, and other users of petroleum commodities. Revenues can be
received directly from these parties or, in certain circumstances, paid to the
operator of the property who disburses to the Partnership its percentage share
of the revenues. Prior to December 31, 2007, the Partnership had no crude oil
and natural gas production and, therefore, had no customers.  During
the years ended December 31, 2009 and 2008, one marketer accounted for all of
the Partnership’s crude oil revenues, and one marketer accounted for all of the
Partnership’s natural gas revenues. During 2008 and 2009, the Partnership’s only
oil and gas property was the Slaughter Dean Project located in Cochran County,
Texas. Reef has chosen to sell the Partnership’s crude oil and natural gas
to two subsidiaries of a large international oil and gas company because of the
price they pay, the promptness with which they pay, and their credit worthiness
indicated by their publicly filed financial statements.  There are other
large companies (or subsidiaries thereof) active in purchasing crude oil and
natural gas in the area of the Slaughter Dean Property, including Exxon, Royal
Dutch Shell, Plains All American Pipeline, Conoco-Phillips, Genesis Energy, and
Holly Energy.  There are also several smaller companies that purchase
and re-sell crude oil.  Due to the competitive nature of the market
for purchase of crude oil and natural gas, the Partnership does not believe that
the loss of the current purchaser would have a material adverse impact on the
Partnership.





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





5.
Commitments and Contingencies





The
Partnership is not currently involved in any legal proceedings.





The
Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN
Associates whereby the Partnership agreed to assign a one percent (1%)
overriding royalty interest, proportionately reduced to the Partnership’s
working interest, to William R. Dixon in exchange for Dixon’s agreement to
“review and evaluate exploration, exploitation, and development drilling
opportunities." This overriding royalty interest burdens the Partnership’s
working interest in the Slaughter Dean Field.





6.
Partnership Equity





Information
regarding the number of units outstanding and the net income (loss) per type of
Partnership unit for the years ended December 31, 2009 and 2008 and the period
from inception (November 27, 2007) through December 31, 2007, is detailed
below:





For the
year ended December 31, 2009





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


F-12


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


Notes to
Financial Statements (continued)





For the
year ended December 31, 2008





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





For the
period from inception through December 31, 2007





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





7.
Subsequent Events





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





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





The
following unaudited pro forma condensed consolidated statements of revenue
and earnings for the years ended December 31, 2009 and 2008 are
presented as if the acquisition had occurred at the beginning of the period
presented. The unaudited pro forma condensed consolidated financial information
is not indicative of our financial position or the results of our operations
that might have actually occurred if the Azalea acquisition had occurred at the
dates presented or of our future financial position or results of operations. In
addition the results may vary significantly from the results reflected in such
statements due to normal oil and gas production declines, reductions in prices
paid for oil and gas, future acquisitions and other factors.


F-13


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


Notes to
Financial Statements (continued)




UNAUDITED
PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF REVENUE AND EARNINGS





As
      of and For the Years Ended December 31,
                  
                  2009
                  
                  
                  2008Revenues
                  
                  $
                  4,219,565
                  
                  
                  $
                  6,456,431Net
      loss
                  
                  $
                  (4,272,297
                  )
                  
                  $
                  (11,270,531
                  )Net
      loss per general partner unit
                  
                  $
                  (4,903.11
                  )
                  
                  $
                  (13,099.73
                  )Net
      loss per limited partner unit
                  
                  $
                  (4,903.11
                  )
                  
                  $
                  (13,099.73
                  )Net
      income per managing general partner unit
                  
                  $
                  8,881.85
                  
                  
                  $
                  40,361.38





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





Capitalized
Costs





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





December
                    31, 2009
                  
                  
                  December
                    31, 2008
                  
                  
                  December
                    31, 2007Oil
      and natural gas properties:Unproved
      properties
                  
                  $
                  52,010,728
                  
                  
                  $
                  38,582,968
                  
                  
                  $
                  111,739Proved
      properties
                  
                  
                  3,358,680
                  
                  
                  
                  3,358,680
                  
                  
                  
                  —Capitalized
      asset retirement obligation
                  
                  
                  213,365
                  
                  
                  
                  213,365
                  
                  
                  
                  —55,582,773
                  
                  
                  
                  42,155,013
                  
                  
                  
                  111,739Less:Accumulated
      depreciation, depletion and amortization
                  
                  
                  (538,943
                  )
                  
                  
                  (232,436
                  )
                  
                  
                  —Property
      impairment
                  
                  
                  (668,430
                  )
                  
                  
                  —
                  
                  
                  
                  —(1,207,373
                  )
                  
                  
                  (232,436
                  )
                  
                  
                  —Total
                  
                  $
                  54,375,400
                  
                  
                  $
                  41,922,577
                  
                  
                  $
                  111,739


F-14


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


Notes to
Financial Statements (continued)





Costs
Withheld from Amortization





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





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





Unproved
property consists of the capitalized costs associated with the development and
enhancement of waterflood operations in the Slaughter Dean
Project.  The costs associated with the development and waterflood
enhancement project are considered unproved pending an initial reservoir
production response.





Costs
Incurred





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





2009
                  
                  
                  2008
                  
                  
                  2007Oil
      and natural gas properties:Exploration
                  
                  $
                  —
                  
                  
                  $
                  —
                  
                  
                  $
                  —Development
                  
                  
                  10,929,932
                  
                  
                  
                  22,588,437
                  
                  
                  
                  —Total
                  
                  $
                  10,929,932
                  
                  
                  $
                  22,588,437
                  
                  
                  $
                  —





Results
of Operations




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





2009
                    
                    
                    2008Oil
      and gas producing activities:Oil
      sales
                    
                    $
                    1,645,056
                    
                    
                    $
                    1,949,274Natural
      gas sales
                    
                    
                    10,756
                    
                    
                    
                    63,215Production
      expenses
                    
                    
                    (1,376,124
                    )
                    
                    
                    (1,284,501
                    )Accretion
      of asset retirement obligation
                    
                    
                    (18,440
                    )
                    
                    
                    (17,107
                    )Depreciation,
      depletion and amortization
                    
                    
                    (306,507
                    )
                    
                    
                    (232,436
                    )Property
      impairment
                    
                    
                    (668,430
                    )Results
      of operations from producing activities
                    
                    $
                    (713,689
                    )
                    
                    $
                    478,445Depletion
      rate per BOE
                    
                    $
                    8.90
                    
                    
                    $
                    9.68





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


F-15


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


Notes to
Financial Statements (continued)





Crude
Oil and Natural Gas Reserves





Recent
SEC and FASB Rule Making Activity





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





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





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





Net
Proved Developed Reserve Summary





The
reserve information presented below is based upon estimates of net proved
reserves that were prepared by the independent petroleum engineering firms
William M. Cobb & Associates as of December 31, 2009 and
2008.   A copy of the William M. Cobb & Associates summary
reserve report is included as Exhibit 99.1 to this Annual
Report.  Proved crude oil and natural gas reserves are the estimated
quantities of crude oil and natural gas which geological and engineering data
demonstrate with reasonable certainty to be economically recoverable in future
years from known reservoirs under existing economic conditions, operating
methods and governmental regulations (i.e. prices and costs as of the date the
estimate is made).  Proved developed reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods.  At December 31, 2009, all of the Partnership’s
reserves are classified as proved developed reserves.  All of the
Partnership’s reserves are located in the United States.





The
following information table sets forth changes in estimated net proved developed
crude oil and natural gas reserves for the years ended December 31, 2009
and 2008. The Partnership had no proved crude oil and natural gas reserves at
December 31, 2007.





Oil
                    (BBL) (1)
                  
                  
                  Gas
                    (mcf)
                  
                  
                  BOE (2)Net
      proved reserves for properties owned by the PartnershipReserves
      at December 31, 2007
                  
                  
                  —
                  
                  
                  
                  —
                  
                  
                  
                  —Purchases
      of reserves in place
                  
                  
                  331,656
                  
                  
                  
                  224,048
                  
                  
                  
                  368,997Production
                  
                  
                  (23,354
                  )
                  
                  
                  (3,939
                  )
                  
                  
                  (24,010
                  )Reserves
      at December 31, 2008
                  
                  
                  308,302
                  
                  
                  
                  220,109
                  
                  
                  
                  344,987Revisions
      of previous estimates (3)
                  
                  
                  (160,667
                  )
                  
                  
                  (146,845
                  )
                  
                  
                  (185,141
                  )Production
                  
                  
                  (33,235
                  )
                  
                  
                  (7,204
                  )
                  
                  
                  (34,436
                  )Reserves
      at December 31, 2009
                  
                  
                  114,400
                  
                  
                  
                  66,060
                  
                  
                  
                  125,410


F-16


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


Notes to
Financial Statements (continued)





(1)
            Oil
      includes both oil and natural gas
liquids


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


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





Standardized
Measure of Discounted Future Net Cash Flows





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




For the
year ended December 31, 2009, future cash inflows are computed by applying the
new SEC pricing, which holds constant the un-weighted arithmetic average of the
first-day-of-the-month prices for crude oil and natural gas over the preceding
12-month period as the price basis for estimating the Partnership’s proved
reserves. For the year ended December 31, 2009, calculations were made using
average prices of $58.19 per barrel of crude oil and $1.57 per MCF of natural
gas. For the year ending December 31, 2008, future cash inflows were computed by
applying the former SEC pricing rules, which hold constant the end-of-year price
for crude oil and natural gas as the price basis for estimating the
Partnership’s proved reserves. During 2008, the calculations were made using
average prices of $45.13 per barrel of oil and $2.16 per MCF of natural
gas.  Prices and costs are held constant for the life of the wells,
however, prices are adjusted by well in accordance with sales contracts, energy
content quality, transportation, compression and gathering fees, and regional
price differentials.




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





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





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





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





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





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


F-17


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


Notes to
Financial Statements (continued)





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





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


F-18