UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~Form~~FORM 10-K

(Mark One)

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

For The Fiscal Year Ended December 31, ~~2013~~2014

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

For the Transition period from to

~~COMMISSION~~Commission ~~FILE~~File ~~NUMBER~~Number 000-53795

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

(Exact name of registrant as specified in its charter)

Texas

26-0805120

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

1901 N. Central Expressway, Suite 300, Richardson, TXTexas 75080-3610 ~~(Address of principal executive offices including zip code) (972) 437-6792 (Registrant’s telephone number, including area code)~~

(Address of principal executive offices including zip code)

(Registrant’s telephone number, including area code) – (972) 437-6792

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~~class)

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

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

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

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

As of March 31, ~~2014~~2015, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest and 0.6000 units of limited partner interest held by the managing general partner, and 396.4172 units of limited partner interest outstanding.

Documents incorporated by reference: None

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

ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, ~~2013~~2014

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Glossary of Oil and Gas Terms

Glossary of Oil and Gas Terms

Part I

Item 1.	Business
Item 1A.	Risk Factors
Item 1B.	Unresolved Staff Comments
Item 2.	Properties
Item 3.	Legal Proceedings
Item 4.	Mine Safety Disclosures

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures
Item 9B.	Other Information

PART III

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

PART IV

Item 15.	Exhibits and Financial Statement Schedules
	Signatures

Part I		4
Item 1.	Business	4
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
PART II		19
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	20
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosure About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	30
Item 9A.	Controls and Procedures	30
Item 9B.	Other Information	31
PART III		31
Item 10.	Directors, Executive Officers and Corporate Governance	31
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35
Item 13.	Certain Relationships and Related Transactions, and Director Independence	36
Item 14.	Principal Accountant Fees and Services	36
PART IV		37
Item 15.	Exhibits and Financial Statement Schedules	37
	Signatures	38

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Glossary of Oil and Gas Terms

The following is a description of the meaning of some of the oil and gas terms used throughout this Annual Report on Form 10-K for the period ended December 31, ~~2013~~2014 (the “Annual Report”):

Bbl: One stock tank barrel, or 42 U.S gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

BOE: Barrels of oil equivalent, with six thousand cubic feet (6 MCF) of natural gas being equivalent to one barrel of crude oil.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Developmental well: A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well: A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond its known horizon.

Horizontal drilling: A drilling technique used in certain formations whereby a well is drilled vertically to a certain depth and then drilled at an angle greater than 70 degrees from vertical for a specified interval.

Hydraulic fracturing: The process of creating and preserving a fracture or system of fractures in a reservoir rock, typically by injecting water, sand or chemicals under pressure through a wellbore and into the targeted formation.

Lease: Full or partial interest in (a) undeveloped oil and gas leases; (b) oil and gas mineral rights; (c) licenses; (d) concessions; (e) contracts; (f) fee rights; or (g) other rights authorizing the owner thereof to drill for, reduce to possession and produce crude oil and natural gas.

Mcf: One thousand cubic feet , used in reference to natural gas.

Organization and offering costs: All costs of organizing and selling the offering including, but not limited to, total underwriting and brokerage discounts and commissions, expenses for printing, engraving, mailing, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts, expenses of qualification of the sale of securities under federal and state law, including taxes and fees and accountants’ and attorneys’ fees and other front-end costs.

Net revenue interest: An owner’s interest in the revenues from a productive well after deducting proceeds allocated to royalty and overriding interests.

Prospect: A specific geographic area which, based upon supporting geological, geophysical, or other data and also preliminary analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved oil and gas reserves: The estimated quantities of crude oil, natural gas, and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known oil and gas reservoirs under existing economic conditions, operating methods, and government regulations (i.e. prices, costs, and government regulations as of the date the estimate is made). Depending on their status of development, proved reserves may be classified as either (1) Proved Developed Reserves or (202) Proved Undeveloped Reserves.

Proved developed oil and gas reserves: Reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This classification includes:

(1) Proved Developed Producing Reserves: Proved developed reserves which are expected to be produced from existing completion intervals now open for production in existing wells.

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(2) Proved Developed Non-Producing Reserves: Proved developed reserves which exist behind the casing of existing wells, or at minor depths below the present bottom of such wells, which are expected to be produced through those wells in a predictable future time, where the required completion or re-completion work prior to the start of oil and gas production is relatively small compared to the cost of a new well.

Proved undeveloped reserves: The proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units which are virtually certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

Undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, and natural gas, and natural gas liquids regardless of whether such acreage contains estimated proved reserves.

Working interest: The operating interest that gives the owner the right to drill, produce, and conduct operating activities on an oil and gas property and receive a share of production, and requires the owner to pay a share of the costs of drilling and production operations.

PART I

ITEM 1. BUSINESS

Introduction

Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) is a limited partnership formed under the laws of the state 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. Terms used in this Annual Report such as “we,” “us” or “our” refer to Reef.

The Partnership has sought to purchase working interests in oil and gas properties with both proved producing reserves and proved undeveloped reserves. Between ~~During the period from~~ November 27, 2007 ~~through~~and ~~the period ended~~ June 30, 2010, the Partnership made three major property acquisitions with the capital raised by the Partnership. These three acquisitions are referred to in this Annual Report as the Slaughter Dean acquisition, the Azalea acquisition, and the Lett acquisition (See ITEM 2 – PROPERTIES). On all properties purchased, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but not to engage in exploratory drilling for unproved reserves. Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef.

In instances where the percentage ownership of the Partnership in a property is large enough, Reef Exploration, L.P., an affiliate of Reef (“RELP”), serves as the property’s operator. RELP currently serves as operator of the wells acquired in the Slaughter Dean acquisition. All wells included in the Azalea and Lett acquisitions are operated by third parties not affiliated with the Partnership, Reef, or any other Reef affiliate. Other partnerships managed by Reef also own working interests in some of the properties acquired in the Azalea and Lett acquisitions. The Partnership operates in only one industry segment, which is the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGL’s”) in the United States.

~~Property~~As ~~Acquisition,~~a ~~Development~~result of the significant decline in crude oil prices that began during the third quarter of 2014 and has continued into the first quarter of 2015, the Partnership has delayed any attempt to sell the properties acquired in the Azalea and ~~Divestiture~~Lett acquisitions. The Partnership continues to pursue possible disposition of the Slaughter Dean acquisition properties (the “Slaughter Dean Properties”).

~~Slaughter Dean Acquisition~~3

The Slaughter Dean acquisition consisted of the purchase of a working interest in a producing oil property with approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. These wells are located in the Slaughter Field in Cochran County, Texas. Though the wells acquired in the Slaughter Dean acquisition had existing production, the acquisition was made primarily for the purpose of developing the field’s reserves by performing a waterflood development project in a portion of the field. The Slaughter Dean acquisition consisted of approximately 70 wells and 6,700 acres and produces crude oil and natural gas from the San Andres formation at depths from 5,000 to 5,500 feet. The major portions of the Slaughter Dean

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field were previously unitized for waterflood operations. During the period from 2008 through 2010, RELP, on behalf of the Partnership and other working interest owners, performed additional waterflood developmental work within the Slaughter Dean field in an attempt to increase the ultimate recovery of crude oil and natural gas from the field. The Slaughter Dean acquisition 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. Waterflood developmental activity was focused in the Dean “B” Unit. Several existing productive wells were converted into water injection wells, unit spacing was changed from 40 acres per well to 20 acres per well, and new production and injection wells were drilled within the new unit spacing. Some inactive water injection wells and marginal producing wells were also converted to water injection wells. New injection pumps were installed which enabled the unit to approximately triple its water injection capacity to over 6,000 barrels of water per day, in an attempt to pressurize the reservoir via water fill-up. The development work was performed during 2008 and 2009, and the additional injection capacity was added during the first quarter of 2010.

The actual results of the additional developmental work did not produce the desired production of additional oil. The waterflood activities described above temporarily reduced the rate of decline in oil production, but did not increase crude oil production as desired. Although significant crude oil reserves may remain in the reservoir, the effort to increase the waterflood response was determined to be unlikely to be effective in materially increasing the recovery of those reserves, based upon the results during 2010. The Partnership re-evaluated its reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean waterflood to determine what quantities of crude oil and natural gas reserves the Partnership could reasonably expect to recover from this reservoir under current economic and operating conditions. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood of $53,166,873 as of December 31, 2010.

RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) during 2011, 2012 and 2013, but no further developmental activities were performed during those years. Although the total water injection on a daily basis exceeds the fluids being removed from the reservoir, no noticeable increase in pressure or fluid production has been observed. During 2012, RELP ran injection profile logs on five of the current water injection wells hoping they might aid in determining if there is any work that might be performed on the injection wells to try and improve the waterflood pattern performance; however, the results of this work were inconclusive. While alternative configurations may improve waterflood results, the Partnership does not possess the capital required to implement a re-configuration of the waterflood. RELP continues to monitor waterflood operations and continues to operate the Slaughter Dean Project without any changes.

Azalea Acquisition

During January 2010, the Partnership acquired from RCWI, an affiliate of the Partnership, at cost, 61% of the working interests initially acquired by RCWI from Azalea Properties, Ltd. RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea acquisition included working interests in more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and also included undrilled infill and offset acreage on certain properties. The acquired working interests are all minority non-operated interests. The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef.

The Partnership has participated as a working interest owner in the drilling of additional developmental wells on some of the properties purchased, and during 2010 sold interests in certain acquired properties to other Reef affiliates when it was determined that additional drilling activities on such properties was not considered developmental. Additional property sales subsequent to 2010 are summarized below.

Lett Acquisition

During June 2010, the Partnership acquired from RCWI, at cost, working interests acquired by RCWI from Lett Oil & Gas, L.P. The Lett acquisition consisted of working interests in the Thums Long Beach Unit, a producing oil and gas property with approximately 870 producing wells and 485 injection wells. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The

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acquired working interests are all minority non-operated interests. The Thums Long Beach Unit is operated by a third party which is not an affiliate of the Partnership or Reef.

Sales of Interests — Thums Long Beach Unit

In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. These interests were initially acquired as part of the Lett Acquisition, and were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s credit agreement. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with these transactions.

Sales of Interests — Covington Prospect

In September 2012, the Partnership sold leasehold interests related to a three well drilling program in the Covington Prospect in Ward County, Texas proposed by a third party operator, to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“Reef 2012-A”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three proposed wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this sales transaction.

Sales of Interests — Carter County, Oklahoma

The Partnership sold its interest in two wells acquired as a part of the Azalea acquisition during the fourth quarter of 2013. The Partnership owned working interests of less than 2% in each well. The operator of these two properties received an offer from a third party interested in drilling new wells to a deeper horizon than the current wells. The operator notified the working interest partners of the offer, and the Partnership agreed to include the interests owned by the Partnership in the sale. The Partnership received approximately $191,000 for its interest in the two wells. The estimated discounted future net cash flows included in the Partnership’s 2012 reserve report for these two wells was less than $2,000. The Partnership utilized $170,000 of the proceeds to prepay principal under its existing credit agreement. The Partnership recorded no gain or loss related to this sales transaction.

Major Customers

The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, ~~2013~~2014, one marketer and one operator accounted for 3837.05% and 3236.80% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, ~~2012~~2013, one marketer and one operator accounted for 3438.60% and 2632.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, ~~2011~~2012, one marketer and one operator accounted for 34.96% and 2926.48% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

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Insurance

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

RELP has obtained various insurance policies, as described below, and intends to maintain such policies subject to its analysis of their premium costs, coverage and other factors. In the exercise of its fiduciary duty as managing general partner, Reef has obtained insurance on behalf of the Partnership to provide the Partnership with such coverage as 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 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 settled on at least 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.

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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 settled on at least a quarterly basis. However, in the event of a large insurance reimbursement being payable to the Partnership, the inter-company balance would be settled earlier, within a reasonable time after receipt of the insurance proceeds.

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

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

· 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.

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general partner of his intent to convert, Reef will amend the partnership agreement and will file the amendment with the State of Texas prior to the effective date of the change in insurance coverage. This amendment to the partnership agreement will effectuate the conversion of the interest of the former non-Reef general partner to that of a limited partner. Effecting conversion is subject to the express requirement that the conversion will not cause a termination of the partnership for federal income tax purposes. However, even after an election of conversion, a non-Reef general partner will continue to have unlimited liability regarding partnership activities while he was a non-Reef general partner.

Competition

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

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

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Markets

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

· the amount of crude oil and natural gas imports;

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

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

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

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

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

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated trade and investment barriers between the United States, Canada, and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before, FERC, as well as nondiscriminatory access requirements could further substantially increase the availability of natural 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 maintaining, reducing, or increasing certain price levels. Reef is unable to predict what effect, if any, such actions will have on both the price and volume of crude oil produced and sold from the Partnership’s wells.

In several initiatives, FERC has required pipeline transportation companies 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.

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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.

Production. 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. Among the ways that states control production is through regulations that establish the spacing of wells, or in some instances limit the number of days in a given month that a well is permitted to produce oil and gas.

Operators of oil and gas properties are required to have a number of permits to operate oil and gas 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 Partnership properties. 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.~~

Natural Gas Transportation and Pricing. FERC regulates the rates for interstate transportation of natural gas as well as the terms for access to natural gas pipeline capacity. Pursuant to the Wellhead Decontrol Act of 1989, however, FERC may not regulate the price of natural gas. Such deregulated natural gas production may be sold at market prices determined by supply and demand, Btu content, pressure, location of wells, and other factors. Reef anticipates that all of the natural gas produced by the Partnership’s wells will be considered price-decontrolled natural gas and that the Partnership’s natural gas will be sold at fair market value. However, while sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.6

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

Climate Change Legislation and Greenhouse Gas Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005 (the “Protocol”). Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol. However, the U.S. Congress is considering proposed legislation directed at reducing greenhouse gas emissions. In addition, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact the operations on wells by the Partnership. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the Partnership’s business.

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prohibitions were imposed on the Partnership for violating such regulations, the Partnership’s operations could be adversely affected.

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

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

Climate Change Legislation and Greenhouse Gas Regulation. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” (“GHG’s”) 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 oil, gas, and refined petroleum products, are considered GHG’s regulated by the Kyoto Protocol. The United States is currently not participating in the Kyoto Protocol.

While Congress has from time to time considered legislation to reduce emissions of GHG’s, there has not been significant activity in the form of adopted legislation to reduce GHG’s at the federal level in recent years. However, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHG’s. While it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact the Partnership, any such future laws and regulations that require reporting of GHG’s or limit emissions of GHG’s from oil and gas operations could require expenditure of funds to reduce such emissions, or, by affecting the demand for refined petroleum products, could affect demand for oil and gas produced from Partnership wells.

In January 2015, the Obama Administration announced its intent to directly regulate methane emissions from the oil and gas industry as a part of its climate change strategy. The EPA is expected to propose in 2015 and finalize during 2016 new regulations that will set methane emission standards aimed at having the oil and gas sector reduce its methane emissions levels by up to 40 to 50% from 2012 emissions levels by the year 2025. Such regulations could adversely affect the cost of the Partnership’s oil and gas operations.

Employees

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

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CAUTIONARY INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This Annual Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements; other than statements of historical fact, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. 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 and disposing of oil and gas properties;

· statements regarding the Partnership’s plans to develop the Slaughter Dean field, 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, our 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;

· statements regarding the timing of distributions

· 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 our investors. 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.” 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. All forward looking statements speak as of the filing date of this report. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. Reef does not intend to update its forward-looking statements, except as otherwise required by applicable law. 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.

10Continued low crude oil, natural gas and NGL prices may result in ceiling test impairments of our asset carrying values and have a material adverse effect on the Partnership.

The Partnership uses 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

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~~not~~exploration ~~currently~~and ~~known~~development activities are capitalized. The net capitalized costs of proved oil and gas properties are subject to usa quarterly “ceiling test” and are limited to the lower of the unamortized cost or the cost ceiling, defined as athe ~~result~~sum of ~~developments~~the ~~occurring~~estimated infuture net revenues from the ~~future,~~Partnership’s ~~conditions~~proved reserves using prices that weare ~~currently~~the ~~deem~~preceding to12-month beun-weighted ~~immaterial~~arithmetic ~~may~~average ~~also~~of ~~materially~~the first-day-of-the-month price for crude oil and ~~adversely~~natural ~~affect~~gas ~~our~~held ~~business~~constant and discounted at 10%, ~~financial~~plus ~~condition~~the lower of cost or estimated fair value of unproved properties, ~~cash~~if ~~flow~~any. Net capitalized costs in excess of the ceiling limit are charged as impairment expense against current earnings. Under full cost accounting rules, ~~and~~the ~~results~~ceiling test must be performed at the end of ~~operations~~each quarter. ~~Consequently~~ Without a substantial increase in crude oil and natural gas prices, ~~you~~a ~~should~~significant ~~not~~portion ~~consider~~of ~~this~~the ~~list~~Partnership’s toreserves may be rendered uneconomic to produce, resulting in significant downward adjustments to estimated proved reserves and estimated future net revenues. While impairment charges would not impact cash flow from operating activities, lower crude oil and natural gas prices could have a ~~complete~~significant ~~statement~~impact on revenues and operating cash flows. The combination of ~~all~~lower prices and property impairment could have a material adverse effect on the Partnership’s results of ~~our~~operations ~~potential~~in ~~risks~~the orperiod ~~uncertainties~~incurred and would reduce Partnership equity.

~~Oil~~During ~~and~~the ~~gas~~fourth ~~well~~quarter ~~drilling~~of is2014, the Partnership recorded impairment charges totaling $1,841,274, primarily resulting from a ~~speculative~~reduction ~~activity~~in ~~involving~~the ~~numerous~~oil ~~risks~~price differential received from production of the Partnership’s California properties. We expect to record additional impairment charges during the first quarter of 2015 directly related to the downturn in crude oil and ~~substantial~~natural gas prices that began during the third quarter of 2014. We estimate that the Partnership could record an additional ceiling test write down of between $2.5 and ~~uncertain~~$3.0 ~~costs~~million ~~which~~for the quarter ending March 31, 2015. Because future ceiling test calculations are based upon a rolling 12-month un-weighted arithmetic average of the first-day-of-the-month commodity prices, a period of continuing lower prices could ~~adversely~~also ~~affect~~result in additional impairment charges during the ~~Partnership~~remaining three quarters of 2015.

~~Drilling~~As ~~for~~a ~~oil~~result ~~and~~of ~~gas involves numerous risks, including~~ the ~~risk~~decline ~~that~~in noprices ~~commercially~~received ~~productive~~for our crude oil and~~/or~~ natural gas ~~reserves~~sales, ~~will be discovered. There can be no assurance that wells drilled by~~ the ~~Partnership~~results ~~will be productive or recover all or any portion~~ of ~~the~~our ~~investment~~operations infor ~~such~~2014 ~~wells. Drilling and completion costs are substantial and uncertain, and drilling operations~~ may not be ~~curtailed,~~indicative ~~delayed, or cancelled due to a variety~~ of ~~factors beyond~~ our ~~control,~~future ~~including~~results ~~shortages~~of oroperations ~~delays~~ in ~~the~~2015 ~~availability of drilling rigs~~ and ~~crews~~beyond, ~~unexpected~~as ~~drilling~~realized ~~conditions,~~prices ~~title~~for ~~problems,~~our ~~pressure~~production ormay ~~irregularities~~remain inlow ~~formations, equipment failures~~ or ~~accidents,~~continue adverse weather conditions, and compliance with environmental and other governmental regulations. Our drilling activities may not be successful and, if unsuccessful, will have an adverse effect on the Partnership’s results of operations and cash flow available for distribution to ~~the partners~~decline.

~~Oil~~Continued ~~and~~low crude oil, natural gas ~~investments~~and ~~are~~NGL ~~risky~~prices may necessitate the Partnership selling some of its assets in a down market, and failing to obtain a maximum return for the Partnership investors.

~~Although~~The sales price at which the Partnership’s ~~will~~crude oil, natural gas, and NGL production is sold has a significant impact on the Partnership’s sales revenue and operating cash flow. The Partnership has not ~~engage~~engaged in ~~any~~commodity ~~exploratory~~futures ~~drilling,~~trading ~~the~~or ~~acquisition~~hedging activities, ~~development~~ and ~~operation~~sells substantially all of its production on a month-to-month basis at current spot market prices. Should prices received from the sale of the Partnership’s oil and gas ~~properties~~production isfail ~~not~~to ancover ~~exact~~the ~~science~~operating and ~~involves~~administrative acosts ~~high~~of ~~degree~~the ofPartnership, ~~risk~~the managing general partner may need to temporarily advance funds to the Partnership. ~~The~~ ~~risks~~In order to repay such advances, the Partnership may be required to sell properties during a period of ~~acquiring~~lower prices, and may not obtain a maximum return to investors upon such property sales.

11Crude oil and natural gas prices are volatile, and fluctuate due to a number of factors outside of our control. A substantial and/or extended decline in crude oil and natural gas prices could have a material adverse effect on the Partnership.

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operating producing properties are generally less than those associated with the drilling of wells. Developmental drilling may result in dry holes or wells that do not produce crude oil or natural gas in sufficient quantities to make them commercially profitable to complete. The producing properties acquired by the Partnership may not produce sufficient quantities of crude oil or natural gas to enable an investor partner to obtain any certain projected rate of return on his or her investment, and it is possible that investor partners may lose money.

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

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, pollution, releases of toxic gas and other environmental hazards and risks. There are also hazards involved in the transportation of crude oil and natural gas from Partnership wells to market. Such hazards include pipeline leakage and risks associated with the spilling of oil transported by rail or barge instead of pipeline, both of which could result in liabilities associated with environmental cleanup. The Partnership could suffer substantial losses as a result of any of these risks. The Partnership is not fully insured against all risks inherent to the oil and gas business. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for the general partners. Although the Partnership maintains insurance coverage in amounts Reef deems appropriate, it is possible that insurance coverage may be insufficient. In that case Partnership assets may have to be sold to pay personal injury and property damage claims and the cost of controlling blowouts or replacing damaged equipment rather than for drilling activities. 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 investor general partners may be jointly and severally liable for such amounts.

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

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

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

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

· domestic government regulations and taxes;

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

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

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

· domestic and worldwide economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, crude oil and natural gas prices do not necessarily move in tandem. Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the amount of crude oil and natural gas that can be economically produced from successful wells drilled by the Partnership, and, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas reserves, and the carrying value of the Partnership’s oil and gas properties. Approximately 78.3% of the Partnership’s estimated proved reserves at December 31, 2013 were crude oil reserves, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.9

The Partnership, while not prohibited from engaging in commodity trading or hedging activities in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at

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~~December 31~~These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, ~~2013~~crude oil and natural gas prices do not necessarily move in tandem. ~~Accordingly~~Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the ~~Partnership~~amount isof atcrude ~~risk~~oil ~~for~~and natural gas that can be economically produced from successful wells drilled by the ~~volatility~~Partnership, inand, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas ~~prices~~reserves, and the ~~level~~carrying value of ~~commodity~~the ~~prices~~Partnership’s ~~has~~oil aand ~~significant~~gas ~~impact~~properties. ~~upon~~Approximately 82.8% of the Partnership’s estimated proved reserves at December 31, 2014 were crude oil reserves, and, as a result, financial results ofare ~~operations~~more sensitive to fluctuations in crude oil prices.

AThe ~~global~~Partnership, ~~economic~~while ~~downturn~~not ~~could~~prohibited ~~have~~from aengaging ~~material~~in ~~adverse~~commodity ~~impact~~trading onor ~~our~~hedging ~~financial~~activities ~~position~~in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at December 31, 2014, and sells substantially all of its crude oil and natural gas production at current spot market prices. Accordingly, the Partnership is at risk for the volatility in crude oil and natural gas prices, and the level of commodity prices has a significant impact upon the Partnership’s results of operations. A prolonged decline in crude oil and/or natural gas prices may materially and adversely affect the Partnership’s liquidity, the amount of cash ~~flows~~flow available for capital expenditures, operating expenses, and distribution to partners, and results of operations.

~~The~~Oil ~~oil~~ and gas ~~industry~~well drilling is cyclical and tends to reflect general economic conditions. The United States and other countries around the world experienced an economic downturn in 2008 and 2009 which had an adverse impact on demand and pricing for crude oil and natural gas. Another downturn similar to that experienced in 2008 and 2009 could lead to a ~~similar~~speculative ~~negative~~activity ~~impact~~involving onnumerous ~~crude~~risks ~~oil~~ and ~~natural~~substantial ~~gas prices or reduced demand for crude oil~~ and ~~natural~~uncertain ~~gas~~costs that could have a significant impact on the Partnership’s operating cash flows and profitability. Declines in crude oil and natural gas prices may also impact the value of our crude oil and natural gas reserves, which could ~~result~~adversely inaffect ~~future impairment charges to reduce~~ the ~~carrying value of the~~ Partnership~~’s oil and gas properties~~.

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

Oil and gas investments are risky.

Although the Partnership will not engage in any exploratory drilling, the acquisition, development and operation of oil and gas properties is not an exact science and involves a high degree of risk. The risks of acquiring and operating producing properties are generally less than those associated with the drilling of wells. Developmental drilling may result in dry holes or wells that do not produce crude oil or natural gas in sufficient quantities to make them commercially profitable to complete. The producing properties acquired by the Partnership may not produce sufficient quantities of crude oil or natural gas to enable an investor partner to obtain any certain projected rate of return on his or her investment, and it is possible that investor partners may lose money.

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

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have to be sold to pay personal injury and property damage claims and the cost of controlling blowouts or replacing damaged equipment rather than for drilling activities. 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 investor general partners may be jointly and severally liable for such amounts.

We cannot control activities on non-operated properties.

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

· timing and amount of capital expenditures; ~~· expertise and financial resources; · inclusion of other participants in drilling wells; and · the use of technology.~~

· expertise and financial resources;

· inclusion of other participants in drilling wells; and

· the use of technology.

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

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

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

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

Securities and Exchange Commission (“SEC”) rules require the Partnership to present annual estimates of reserves using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end 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.

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month period and year end 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.

Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

You should not assume the present value of future net cash flows referred to in this Annual Report to be the current market value of our estimated crude oil and natural gas reserves. The estimated discounted future net cash flows from our proved reserves as of December 31, ~~2013~~2014 are based upon the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month prices and year end costs. Actual current prices, as well as future prices and costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.

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costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.

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

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

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

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

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

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

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

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

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

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

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

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We face strong competition within the energy industry.

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

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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.

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

~~Net~~ In proceeds from the sale of units in the Partnership were used for the Slaughter Dean acquisition and the execution of the waterflood development work plan, including drilling new oil wells on the Dean “B” Unit and providing necessary production equipment and facilities to service such oil and gas wells. Net proceeds from the sale of units in the Partnership were also used in connection with the ~~Azalea~~Lett acquisition in ~~January 2010.~~June ~~However~~2010, the Partnership borrowed $5,000,000 ~~from~~under a ~~bank~~Credit inAgreement ~~connection~~ with ~~the~~Texas ~~Lett~~Capital ~~acquisition in June 2010. As of December 31~~Bank, ~~2013, the outstanding balance of these borrowings was $690,000~~N. 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 financingA. 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~~“TCB”) ~~or the sale of net profits interests or other operated or non-operating interests in properties~~. ~~This~~ ~~could~~The ~~result~~Partnership inmade ~~the~~its ~~Partnership~~final ~~giving~~payment upunder athis ~~substantial~~Credit ~~interest~~Agreement in ~~crude~~December ~~oil~~2014 and ~~natural~~terminated ~~gas reserves. If~~ the ~~Partnership~~Credit ~~sells~~Agreement ~~net~~on ~~profits~~December ~~interests in properties~~31, ~~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~~2014. 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.

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.

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~~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~~future 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.

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

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

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

Titles to the Partnership’s interest in the leases for the Slaughter Dean ~~field~~Properties and the Thums Long Beach Unit are held in the name of the Partnership. Under the purchase agreement with RCWI, ~~Agreement~~L.P. (“RCWI”), ~~title~~an affiliate of the Partnership, relating to the Azalea ~~acquisition~~Properties, ~~properties~~title to the Azalea Properties is held temporarily in the name of RCWI. When the Partnership acquires additional properties, title to those properties may be held temporarily in Reef’s name or in the name of one or more of Reef’s affiliates as nominee for the Partnership in order to facilitate the acquisition of properties by the Partnership and for other valid purposes. When this is the case, the Partnership runs the risk that the transfer of title could be set aside in the event of the bankruptcy of the party holding title. In this event, title to the leases and the wells would revert to the creditors or trustee, and the Partnership would either recover nothing or only the amount paid for the leases and the cost of drilling the wells. Assigning the leases to the Partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the Partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. See “ITEM 2. PROPERTIES — Title to Properties.”

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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.”

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

~~Drilling~~Property Acquisition, ~~Waterflood~~ Development Activities, and ~~Productive~~Divestiture ~~Wells~~of Certain Properties

~~The~~ Slaughter Dean acquisition included approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. Reef implemented a waterflood development plan on a portion of the Dean “B” Unit during 2008 and 2009, and upgraded water injection facilities during 2010. The Partnership spent a significant portion of its capital on the Slaughter Dean waterflood project.Acquisition

The Slaughter Dean acquisition included approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. These wells are located in the Slaughter Field in Cochran County, Texas. Reef implemented a waterflood development plan on a portion of the Dean “B” Unit during 2008 and 2009, and upgraded water injection facilities during 2010. The Partnership spent a significant portion of its capital on the Slaughter Dean waterflood project.

The drilling of new water injection wells and the conversion of a number of old already-producing oil wells to water injection wells was intended to increase the productivity of the project as a whole. The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil, thereby increasing the ultimate recovery of crude oil in the Dean “B” Unit.

While the waterflood development activity temporarily reduced the rate of decline in oil production, the desired increase in oil production rates did not materialize. As a result, as of December 31, 2010 the Partnership determined that the waterflood development work was unlikely to be effective in materially increasing the recoverable crude oil reserves that may remain in the reservoir. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood development project of $53,166,873 as of December 31, 2010 by re-classing this amount from unproved property to the proved property full cost pool, where it was subject to depletion and the full cost ceiling test for the year ended December 31, 2010. As a result of the ceiling test calculation, the Partnership recorded impairment expense totaling $57,944,024 in 2010, primarily resulting from this transfer of the Slaughter Dean waterflood project costs into the proved property full cost pool.

RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) ~~during~~subsequent ~~2011,~~to ~~2012 and 2013~~2010, but no further developmental activities ~~were~~have ~~performed~~been ~~during those years~~performed. Although the total water injection on a daily basis exceeds the fluids being removed from the reservoir, no noticeable increase in pressure or fluid production has been observed. During 2012, RELP ran injection profile logs on five of the current water injection wells hoping they might aid in determining if there is any work that might be performed on the injection wells to try and improve the waterflood pattern performance; however, the results of this work were inconclusive. While alternative configurations may improve waterflood results, the Partnership does not possess the capital required to implement a re-configuration of the waterflood. RELP continues to monitor waterflood operations and continues to operate the Slaughter Dean Properties without any changes.

16Azalea Acquisition

During January 2010, the Partnership acquired from RCWI, at cost, 61% of the working interests initially acquired by RCWI from Azalea Properties, Ltd. RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Properties included working interests in more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and also included undrilled infill and offset acreage on certain properties. The acquired working interests are all minority non-operated interests. The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef.

The largest property purchased in the Azalea acquisition is an interest in the Thums Long Beach Unit, which is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. Thums Long Beach has produced more than 940 million BOE from the Wilmington Field, and it is estimated it has in excess of 200 million barrels of oil equivalent remaining to be produced using current costs and pricing as of December 31, 2014. Thums Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell.

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~~operations~~Lett ~~and continues to operate the Slaughter Dean Project without any changes.~~Acquisition

~~The~~During ~~Partnership~~June ~~also~~2010, ~~owns~~the ~~non-operated~~Partnership ~~minority working interests in properties~~ acquired infrom ~~the Azalea and Lett acquisitions~~RCWI, ~~which~~at ~~consist of over 400 properties and more than 1~~cost,~~400~~ ~~wells~~working ~~located~~interests ~~in twelve states, which were~~ acquired inby ~~two~~RCWI ~~separate~~from ~~purchases~~Lett ~~completed~~Oil ~~during~~& ~~2010~~Gas, L. P. The ~~largest~~Lett ~~property~~Properties ~~purchased~~consisted inof ~~the~~working ~~Azalea~~interests ~~acquisition is an interest~~ in the Thums Long Beach Unit,. ~~which~~The isacquired aworking ~~long-lived~~interests ~~waterflood~~are ~~project~~all inminority ~~the~~non-operated ~~Wilmington~~interests. ~~Field,~~The ~~located underneath the Long Beach Harbor in southern California.~~ Thums Long Beach ~~has~~Unit ~~produced more than 930 BOE from the Wilmington Field, and it~~ is ~~estimated~~operated itby ~~has~~a inthird ~~excess~~party ofnot ~~200~~affiliated ~~million~~with ~~barrels of oil equivalent remaining to be produced using current costs and pricing as of December 31, 2013. Thums Long Beach derived its name from~~ the ~~property’s~~Partnership ~~original~~or ~~shareholders, Texaco, Humble, Union, Mobil and Shell~~Reef. ~~The only property acquired in the Lett acquisition was an additional interest in the Thums Long Beach Unit.~~

InSale ~~January 2011, the Partnership sold a portion~~ of ~~its~~Certain ~~interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. In June 2011, the~~ Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. These interests were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s credit agreement. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with this transaction.Properties

InThe ~~September 2012, the~~ Partnership sold ~~leasehold~~its ~~interests~~interest ~~related to a three well drilling program~~ in ~~the~~two ~~Covington~~wells ~~Prospect~~acquired inas ~~Ward County, Texas proposed by~~ a ~~third~~part ~~party~~of ~~operator,~~the toAzalea ~~Reef~~acquisition ~~2012-A~~during ~~Private~~the ~~Drilling~~fourth ~~Fund,~~quarter ~~L.P.,~~of ~~a Reef affiliate (“Reef 2012-A”)~~2013. The ~~estimated~~Partnership ~~drilling~~owned ~~cost~~working interests of ~~the~~less ~~three~~than ~~proposed~~2% ~~wells~~in toeach ~~the~~well. ~~Partnership~~The ~~was~~operator ~~in excess~~ of ~~$450,000,~~these ~~and~~two ~~the~~properties ~~Partnership~~received ~~would~~an ~~have~~offer ~~needed~~from toa ~~retain~~third ~~cash~~party ~~flow~~interested ~~from~~in ~~producing~~drilling ~~properties~~new ~~and~~wells ~~forego distributions~~ to ~~partners~~a ~~for~~deeper ~~several~~horizon ~~months~~than inthe ~~order~~current ~~to fund this drilling project~~wells. The ~~leasehold~~operator ~~acreage~~notified ~~sold~~the ~~also included one productive~~ working interest ~~well~~partners ~~and~~of ~~twelve~~the ~~productive~~offer, ~~royalty interest wells that currently produce oil~~ and ~~gas~~the ~~from~~Partnership ~~different~~agreed ~~geologic~~to ~~zones~~include ~~than~~ the ~~zone~~interests toowned beby ~~tested~~the Partnership in the ~~three proposed wells~~sale. The Partnership ~~recorded~~received approximately $~~138~~191,~~973~~000 asfor ~~accounts~~its ~~receivable~~interest ~~from~~in ~~affiliates~~these attwo ~~September 30,~~wells. ~~2012~~The ~~related~~estimated todiscounted ~~this~~future ~~transaction. During~~net ~~2012,~~cash ~~Reef~~flows ~~2012-A~~included ~~paid~~in ~~$93,451 to~~ the Partnership’s in2012 ~~connection~~reserve ~~with~~report ~~this~~for ~~sale,~~these ~~and~~two ~~the~~wells ~~Partnership~~was ~~had~~less athan ~~receivable of~~ $452,~~522 at December 31, 2012~~000. The ~~purchase and sale agreement called for the~~ Partnership toutilized ~~receive~~$170,000 ~~an amount equal to the value~~ of the ~~first~~proceeds ~~drilled~~to ~~well,~~prepay ~~based~~loan ~~upon~~principal aunder 12its ~~percent~~Credit ~~per~~Agreement ~~year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance~~ with ~~SEC~~TCB ~~regulations. This report was received~~ during ~~2013~~November ~~and the sales price was adjusted from $138,973 to $201,573~~2013. ~~The~~In ~~Partnership~~accordance ~~received~~with the ~~$45,522~~full ~~account~~cost ~~receivable,~~method ~~plus an additional payment~~ of ~~$62~~accounting,~~600~~ ~~from~~the ~~Reef~~Partnership ~~2012-A~~did innot ~~2013.~~record ~~The~~any ~~Partnership recorded no~~ gain or loss related to this ~~sales~~ transaction.

~~The~~During the second quarter of 2014, the Partnership sold its interest in ~~two~~several oil and gas wells acquired as a part of the Azalea acquisition ~~during~~for ~~the~~approximately ~~fourth~~$135,000. ~~quarter~~The ofestimated ~~2013.~~discounted ~~The~~future cash flows included in the Partnership’s ~~owned~~2013 ~~working~~reserve ~~interests~~report offor ~~less~~these ~~than~~wells 2%was inless ~~each~~than ~~well~~$45,000. The operator of ~~these~~the ~~two~~ properties ~~received~~notified anthe ~~offer~~Partnership ~~from~~of atheir ~~third~~intent ~~party~~to ~~interested~~form ina ~~drilling~~waterflood ~~new~~unit ~~wells~~ to abe ~~deeper~~implemented ~~horizon~~in ~~than~~three ~~the current wells~~phases. The ~~operator~~cost ~~notified~~of the ~~working~~initial ~~interest~~phase, ~~partners~~net ofto the ~~offer,~~working ~~and~~interest owned by the Partnership, ~~agreed~~was toapproximately ~~include~~$351,500, ~~the~~and ~~interests~~would ~~owned~~have byrequired the Partnership into ~~the~~pay ~~sale.~~these ~~The~~capital ~~Partnership~~costs, ~~received~~plus ~~approximately~~costs ~~$191,000~~associated ~~for~~with ~~its~~Phases ~~interest~~2 inand ~~the~~3, ~~two~~from ~~wells.~~current ~~The~~cash ~~estimated~~flows ~~discounted~~instead ~~future~~of ~~net~~distributing those cash flows ~~included~~to ininvestors. ~~the~~The Partnership’s ~~2012~~utilized ~~reserve~~the ~~report~~sales ~~for~~proceeds, ~~these~~as ~~two~~well ~~wells~~as ~~was~~current ~~less~~operating ~~than~~cash $2flow,~~000.~~ ~~The~~to ~~Partnership~~make ~~utilized~~a $~~170~~150,000 prepayment of ~~the~~loan ~~proceeds to prepay~~ principal under its ~~existing~~Credit ~~credit~~Agreement ~~agreement~~with TCB during June 2014. In ~~The~~accordance with the full cost method of accounting, the Partnership ~~recorded~~did nonot record any gain or loss related to this ~~sales~~ transaction.

The Partnership does not expect to purchase interests in any additional properties. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership receive proposals for new wells that are classified as exploratory wells, the Partnership may sell the acreage, along with any currently productive wells on the lease, to other Partnerships affiliated with Reef and RELP.

Proved Crude Oil and Natural Gas Reserves

Estimates of the Partnership’s proved reserves are prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014. All of the Partnership’s reserves are located in the United States.

17The estimated net proved crude oil and natural gas reserves at December 31, 2014, 2013, and 2012 are summarized below. Proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership can estimate with reasonable certainty to be economically producible in future years from known oil and gas reservoirs under existing economic conditions, operating methods, and government regulations. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

	Oil (BBL)	Gas (MCF)
Net proved reserves as of December 31, 2012	765,790	970,760
Net proved reserves as of December 31, 2013	544,000	905,950
Net proved reserves as of December 31, 2014	526,675	657,650

The standardized measure of discounted future net cash flows as of December 31, 2014, 2013, and 2012 is computed by applying the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period, 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.

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costs. The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2013. All of the Partnership’s reserves are located in the United States.

Standardized measure of discounted future net cash flows as of December 31, 2012	$	16,721,530
Standardized measure of discounted future net cash flows as of December 31, 2013	$	13,982,370
Standardized measure of discounted future net cash flows as of December 31, 2014	$	11,116,900

~~The~~During ~~estimated~~the ~~net~~year ~~proved~~ended ~~crude oil and natural gas reserves at~~ December 31, ~~2013,~~2014 ~~2012, and 2011 are summarized below. Proved crude oil and natural gas reserves discussed in this section include only~~ the ~~amounts which the~~ Partnership ~~can~~recorded ~~estimate~~property ~~with~~impairment ~~reasonable~~costs ~~certainty~~of toproved beproperties ~~economically~~totaling ~~producible in future years from known oil and gas reservoirs under existing economic conditions~~$1, ~~operating methods~~841, ~~and government regulations~~274. ~~Proved~~During ~~reserves include only quantities that~~ the ~~Partnership~~years ~~expects~~ended toDecember ~~recover commercially using current prices~~31, ~~costs~~2013, ~~existing regulatory practices,~~ and ~~technology. Therefore~~2012, ~~any~~the ~~changes~~Partnership inrecorded ~~future~~no ~~prices,~~property impairment costs, ~~regulations,~~of ~~technology or other unforeseen factors could materially increase or decrease the~~ proved ~~reserve estimates~~properties.

	Oil (BBL)	Gas (MCF)
Net proved reserves as of December 31, 2011	679,860	1,172,750
Net proved reserves as of December 31, 2012	765,790	970,760
Net proved reserves as of December 31, 2013	544,000	905,950

During 2013, the rate of decline in production from the wells in the Slaughter Dean field increased, and, as a result, reserve estimates were adjusted downward. Estimated proved reserves related to the Partnership’s working interest in the Slaughter Dean Properties at December 31, 2013 were estimated to be approximately 113,000 Bbl, compared to approximately 332,000 Bbl at December 31, 2012. During 2014, gas reserve estimates on the Dean B unit were adjusted downward by approximately 60,000 MCF, due to an increase in the decline rate of natural gas production form the lease. Adjustments to various Azalea Properties totaled approximately 96,000 MCF.

The standardized measure of discounted future net cash flows as of December 31, 2013, 2012, and 2011 is computed by applying the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period, 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, 2011	$	16,035,470
Standardized measure of discounted future net cash flows as of December 31, 2012	$	16,721,530
Standardized measure of discounted future net cash flows as of December 31, 2013	$	13,982,370

During the years ended December 31, 2013, 2012, and 2011, the Partnership recorded no property impairment costs of proved properties.

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

The Partnership used an independent petroleum engineering firm, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, ~~2013~~2014, ~~2012~~2013, and ~~2011~~2012 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, ~~2013~~2014, ~~2012~~2013 and ~~2011~~2012. The technical personnel responsible for preparing the reserve estimates at FGA meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. FGA is an independent firm of petroleum engineers and geologists. They do not own an interest in any of our properties, and are not employed on a contingent fee basis. FGA’s report was developed utilizing state reporting records and published production data purchased from third parties, and data provided by Reef. Their reserve summary, which contains further discussions of the reserve estimates and evaluations, as well as the qualifications of FGA’s technical personnel responsible for overseeing their estimates and evaluations, is included as Exhibit 99.1 to this Annual Report.

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

Reef maintains a staff of technical personnel who are well versed in the engineering evaluation computer programs and technology used and who provide well and production data to our independent petroleum engineering firm, FGA. Our accounting department accumulates historical production and pricing data and lease operating expenses for our wells, as well as the percentage interest owned by the Partnership, which is reviewed by our technical staff. Reserve estimates are prepared by FGA. Our technical staff and members of our accounting department meet regularly with FGA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. Jerald Sluder, Senior Reservoir Engineer for RELP, is primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Sluder has a B.S. in Petroleum Engineering, is a Registered Professional Engineer in the State of Texas and has over twenty years of industry experience in oil and gas operations. Mr. Sluder is an active member of the Society of Petroleum Engineers and of the Petroleum Engineers Club of Dallas. Any significant reserve changes are approved by Mr. Daniel C. Sibley, Chief Financial Officer and General Counsel of RELP, and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

1816

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for our wells, as well as the percentage interest owned by the Partnership, which is reviewed by our technical staff. Reserve estimates are prepared by FGA. Our technical staff and members of our accounting department meet regularly with FGA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. Jerald Sluder, Senior Reservoir Engineer for RELP, is primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Sluder has a B.S. in Petroleum Engineering, is a Registered Professional Engineer in the State of Texas and has over nineteen years of industry experience in oil and gas operations. Mr. Sluder is an active member of the Society of Petroleum Engineers and of the Petroleum Engineers Club of Dallas. Any significant reserve changes are approved by Mr. Daniel C. Sibley, Chief Financial Officer and General Counsel of RELP, and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.

Title to Properties

Title to the Partnership’s interest in the leases for the Slaughter Dean ~~wells~~Properties, the Thums Long Beach Unit, and certain Azalea ~~acquisition~~Properties ~~properties~~ is held in the name of the Partnership. Under the purchase agreement with RCWI ~~Agreement~~relating to the Azalea acquisition, title to certain properties is temporarily held in the name of RCWI. Upon acquiring properties, title to 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. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

AsUnits ~~of December 31, 2013, the Partnership had one managing general partner, 813 non-Reef general partners,~~ and 666 non-Reef limited partners. Reef holds a total of 8.9697 general partner units and 0.6000 limited partner units, and the non-Reef partners hold 490.9827 general partner units and 396.4172 limited partner units. No established trading market exists for the units, and there is no unit repurchase program available to investor partners under the terms of the Partnership Agreement.Holders

~~Cash~~As ~~which~~of December 31, in2014, the ~~sole~~Partnership ~~judgment~~had one managing general partner, 816 non-Reef general partners, and 666 non-Reef limited partners. Reef holds a total of 8.9697 general partner units and 0.6000 limited partner units, and the ~~managing~~non-Reef partners hold 490.9827 general partner, isunits ~~not~~and ~~required~~396.4172 tolimited ~~meet~~partner units. No established trading market exists for the ~~Partnership’s~~units, ~~obligations~~and there is ~~available~~no ~~for~~unit ~~distribution~~repurchase program available to ~~the~~investor partners atunder ~~least~~the ~~quarterly~~terms inof ~~accordance with~~ the Partnership Agreement.

19Investor 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.

Distributions

Cash which, in the sole judgment of the managing general partner, is not required to meet the Partnership’s obligations, is available for distribution to the partners at least quarterly in accordance with the Partnership Agreement. The Partnership has made cash distributions to the partners of crude oil and natural gas sales revenues, less operating, general and administrative, and other costs since January 2008. Cash distributions were previously distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. Thus, effective October 1, 2013 Reef also receives 0.06% of the distributions paid to investor partners. As such, Reef currently receives 11.06% and investor partners receive 88.94% of total cash distributions. Total cash distributions paid during 2014, 2013, and 2012 were $170,871, $682,835, and $655,321, respectively. The Partnership’s Credit Agreement, which was terminated as of December 31, 2014, contained certain restrictions on distributions, including the absence of default as defined by the credit agreement, the maintenance of a minimum cash balance, and a maximum amount to be distributed based on certain other calculations described in the credit agreement.

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Agreement. The Partnership has made cash distributions to the partners of crude oil and natural gas sales revenues, less operating, general and administrative, and other costs since January 2008. Cash distributions were distributed 11% to Reef and 89% to investor partners. During 2013, Reef purchased 0.60 units of limited partner interest from one of the investor partners (representing 0.067% of investor partner units.). Thus, effective October 1, 2013 Reef also holds 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units, and receives 0.060% of the distributions paid to investor partners. The Partnership’s credit agreement contains certain restrictions on distributions, including the absence of default as defined by the credit agreement, the maintenance of a minimum cash balance, and a maximum amount to be distributed based on certain other calculations described in the credit agreement. Cash distributions paid during 2013, 2012, and 2011 were $682,835, $655,321, and $867,371, respectively.

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

Use of Proceeds

Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, with a maximum offering amount of $90,000,000 (900 units). Reef Securities, Inc., an affiliate of Reef, served as the dealer manager for the private placement. An amount equal to 15% of the proceeds realized from the sale of interests to investors was paid to Reef as a management fee. Reef paid all organization and offering costs of the Partnership, including sales commissions, from this amount. The remaining 85% of the proceeds has been expended on the Slaughter Dean, Azalea, and Lett acquisitions, the waterflood development project at Slaughter Dean and drilling of developmental wells upon acreage purchased in connection with the Azalea acquisition, and payment of additional fees owed to Reef as a result of such activities. On June 12, 2008, the offering of units of general and limited partner interests in the Partnership 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 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 payment of the 15% management fee used by Reef to pay 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, 2013, the Partnership had expended $57,328,179 on acquisition and development of the Slaughter Dean wells, $16,270,856 on the acquisition and development of the Azalea properties, and $6,901,254 on the acquisition and development of the Lett properties, prior to sales of the Partnership’s interests or portions of its interests in certain properties. The Partnership has no current plans to purchase additional oil and gas properties.

Expenditures in excess of available capital have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial and operating 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,
Financial Data	2014			2013			2012			2011			2010

Revenue	$	4,234,581		$	5,112,482		$	5,830,997		$	6,048,932		$	5,599,090
Costs and expenses	(6,695,687		)	(4,620,409		)	(4,939,658		)	(5,786,568		)	(65,305,926		)
Other expense	(32,764		)	(70,773		)	(105,339		)	(174,257		)	(133,068		)
Net income (loss)	(2,493,870		)	421,300			786,000			88,107			(59,839,904		)

Allocation of net income (loss):
Managing general partner	29,212			156,604			208,709			112,569			(588,353		)
General partner	(1,395,034		)	146,353			319,189			(13,525		)	(32,760,687		)
Limited partner	(1,128,048		)	118,343			258,102			(10,937		)	(26,490,864		)
Net income (loss) per managing partner unit	3,256.80			17,459.23			23,268.23			12,549.94			(65,593.41		)
Net income (loss) per general partner unit	(2,841.31		)	298.08			650.10			(27.55		)	(66,724.73		)
Net income (loss) per limited partner unit	(2,841.31		)	298.08			650.10			(27.55		)	(66,724.73		)

Total assets	11,668,595			14,949,750			15,737,217			15,522,756			18,362,120
Long-term liabilities	2,528,422			2,793,175			2,366,899			3,240,115			5,653,946
Distributions to managing general partner	18,898			75,112			72,085			107,464			101,085
Distributions to general partners	84,027			336,015			322,476			420,159			512,791
Distributions to limited partners	67,946			271,708			260,760			339,748			414,650
Distributions per managing general partner unit	2,106.87			8,373.97			8,036.50			11,980.78			11,269.61
Distributions per general partner unit	171.14			684.37			656.80			855.75			1,044.42
Distributions per limited partner unit	171.14			684.37			656.80			855.75			1,044.42

Operating Data (unaudited)
Annual sales volume:
Gas (MCF)	92,149			93,936			138,956			127,039			190,208
Oil (BBL)	47,555			52,584			61,718			62,255			66,352

Average sales price:
Gas (per MCF)	$	4.14		$	3.89		$	3.40		$	4.70		$	4.66
Oil (per BBL)	$	81.01		$	90.27		$	86.82		$	87.58		$	71.04

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	As of and For the Years Ended December 31,
	2013			2012			2011			2010			2009
Revenue	$	5,112,482		$	5,830,997		$	6,048,932		$	5,599,090		$	1,655,812
Interest income	—			—			—			3,490			140,471
Miscellaneous income	463			69			—			—			—
Costs and expenses	(4,691,645		)	(5,045,066		)	(5,786,568		)	(65,305,926		)	(3,343,360		)
Net income (loss)	421,300			786,000			88,107			(59,839,904		)	(1,547,077		)
Allocation of net income (loss):
Managing general partner	156,604			208,709			112,569			(588,353		)	(70,841		)
General partner	146,353			319,189			(13,525		)	(32,760,687		)	(816,223		)
Limited partner	118,343			258,102			(10,937		)	(26,490,864		)	(660,013		)
Net income (loss) per managing partner unit	17,459.23			23,268.23			12,549.94			(65,593.41		)	(7,897.79		)
Net income (loss) per general partner unit	298.08			650.10			(27.55		)	(66,724.73		)	(1,662.43		)
Net income (loss) per limited partner unit	298.08			650.10			(27.55		)	(66,724.73		)	(1,662.43		)
Total assets	14,949,750			15,737,217			15,522,756			18,362,120			74,855,409
Long-term liabilities	2,793,175			2,366,899			3,240,115			5,653,946			248,912
Distributions to managing general partner	75,112			72,085			107,464			101,085			49,050
Distributions to general and limited partners	607,723			583,236			759,907			927,441			362,131
Distributions per managing general partner unit	8,373.97			8,036.50			11,980.78			11,269.61			5,468.41
Distributions per general partner unit	684.37			656.80			855.75			1,044.42			407.81
Distributions per limited partner unit	684.37			656.80			855.75			1,044.42			407.81
Operating Data
Annual sales volume:
Gas (MCF)	93,936			138,956			127,039			190,208			7,204
Oil (BBL)	52,584			61,718			62,255			66,352			33,235
Average sales price:
Gas (per MCF)	$	3.89		$	3.40		$	4.70		$	4.66		$	1.49
Oil (per BBL)	$	90.27		$	86.82		$	87.58		$	71.04		$	49.50

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.

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

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Critical 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 judgments that affect the reported amounts ~~reported~~of inassets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and ~~accompanying~~the ~~notes~~reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.

Management is 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 ~~its~~ oil and gas ~~activities~~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 barrels of oil equivalent (“BOE”) at a rate of 6 Mcf to 1 Bbl. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

In applying the full cost method, the Partnership isperforms ~~required to 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 lower of unamortized cost or the cost ceiling, which is defined as the sum of the estimated future net revenues from the Partnership’s proved reserves using prices that are the preceding 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. 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. During the ~~years~~year ended December 31, ~~2013~~2014, ~~2012~~the Partnership recognized $1,841,274 of impairment expense of proved properties. During the years ended December 31, 2013, and ~~2011~~2012, the Partnership recognized no property impairment expense of proved properties.

Unproved property consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea ~~properties~~Properties in 2010. Investments in unproved ~~properties~~property are not ~~depleted~~subject ~~pending~~to ~~determination~~depletion ofuntil ~~the~~they ~~existence~~are ofeither ~~proved~~impaired ~~reserves~~or developed. Unproved ~~properties~~property ~~are~~is assessed for impairment quarterly as of the balance sheet date. ~~The~~In ~~assessment~~determining ~~includes~~whether ~~consideration~~an ofunproved property is impaired, the ~~following~~Partnership considers numerous factors including, ~~among~~but ~~others~~not limited to, the following items: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property;, ~~and~~ geological and geophysical evaluation and current market conditions. To the extent that the assessment indicates a property is impaired, the impairment amount ofis ~~impairment~~re-classed isfrom ~~added~~unproved property to the ~~capitalized~~proved ~~costs~~property offull ~~oil~~cost pool and ~~gas~~subjected to depletion and the quarterly full cost ceiling test. After considering the holding period of the Azalea unproved properties ~~which~~as ~~are~~well ~~subject~~as current market conditions at December 31, 2014, the Partnership impaired unproved property totaling $361,865 during the fourth quarter of 2014. This amount was re-classed from unproved property to the ~~quarterly~~proved property full cost pool and subjected to depletion and the full cost ceiling test at December 31, 2014. During the years ended December 31, 2013, ~~2012,~~ and ~~2011~~2012, the Partnership recognized no ~~property~~ impairment ~~expense~~ of unproved ~~properties~~property.

The Partnership expects that all of its unproved property costs at December 31, 2013 will be drilled and transferred to proved property cost within 10 years of acquisition. All unproved property cost not being amortized as of December 31, 2013 was incurred during the year ended December 31, 2010.

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Estimates of Proved Oil and Gas Reserves

The estimate of the Partnership’s proved reserves at December 31, ~~2013~~2014 was prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by FGA, an independent petroleum engineering firm.

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.19

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knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

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 future net income. A decline in estimated proved reserves and future cash flows, whether caused by declining commodity prices or downward adjustments to the rate of production from Partnership wells, also reduces the capitalized cost ceiling and may result in increased impairment expense.

Asset Retirement Obligation

The Partnership has recognized an estimated liability for future well plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.

The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.

~~During 2011, the Partnership plugged and abandoned seven wells located in the Slaughter Dean Field.~~ The ~~costs~~following ~~associated~~table ~~with~~summarizes the ~~plugging operation exceeded the~~ Partnership’s ~~recorded~~ asset retirement obligation, and approximately $62,000 of plugging and abandonment cost was recorded as lease operating expenses on the 2011 statement of operations. The Partnership determined that its estimated asset retirement obligation for the ~~Slaughter~~periods ~~Dean~~ended ~~wells~~December ~~(approximately 145 wells) was understated~~31, ~~and,~~2014 ~~in that regard, the Partnership increased the basis of the Slaughter Dean wells by $860,878~~ and ~~recorded additional asset retirement obligation of this amount as a change in estimate~~2013.

During 2012, the Partnership plugged and abandoned three wells located in the Slaughter Dean Field. Approximately $27,362 of plugging and abandonment costs related to these three wells were applied against the Partnership’s asset retirement obligation shown on the accompanying balance sheet, and approximately $88,000 was recorded as lease operating expenses on the 2012 statement of operations. The Partnership received lower bids for providing plugging services from two other third party vendors; however, those vendors could not schedule the services prior to the regulatory deadlines imposed by the state. Based upon the bids received from the other two vendors, the Partnership did not revise its estimated asset retirement liability for the other wells in the Slaughter Dean Field.

	2014			2013
Beginning asset retirement obligation	$	2,463,175		$	2,366,899
Additions related to new properties	2,014			2,683
Retirement related to sale and disposition of proved properties	(4,692		)	(5,859		)
Retirement related to property abandonment and restoration	(95,565		)	(55,893		)
Accretion expense	163,490			155,345
Ending asset retirement obligation	$	2,528,422		$	2,463,175

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The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2013 and 2012.

	2013			2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	2,683			7,579
Revisions related to existing properties	—			438,610
Retirement related to property sales	(5,859		)	(1,605		)
Retirement related to property abandonment and restoration	(55,893		)	(32,388		)
Accretion expense	155,345			119,588
Ending asset retirement obligation	$	2,463,175		$	2,366,899

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 Partnership’s share of 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, ~~2013~~2014, ~~2012~~2013 and ~~2011~~2012, the Partnership had no material gas imbalance positions.

Recent Accounting Developments

The following recently issued accounting pronouncement has been adopted or may impact the Partnership in future periods:

Revenue Recognition. The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenues arising from contracts to provide goods or services to customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following five steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract(s); (5) recognize revenue when (or as) the entity satisfies a performance obligation. The requirements from the new ASU will supersede prior revenue recognition requirements and most prior industry-specific guidance throughout the FASB’s ASC, and will be effective for all interim and annual periods beginning after December 15, 2016. The Partnership is still considering the method of adoption but does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flow.

Overview

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

On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but will not engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations. Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef. In 2010, after expending funds on a major waterflood development project located on the Dean “B” Unit, a portion of the Partnership’s Slaughter Dean acquisition, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood of $53,166,873. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership decide to participate in such developmental drilling, funds to drill are taken from current net cash flows available for distributions to investors. The Partnership does not expect to purchase interests in any additional properties.

The Partnership owns interests in over 1,500 wells located in twelve states. The management of the operations and other business of the Partnership is the responsibility of Reef. RELP, an affiliate of Reef, serves as operator of the Partnership’s Slaughter Dean wells. All properties associated with the Azalea and Lett acquisitions are operated by third party operators not affiliated with Reef or any of Reef’s affiliates. The Partnership does not operate in any other industry segment.20

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

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reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership decide to participate in such developmental drilling, funds to drill are taken from current net cash flows available for distributions to investors. The Partnership does not expect to purchase interests in any additional properties.

The Partnership made three major property acquisitions, referred to as the Slaughter Dean acquisition, Azalea acquisition, and Lett acquisition, and owns interests in over 1,500 wells located in twelve states. The management of the operations and other business of the Partnership is the responsibility of Reef. RELP, an affiliate of Reef, serves as operator of the Partnership’s Slaughter Dean Properties. All properties associated with the Azalea and Lett acquisitions are operated by third party operators not affiliated with Reef or any of Reef’s affiliates. The Partnership does not operate in any other industry segment.

The Partnership has expended all of the capital it raised on the Slaughter Dean, Azalea, and Lett acquisitions, and upon developmental drilling opportunities on infill and offset acreage acquired in connection with the Azalea acquisition. The Partnership does not expect to add significant additional reserves either by acquisition or drilling. Partnership production is expected to decline based upon the natural decline rates of its current producing properties. The original objective of the Partnership was to sell its properties no later than 2015 in order to maximize the rate of return to investors. However, the significant decline in crude oil prices that began during the third quarter of 2014 has significantly impacted the potential sales prices for the Partnership’s oil and gas properties. During 2014, the NYMEX future spot price for oil averaged $92.91 per barrel, however, the NYMEX future spot price for oil closed on December 31, 2014 at $53.27 per barrel. Prices have hovered near or below this level throughout the first quarter of 2015, with the NYMEX future spot price for oil closing at $48.29 on March 10, 2015.

In light of current market conditions, the Partnership has delayed any attempt to sell the properties acquired in the Azalea and Lett acquisitions. The Partnership is pursuing possible disposition of the Slaughter Dean Properties. The waterflood development project has not proven to be successful, the field has exhibited higher operating costs and also has had high workover costs on the 100+ wells in the field.

The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. See “Item 7A — Quantitative and Qualitative Disclosure About Market Risk.” While oil and gas sales revenues began declining during the third quarter of 2014, the full impact of the decline in prices will not be felt until the first quarter of 2015 and beyond. The significant declines in prices for oil and gas will have a material effect on our financial condition, results of operations, cash flows, and quantities of reserves that are economically recoverable. The Partnership expects the first quarter ceiling test to result in an impairment write down of approximately $2.5 to $3.0 million in property value. If oil and gas prices remain depressed for a significant period of time, the Partnership may not be able to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.

Liquidity and Capital Resources

Capital Contributions

The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef. Non-Reef partners purchased 490.9827 units of general partner interest and 397.0172 units of limited partner interest 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 units of general partner interest at a price of $85,000 per unit, which is net of the 15% management fee paid by non-Reef investors. The 15% management fee used to pay organization and offering costs, including sales commissions, totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of December 31, ~~2013~~2014, the Partnership had expended $57,~~328~~318,~~179~~891 on acquisition and development of the Slaughter Dean ~~wells~~Properties, $16,~~270~~532,~~856~~120 on the acquisition and development of the Azalea ~~properties~~Properties, and $67,~~901~~201,~~254~~297 on the acquisition and development of the Lett ~~properties, prior to sales of the Partnership’s interests or portions of its interests in certain properties~~Properties. Expenditures in excess of available capital have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

~~Credit Agreement~~21

On June 30, 2010, the Partnership and Texas Capital Bank, N.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding the Lett acquisition. The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. At December 31, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable. The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans. At December 31, 2013, the borrowing base and the current outstanding loan balance are $690,000, and the borrowing base reduces at a rate of $30,000 per month. Therefore, the Partnership has recognized $360,000 of the note payable balance due as a current liability on the accompanying balance sheet. The Partnership has no plans to request any additional borrowing or changes to the borrowing base, and does not expect to extend the term of the loan beyond its current expiration date of June 30, 2015. The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty. During 2013, the Partnership made prepaid principal payments totaling $265,000, in addition to $360,000 in regularly scheduled principal balance reductions.

The Partnership has paid TCB certain facility fees and engineering fees in connection with prior year redeterminations of the borrowing base. The Partnership is obligated to pay additional facility fees upon each determination of an increase in the borrowing base, and additional engineering fees if TCB’s internal engineers perform an engineering review of the collateral, or the actual fees and expenses of any third-party engineers retained by TCB to prepare an engineering report, payable at the time of a redetermination of the borrowing base. The Partnership has no plans to request a redetermination of the borrowing base. The fees paid in connection with prior borrowing base redeterminations have been capitalized by the Partnership as Deferred Financing Fees on the accompanying balance sheets, and are being amortized over the remaining term of the Credit Agreement.

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

On April 30, 2013, the Partnership entered into the Third Amendment to the Credit Agreement (“Third Amendment”), with TCB. The Third Amendment extended the final maturity date of the Credit Agreement and the obligations thereunder from June 30, 2013 to June 30, 2015. During May 2013, the Partnership paid TCB fees of $13,150 in connection with the Third Amendment. These fees, as well as attorney fees paid in connection with the Third Amendment, have been capitalized as Deferred Financing Fees on the accompanying balance sheet and are being amortized over the remaining term of the Credit Agreement.

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~~The~~ Credit Agreement contains various covenants, including among others restrictions on distributions and liens, incurring other indebtedness, and the maintenance of a certain current ratio and interest coverage ratio. At December 31, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into a Partnership bank account maintained at the lender. A waiver of this requirement has been obtained.

~~Please~~On ~~see~~June ~~Item~~30, 1A2010, ofthe ~~this~~Partnership ~~Annual~~and ~~Report~~TCB entered into a Credit Agreement with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding a ~~list~~property acquisition. The per annum interest rate was equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of ~~risk~~5%, ~~factors~~payable ~~that~~monthly. The ~~could~~obligations ~~impact~~of TCB to the Partnership under the Credit Agreement were to expire on June 30, 2015, at which point the promissory note was to mature, and any unpaid principal and interest would have become due and payable. The Credit Agreement was a reducing revolving credit facility, and was subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.

The Partnership had the right to prepay promissory note principal and accrued interest thereon in whole or in part at any time without premium or penalty. During 2014, the Partnership made various pre-payments of principal on the promissory note, utilizing proceeds from property sales and current cash flows. The Partnership completed repayment of the promissory note balance during December 2014 and terminated the Credit Agreement with TCB on December 31, 2014.

The Partnership paid TCB certain facility fees and engineering fees in connection with prior year redeterminations of the borrowing base. The fees paid in connection with these prior borrowing base redeterminations were capitalized by the Partnership as Deferred Financing Fees and amortized over the term of the Credit Agreement.

Capital Expenditures

~~The~~As ~~table~~of ~~below~~December 31, ~~summarizes~~2014, the Partnership ~~expenditures~~had ~~for~~expended $81,052,308 on property ~~purchases,~~acquisition and development costs. Of this amount, ~~and~~$57,318,891 ~~waterflood~~has ~~enhancement~~been byexpended ~~type~~on the Slaughter Dean Properties, $16,532,120 has been expended on the Azalea Properties, and ~~classification~~$7,201,297 ofhas ~~wells~~been asexpended on the Lett Properties. Expenditures in excess of ~~December 31~~available Partnership capital, ~~2013:~~which totaled $76,242,425, have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs
Purchase Existing Wells	$	35,496,694	$	—	$	—	$	35,496,694
New Wells
Producing Wells	34,126		30,039,511		—		30,073,637
Waterflood Injector Wells	—		5,149,620		—		5,149,620
Facilities	—		1,795,397		—		1,795,397
Existing Wells	—		—		7,076,418		7,076,418
	$	35,530,820	$	36,984,528	$	7,076,418	$	79,591,766

At December 31, 2010, the Partnership fully impaired its unproved properties associated with the Slaughter Dean waterflood project totaling $53,166,873. This amount was re-classed from unproved property to the proved property full cost pool, where it was subject to depletion and the full cost ceiling test for the year ended December 31, 2010. As a result of the ceiling test calculation, the Partnership recorded impairment expense totaling $57,944,024 in 2010, primarily resulting from this transfer of the Slaughter Dean waterflood project costs into the proved property full cost pool.

~~The~~Unproved ~~table~~property ~~below~~on ~~summarizes~~the Partnership ~~expenditures~~balance sheet consists of undrilled infill and offset acreage obtained in connection with the Azalea acquisition during 2010. The Partnership allocated $2,486,463 of the purchase price paid for the Azalea Properties in January 2010 as unproved property. ~~purchases~~Subsequent to 2010, ~~development~~the Partnership has sold portions of this unproved property due to intended exploratory drilling activities or because drilling costs of proposed wells on the unproved property were high enough that the Partnership would be forced to forego distributions to partners for several months in order to fund the proposed drilling project from existing cash flows. In addition, ~~and~~the ~~waterflood~~Partnership ~~enhancement~~has transferred amounts from unproved property to proved property as wells have been drilled by ~~type~~the ~~and~~various ~~classification~~operators of the Azalea Properties subsequent to 2010. After considering the holding period of the remaining Azalea unproved properties as well as current market conditions at December 31, 2014, the Partnership recognized impairment of unproved property totaling $361,865 during the fourth quarter of 2014. This amount was re-classed from unproved property to the proved property full cost pool, where it was subject to depletion and the full cost ceiling test for the year ended December 31, ~~2012:~~2014.

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs
Purchase Existing Wells	$	35,471,836	$	—	$	—	$	35,471,836
New Wells
Producing Wells	33,682		29,479,230		—		29,512,912
Waterflood Injector Wells	—		5,149,620		—		5,149,620
Facilities	—		1,795,397		—		1,795,397
Existing Wells	—		—		7,076,418		7,076,418
	$	35,505,518	$	36,424,247	$	7,076,418	$	79,006,183

The Partnership has expended $57,328,179 (included in the expenditures shown in the tables above) on the Slaughter Dean wells as of December 31, 2013. At December 31, 2010, the Partnership fully impaired its unproved properties associated with the Slaughter Dean wells by recognizing $53,166,873 of property impairment expense.

At December 31, 2013 and 2012, unproved property on the Partnership balance sheet consists of undrilled infill and offset acreage obtained in connection with the Azalea acquisition. The Partnership acquired $2,486,463 of unproved

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~~properties during the year ended December 31, 2010 related to the Azalea acquisition.~~ The ~~Partnership~~table ~~sold~~below ~~portions~~summarizes of this unproved property in December 2010 due to intended or in-process exploratory drilling activities, and sold portions of this unproved property in September 2012 because drilling costs of the proposed wells would have necessitated the Partnership ~~foregoing~~activity ~~distributions~~related to ~~partners for several months in order to fund the proposed drilling project. In addition, the Partnership transfers portions of~~ unproved properties toduring ~~proved properties as~~ the ~~related~~year ~~wells~~ended ~~from~~December ~~the~~31, ~~unproved properties are drilled by the various operators of the Azalea acquisition properties.~~2014:

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2013:

	Azalea Properties			Total Costs
Beginning balance	$	389,672		$	389,672
Transfers to proved properties	(27,807		)	(27,807		)
Impairments moved to proved property	(361,865		)	(361,865		)
Ending balance	$	—		$	—

	Azalea Acquired Properties			Total Costs
Beginning balance	$	524,357		$	524,357
Transfers to proved properties	(134,685		)	(134,685		)
Sales of unproved properties	—			—
Ending balance	$	389,672		$	389,672

The table below summarizes Partnership activity related to unproved properties during the year ended December 31, 2013:

The table below summarizes Partnership activity related to unproved properties by project during the year ended December 31, 2012:

	Azalea Properties			Total Costs
Beginning balance	$	524,357		$	524,357
Transfers to proved properties	(134,685		)	(134,685		)
Ending balance	$	389,672		$	389,672

	Azalea Acquired Properties			Total Costs
Beginning balance	$	1,708,425		$	1,708,425
Transfers to proved properties	(1,172,792		)	(1,172,792		)
Sales of unproved properties	(11,276		)	(11,276		)
Ending balance	$	524,357		$	524,357

The Partnership had working capital of $534,972 at December 31, 2014. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the Partnership working capital consists primarily of cash flows from productive properties, which have been utilized to pay cash distributions to investors. Sources of future funding consist of cash on hand, cash flow from operations, and sales of properties. The Partnership may not be able to sell properties at the values desired. As a result, the Partnership’s future ability to participate in the further development of properties in which the Partnership holds an interest may be restricted, unless the Partnership chooses to utilize cash flows from operations available for distributions to investors.

The Partnership had working capital of $802,876 at December 31, 2013. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the Partnership working capital consists primarily of cash flows from productive properties, which have been utilized to pay cash distributions to investors. Sources of future funding consist of cash on hand, cash flow from operations, and sales of properties. The Partnership may not be able to sell properties at the values desired. As a result, the Partnership’s future ability to participate in the further development of properties in which the Partnership holds an interest may be restricted, unless the Partnership chooses to utilize cash flows from operations available for distributions to investors.

Results of Operations

Year Ended December 31, 2014 compared to Year Ended December 31, 2013

The Partnership had a net loss of $2,493,870 for the year ended December 31, 2014, compared to net income of $421,300 for the year ended December 31, 2013. The primary change in operating results is primarily due to impairment of proved properties during the year ended December 31, 2014. In addition, decreases in average sales prices for crude oil and increases in lease operating expenses contributed to the loss for the year ended December 31, 2014 as compared to the year ended December 31, 2013.

During the year ended December 31, 2014, the Partnership recognized impairment expense of $1,841,274. The impairment was primarily related to a change in the per barrel price received by the Partnership for oil production from the Thums Unit wells, which account for approximately 38.1% of the Partnerships total oil revenues. The per- barrel price received by the Partnership dropped from a premium of approximately $8 over current spot prices to a premium of approximately $2 over spot prices. This change in pricing reduced the future estimated net revenues expected from the property and led to a ceiling test write down.

Partnership revenues totaled $4,234,581 for the year ended December 31, 2014 compared to $5,112,482 for the comparable period in 2013, a decrease of 17.2% due primarily to decreases in oil sales prices. Overall, oil and gas sales volumes decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 by approximately 7.8% on a BOE basis, a result of natural declining production from existing wells. In addition, the average sales price for crude oil decreased by 10.3%, to an average price of $81.01 per Bbl for the year ended December 31, 2014 compared to an average price of $90.27 for the year ended December 31, 2013. The majority of the 2014 price decline occurred during the fourth quarter, with the fourth quarter 2014 average oil price dropping to $61.32 per barrel from $86.68 received during the third quarter. While the overall decrease in 2014 revenues year to year was 17.2%, fourth quarter revenues dropped to $743,402 from third quarter revenues of $1,182,939, a decline of 37.2%. The average sales price for natural gas increased by 6.4%, to an average price of $4.14 per MCF for the year ended December 31, 2014 compared to an average price of $3.89 for the year ended December 31, 2013. However, gas revenues account for less than 10% of total Partnership oil and gas sales revenues.

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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. Prices for crude oil have continued to decline throughout the first quarter of 2015.

Lease operating expenses increased from $2,327,209 for the year ended December 31, 2013 to $2,608,987 for the year ended December 31, 2014, due primarily to increased workover expenses on the Slaughter Dean Properties. Total workover costs included in lease operating expenses, most of which are incurred on the Partnership’s Slaughter Dean Properties, increased from $212,715 in 2013 to $390,078 in 2014. As workover costs are primarily a function of repairing mechanical well failures, workover costs can vary from year to year. Production tax expense decreased in conjunction with the decrease in revenues, from $298,815 for the year ended December 31, 2013 to $252,144 for the year ended December 31, 2014.

General and administrative costs during the year ended December 31, 2014 decreased to $635,685 as compared to $736,429 incurred during the year ended December 31, 2013. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. The administrative overhead charged to the Partnership decreased from $489,183 during the year ended December 31, 2013 to $431,793 during the year ended December 31, 2014. In addition, professional services incurred during the year decreased from $229,122 for the year ended December 31, 2013 to $184,476 for the year ended December 31, 2014. Professional services include legal fees, audit fees, engineering fees for reserve reports and other analysis, and fees for preparation of SEC filings and XBRL services. During 2013, the Partnership incurred one time fees associated with XBRL services to set up the initial detailed XBRL tagging of its financial statements and footnotes. These decreases were offset by a slight increase in geology and geophysical charges incurred related to resolving ownership issues and various other issues related to the individual properties.

Year Ended December 31, 2013 compared to Year Ended December 31, 2012

The Partnership had net income of $421,300 for the year ended December 31, 2013, compared to net income of $786,000 for the year ended December 31, 2012. The primary cause of this change was declines in sales volumes, which were partially offset by increases in average sales prices for crude oil and natural gas.

Partnership oil and gas sales volumes declined during 2013. The property with the biggest impact on sales volumes was the Dean “B” Unit. Oil sales volumes, which during 2012 had declined by about 7.2% compared to 2011, declined by an additional 16.2% during 2013. Oil sales revenues from the Dean “B” unit, which accounted for 35.1% of Partnership oil sales revenues during 2012 and 34.7% of Partnership oil sales revenues during 2013, fell by approximately $232,600. In addition, as a result of the increase in the decline rate, the estimated proved crude oil reserves attributable to the Dean “B” unit were reduced as of December 31, 2013. The Partnership also experienced natural declines in sales volumes on its Azalea ~~acquisition properties~~Properties. Oil sales volumes from the Thums Long Beach Unit, a long-lived waterflood, declined at a rate of less than 1%. While the Partnership has participated in developmental drilling on its Azalea ~~acquired properties~~Properties, and added nine new wells during 2013, future drilling activity is not expected to reverse the continuing year-to-year decline in sales volumes. The decline in sales volumes was partially offset by increased crude oil and natural gas prices during 2013. Approximately 92.8% of the Partnership’s 2013 revenues came from crude oil sales. During 2013, the average sales price for crude oil sold from Partnership wells increased by approximately 4.0%, from an average price of $86.82 per barrel to $90.27 per barrel.

27The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells substantially all 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.

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~~was~~the ~~partially~~year ~~offset~~ended byDecember 31, ~~increased~~2012 ~~crude~~to ~~oil~~only ~~and~~$237,220 ~~natural~~for ~~gas~~the ~~prices~~year ~~during~~ended December 31, 2013. ~~Approximately~~As ~~92.8%~~workover costs are primarily a function of ~~the~~repairing ~~Partnership’s~~mechanical ~~2013~~well ~~revenues~~failures, ~~came~~workover costs can vary from ~~crude~~year ~~oil~~to ~~sales~~year. ~~During~~Production tax expense totaled $298,815 for the year ended December 31, 2013 compared to $314,377 for the ~~average~~year ~~sales~~ended ~~price~~December 31, 2012. Production taxes for ~~crude~~the ~~oil~~year ~~sold~~ended ~~from~~December 31, ~~Partnership~~2012 ~~wells~~were ~~increased~~impacted by a production tax refund from the State of Texas of approximately $54,000 related to the Slaughter Dean waterflood enhancement project. RELP had applied for a ten year severance tax reduction, pursuant to which the state severance tax on oil production would be reduced by 50%, from 4.06% to 2.3%, after completing the waterflood enhancement project during 2011. The State of Texas approved the severance tax reduction for the ten year period beginning period August 2011 through July 2021, and the overpaid taxes from anAugust 2011 forward were refunded during the third quarter of 2012. Going forward, the overall average ~~price~~production tax rate paid by the Partnership will decline as a result of ~~$86~~this rate reduction.82 ~~per~~Oil ~~barrel~~sales tofrom ~~$90~~the Slaughter Dean B Unit accounted for 32.272% ~~per~~of ~~barrel~~total revenues for the year ended December 31, 2013. The tax rate reduction saved the Partnership approximately $37,900 during the year ended December 31, 2013.

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

Lease operating expenses decreased from $2,506,677 for the year ended December 31, 2012 to $2,327,209 for the year ended December 31, 2013, due primarily to lower workover expenses on the Slaughter Dean wells, and lower overhead on the Azalea acquisition properties. Overall, workover expenses declined from $338,114 incurred during the year ended December 31, 2012 to only $237,220 for the year ended December 31, 2013. As workover costs are primarily a function of repairing mechanical well failures, workover costs can vary from year to year. Production tax expense totaled $298,815 for the year ended December 31, 2013 compared to $314,377 for the year ended December 31, 2012. Production taxes for the year ended December 31, 2012 were impacted by a production tax refund from the State of Texas of approximately $54,000 related to the Slaughter Dean waterflood enhancement project. RELP had applied for a ten year severance tax reduction, pursuant to which the state severance tax on oil production would be reduced by 50%, from 4.6% to 2.3%, after completing the waterflood enhancement project during 2011. The State of Texas approved the severance tax reduction for the ten year period beginning period August 2011 through July 2021, and the overpaid taxes from August 2011 forward were refunded during the third quarter of 2012. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 32.2% of total revenues for the year ended December 31, 2013. The tax rate reduction saved the Partnership approximately $37,900 during the year ended December 31, 2013.

General and administrative costs incurred during the year ended December 31, 2013 decreased to $736,429 as compared to $776,523 incurred during the year ended December 31, 2012. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. The administrative overhead charged to the Partnership decreased from $567,424 during the year ended December 31, 2012 to $489,183 during the year ended December 31, 2013. The decrease in the administrative overhead charge was partially offset by additional professional fees incurred related to processing SEC filings.

Year Ended December 31, 2012 compared to Year Ended December 31, 2011

During the year ended December 31, 2012, the Partnership earned net income totaling $786,000 compared to net income of $88,107 for the year ended December 31, 2011. Decreased general and administrative costs and interest expense were the primary causes of this change.

Partnership revenues totaled $5,830,997 for the year ended December 31, 2012 compared to $6,048,932 for the comparable period in 2011, a decrease of 3.6% due primarily to decreases in oil and gas sales prices. Overall, oil and gas sales volumes increased during the year ended December 31, 2012 compared to the year ended December 31, 2011 by approximately 1.7% on BOE basis, as a result of production from newer wells offsetting natural declines from existing wells. The average sales price for crude oil decreased by 0.9%, to an average price of $86.82 per Bbl for the year ended December 31, 2012 compared to an average price of $87.58 for the year ended December 31, 2011, and the average sales price for natural gas decreased by 27.7%, to an average price of $3.40 per MCF for the year ended December 31, 2012 compared to an average price of $4.70 for the year ended December 31, 2011. The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

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Production tax expense totaled $314,377 for the year ended December 31, 2012 compared to $394,160 for the year ended December 31, 2011. During the third quarter of 2012, RELP received a production tax refund from the State of Texas totaling approximately $54,000 related to the waterflood enhancement project performed in the Slaughter Dean Field. RELP had applied for a ten year severance tax reduction (the state severance tax on oil production is reduced by 50%, from 4.6% to 2.3%) after completing the waterflood enhancement project during 2011. The State of Texas approved the severance tax reduction for the ten year period beginning period August 2011 through July 2021, and the overpaid taxes were refunded. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 32.9% of total 2012 revenues. The tax rate reduction saved the Partnership approximately $43,260 during the year ended December 31, 2012.

General and administrative costs incurred during the years ended December 31, 2011 and 2012 decreased from $1,382,040 to $776,523, respectively. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. As described in Note 5 to the audited financial statements reported in this Annual Report, during the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from a fixed monthly amount as prescribed in the Partnership Agreement to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. As a result of this change the administrative overhead charged to the Partnership decreased from $896,880 during the year ended December 31, 2011 to $567,424 during the year ended December 31, 2012. In addition, salaries and wages for field personnel in the Slaughter Dean Field decreased by $124,000 due to staffing reductions. Finally, direct costs for technical personnel and for third party reserve reports declined by approximately $99,000 for the year ended December 31, 2012 compared to the same period in 2011, related primarily to time spent examining the Slaughter Dean Field and the waterflood enhancement project in 2011.

Total other income and expense for the years ended December 31, 2012 and 2011 decreased from expense of $174,257 in 2011 to expense of $105,339 in 2012. Interest expense decreased from $160,720 during the year ended December 31, 2011 to $80,632 during the year ended December 31, 2012 due to the Partnership’s payment of principal on its note payable.

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, ~~2013~~2014, ~~2012~~2013 and ~~2011~~2012, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.

Contractual Obligations Table

	Payment due by period
Contractual obligations	Total		Less than 1 Year	~~Less than 1 Year~~	1-3 Years	1-3-5 ~~Years~~years		More than 5 Years	~~3-5 years~~	~~More than 5 Years~~
Consulting agreement *	—		—	—	—	—		—	—	—
Credit Agreement	$	690,000		$	360,000	$	330,000		—	—
Interest related to Credit Agreement**	$	32,625		$	26,250	$	6,375		—	—

* In September 2006, 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~~Properties only. The amounts payable to William R. Dixon under the aforementioned agreement are not fixed and determinable amounts, and will vary based upon sales revenues from the Slaughter Dean Properties. During the years ended December 31, 2014, 2013, and 2012, William R. Dixon received $19,379, $17,147, and $23,819, respectively, related to this overriding royalty interest. At December 31, 2014, the estimated net proved reserves of the Slaughter Dean Properties, as determined by the independent engineering firm used by the Partnership’s, had a remaining economic life of 27 years.

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revenues from the Slaughter Dean Project. During the years ended December 31, 2013, 2012, and 2011, William R. Dixon received $17,147, $23,819, and $21,914, respectively, related to this overriding royalty interest.

** Interest expense assumes the balance of the Credit Agreement at the end of the period and the rate in effect as of December 31, 2013.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Interest Rate Risk

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. At ~~December 31,~~During ~~2013~~2014, the Partnership ~~had~~completed ~~$690,000~~repayment of all of its outstanding debt under ~~the~~its Credit Agreement. ~~Interest is calculated under the terms of the agreement based on the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%,~~ with ~~a minimum interest rate of 5%~~TCB, ~~payable~~and ~~monthly.~~terminated ~~A 1.0% increase in interest rates during~~ the ~~year~~Credit ended December 31, 2013 would have increased interest expense by approximately $10,150. The Partnership does not currently intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.

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Agreement as of December 31, 2014. The Partnership currently has no plans to borrow additional monies. The Partnership does not plan to purchase additional properties nor engage in additional development activity proposed on Partnership properties unless such development can be paid for via current cash flows. If the Partnership did elect to borrow monies for additional acquisition or development activity, it would 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.

To the extent that changes in interest rates affect general economic conditions, the Partnership will be affected by such changes.

Commodity Price Risk

AsThe ofPartnership’s ~~December 31~~oil and gas sales revenues, ~~2013~~cash flow from operations, and reserve values are substantially dependent upon the prevailing price of crude oil and natural gas. 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 asubstantially ~~vast~~all ~~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. Declines in commodity prices will adversely affect our financial condition, liquidity, and operating results, and a sustained period of lower prices may reduce the amount of crude oil and natural gas that can be economically be produced from Partnership wells. Prevailing prices are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of other factors beyond our control, such as global, political, and economic conditions. Historically, prices received for oil and gas production have been volatile and unpredictable, and such volatility is expected to continue.

Assuming the production levels the Partnership attained during the year ended December 31, ~~2013~~2014, a 10% change in the price received for crude oil would have had an approximate $~~475~~385,000 impact on the Partnership’s oil revenues, and a 10% change in the price received for the natural gas would have had an approximate $3638,000 impact on the Partnership’s natural gas revenues. If commodity prices remain at their current levels, the impact on future operating revenues and cash flows could be much more significant.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

Management Report on Internal Control Over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation under the framework in Internal Control — Integrated Framework (1992), management of the Partnership concluded that the Partnership’s internal control over financial reporting was effective as of December 31, ~~2013~~2014.

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

Changes in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended December 31, ~~2013~~2014 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

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

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

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

Name	Age	Positions and Offices Held
Michael J. Mauceli	5758	Manager of Reef Oil & Gas Partners GP, LLC; Chief Executive Officer of RELP
Daniel C. Sibley	6263	Chief Financial Officer and General Counsel of RELP
David M. Tierney	6162	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 gas business in 1976 when he joined Tenneco Oil & Gas Company. Mr. Mauceli moved to Dallas in 1979, where he was independently

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Houston where he received his Commercial Real Estate License. He entered the oil and 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.

Daniel C. Sibley became Chief Financial Officer of RELP in March 2010 and General Counsel of RELP in January 2009. He previously served as Chief Financial Officer of Reef from December 1999 until his appointment to General Counsel of RELP. He also served as Chief Financial Officer for RELP from January 2006 until his appointment to General Counsel of RELP, and had served in this same position with RELP’s predecessor entity, OREI, since 1998. Mr. Sibley was employed as a Certified Public Accountant with Grant Thornton from 1977 to 1980. From 1980 to 1994, he was involved in the private practice of law. He received a B.B.A. in accounting from the University of North Texas in 1973, a law degree (J.D.) from the University of Texas in 1977, and a Master of Laws-Taxation degree (Ll.M) from Southern Methodist University in 1984. Mr. Sibley became a certified public accountant in 1977, but no longer maintains that license. He is an active member of the Texas Bar Association.

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

Audit Committee and Nominating Committee

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

Code of Ethics

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

ITEM 11. EXECUTIVE COMPENSATION

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

Recipient	Form of Compensation	Amount
Managing General Partner	Partnership interest	10% carried interest in the Partnership, out of which the economic equivalent of a 3% carried interest is allowed to the broker/dealers who were involved in the offering of units.
Managing General Partner	Management fee	15% of subscriptions, less organization and offering costs to be paid by Reef (non-recurring). For the year ended December 31, 2008, the Partnership paid a management fee of $13,320,000.
Managing General Partner and its	Monthly administrative fee	For the years ended December 31, 2014

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Recipient	Form of Compensation	Amount
Managing General Partner	Management fee	15% of subscriptions, less organization and offering costs to be paid by Reef (non-recurring). For the year ended December 31, 2008, the Partnership paid a management fee of $13,320,000.
Affiliates		and 2013, the Partnership paid administrative fees totaling $431,793 and $489,183, 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, 2013 and 2012, the Partnership paid administrative fees of $489,183 and $567,424 respectively.
Managing General Partner or its Affiliates	Drilling compensation	When Reef or an affiliate of Reef serves as operator of a Partnership property, then Reef or such affiliate, as the case may be, will receive drilling compensation equal to 15% of the total well costs, excluding lease acquisition costs. Total well costs include the costs associated with all developmental activities on a well, such as drilling, completing, reworking, working over, deepening, sidetracking, or fracturing a well. Because RELP will serve as operator of the Slaughter Dean Properties, 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, 2014 and 2013, the Partnership paid drilling compensation fees totaling $21,201 and $25,602, respectively.
Managing General Partner or its Affiliates	Drilling compensation	When Reef or an affiliate of Reef serves as operator of a Partnership property, then Reef or such affiliate, as the case may be, will receive drilling compensation equal to 15% of the total well costs, excluding lease acquisition costs. Total well costs include the costs associated with all developmental activities on a well, such as drilling, completing, reworking, working over, deepening, sidetracking, or fracturing a well. Because RELP will serve as operator of the Slaughter Dean wells, 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, 2013 and 2012, the Partnership paid a drilling compensation fee of $25,602 and $39,856 respectively.
Managing General Partner and its Affiliates	Direct costs	Reimbursement at cost. For the years ended December 31, 2014 and 2013, the Partnership paid direct costs totaling $97,934 and $104,313, respectively.
Managing General Partner and its Affiliates	Payment for equipment, supplies, marketing, and other services	Competitive prices. For the years ended December 31, 2014 and 2013, the Partnership paid no payments for equipment, supplies, marketing and other services.

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Recipient	Form of Compensation	Amount
Managing General Partner and its Affiliates	~~Direct~~Acquisition ~~costs~~and Development Costs	Reimbursement at cost. For the years ended December 31, ~~2013~~2014 and ~~2012~~2013, the Partnership ~~paid~~did ~~direct~~not ~~costs~~reimburse ofthe ~~$104,313~~Managing General Partner and ~~$173,102~~its ~~respectively~~affiliates for any acquisition and development costs.
Managing General Partner and its Affiliates	Payment for equipment, supplies, marketing, and other services	Competitive prices. For the years ended December 31, 2013 and 2012, the Partnership paid no payments for equipment, supplies, marketing and other services.
Managing General Partner and its Affiliates	Acquisition and Development Costs	Reimbursement at cost. For the years ended December 31, 2013 and 2012, the Partnership did not reimburse the Managing General Partners and its affiliates for any acquisition and development costs.

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~~Partnership units to brokers for their own accounts, who were permitted to buy ~~Units~~Partnership units at a price net of the commission that they would normally earn on sales of ~~Units~~such 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 purchased 1% of the Partnership units, and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. ~~Cash~~Prior to October 1, 2013, cash distributions to partners of the net cash flow from crude oil and natural gas sales revenues, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, ~~as a result of~~ Reef’s ~~purchase~~purchased of 0.60 units of limited partner interest from anone of the Partnership’s investor partners. Thus, effective October 1, 2013, Reef also receives 0.~~067~~06% of the ~~89%~~distributions ~~interest~~paid into ~~the~~investor ~~Partnership~~partners. (0As such, Reef currently receives 11.~~060~~06%) ~~represented~~and byinvestor ~~the~~partners ~~investor~~receive ~~partner~~88.94% ~~units~~of total cash distributions. During the years ended December 31, ~~2013~~2014, ~~2012~~2013 and ~~2011~~2012, Reef received $7518,~~112~~796, $7275,~~085~~112, and $~~107~~72,~~464~~085, respectively, in cash distributions related to its 11% interest, and received $103 and $142 during the ~~year~~years ended December 31, 2014 and 2013 related to its ~~units~~0.06% of limited partner interest.

In addition, when RELP, serves as operator of a Partnership well, then RELP, receives 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 ~~wells~~Properties. As a result, such drilling compensation payable to RELP may amount to approximately 9% of total partnership subscriptions, depending on the level of developmental operations conducted by 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. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells. During the years ended December 31, ~~2013~~2014, ~~2012~~2013, and ~~2011~~2012, RELP received $2521,~~602~~201, $3925,~~856~~602, and $5439,~~005~~856, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.

Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership. During the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $96,804 and $1,130, respectively. During the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively. During the year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively.

34RELP allocates its general and administrative expenses as overhead to all of the partnerships to which it provides services, and this allocation is a significant portion of the Partnership’s general and administrative expenses. The allocation of RELP’s overhead to the partnerships to which it provides services is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the years ended December 31, 2014, 2013, and 2012, the

~~Table of Contents~~30

onTable ~~behalf~~ of the Partnership. During the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively. During the year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively. During the year ended December 31, 2011, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $342,271 and $2,818, respectively.Contents

~~Prior to January 1, 2012, RELP received an~~ administrative ~~fee~~overhead to cover all general and administrative costs in an amount equal to 1/12th of 1% of all capital raised payable monthly, totaling $74,740 per month. During the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged ~~to the Partnership~~ by ~~changing the calculation of the fee from the fixed monthly amount referenced above to a variable monthly amount calculated in accordance with the standard~~ RELP ~~overhead allocation method used~~ to ~~charge overhead to other affiliated partnerships. The allocation of RELP’s overhead to partnerships is based upon several factors, including~~ the ~~level~~Partnership oftotaled ~~drilling activity~~$431, ~~revenues~~793, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the years ended December 31, 2013, 2012, and 2011, RELP received administrative fees totaling $489,183, and $567,424, ~~and $896,880,~~ respectively. ~~Administrative~~The ~~fees~~administrative ~~are~~overhead charged by RELP is included in general and administrative expense in the ~~financial~~accompanying statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

RELP processes joint interest billings and revenues on behalf of the Partnership. At December 31, ~~2013~~2014 and ~~2012~~2013, RELP owed the Partnership $~~509~~183,~~271~~078 and $~~633~~509,~~900~~271, respectively, for net revenues processed in excess of net joint interest and technical and administrative service charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.

Compensation Committee

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

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

The following table sets forth information as of December 31, ~~2013~~2014 concerning all persons known by Reef to own beneficially more than 5% of the interests in the Partnership. Unless expressly indicated otherwise, each partner exercises sole voting and investment power with respect to the units beneficially owned.

Person or Group	Number of Units Beneficially Owned	Percent of Total Partnership Units Outstanding		Percentage of Total Partnership Interests Beneficially Owned
Title of Interest	Person or Group	Number of Units Beneficially Owned		Percent of Total Partnership Units Outstanding		Percentage of Total Partnership Interests Beneficially Owned
Reef Oil & Gas Partners, L.P. (1)	8.969696	1.00	%	1.00	%
General Partner	Reef Oil & Gas Partners, L.P. (1)	8.969696		1.00	%	1.00	%
Reef Oil & Gas Partners, L.P. (1)	0.600000	0.067	%	0.06	%
Limited Partner	Reef Oil & Gas Partners, L.P. (1)	0.600000		0.067	%	0.06	%
Reef Oil & Gas Partners, L.P. (1)				10.00	%
General Partner	Reef Oil & Gas Partners, L.P. (1)					10.00	%

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

Reef, as managing general partner, received a 10% general partner interest in the Partnership as compensation for forming the Partnership. This interest is not represented by Partnership units. Reef also acquired a 1% general partner interest as a result of purchasing 1% of total Partnership units (8.9697 units). The units purchased by investor partners represent an 89% interest in the Partnership. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from an investor partner, representing .067% of outstanding investor partner 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.

~~Table~~The Partnership is managed by a managing general partner and does not have directors. Reef is the managing general partner of ~~Contents~~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.”

~~right to acquire additional units within sixty days from options, warrants, rights, conversion privileges, or similar obligations.~~31

~~ITEM~~Table ~~13.~~of ~~CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE~~Contents

~~The~~ITEM ~~Partnership is managed by a managing general partner and does not have directors~~14. ~~Reef~~PRINCIPAL isACCOUNTANT ~~the~~FEES ~~managing~~AND 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.”SERVICES

In ~~January 2011,~~each ~~the Partnership sold a portion~~ of ~~its interests in~~ the ~~Thums~~last ~~Long~~two ~~Beach~~fiscal ~~Unit to Reef Oil & Gas 2010-A Income Fund~~years, ~~L.P., a Reef affiliate. In June 2011,~~ the Partnership ~~sold~~incurred anprofessional ~~additional~~audit ~~portion~~and oftax ~~its~~fees ~~interests~~from inits ~~the~~principal ~~Thums~~accountant ~~Long~~BDO ~~Beach Unit to the same affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field~~USA, ~~located underneath the Long Beach Harbor in southern California. The Partnership received $350~~LLP,~~000~~ inas ~~cash~~disclosed in ~~exchange for~~ the ~~interests~~table ~~sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with this transaction.~~below:

In September 2012, the Partnership sold leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“purchaser”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three new drilled wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this transaction.

	2014		2013
Audit Fees	$	70,803	$	72,588
Audit Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—

~~ITEM~~As 14indicated in Item 10 above, the Partnership does not have any directors or an audit committee. ~~PRINCIPAL~~As ~~ACCOUNTANT~~such, ~~FEES~~no ~~AND~~pre-approval ~~SERVICES~~policies or procedures for engagement of principal accountants have been established.

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

	2013		2012
Audit fees	$	72,588	$	81,296
Audit related fees	—		—
Tax fees	—		—
All other fees	—		—

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

(a)	1. Financial Statements

	Report of Independent Registered Public Accounting Firm	F-1
	Balance Sheets	F-2
	Statements of Operations	F-3
	Statements of Partnership Equity	F-4
	Statements of Cash Flows	F-5
	Notes to Financial Statements	F-6

	2. Financial Statement Schedules	None

	3. Exhibits

36A 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.

~~Table of Contents~~32

~~PART IV~~Table of Contents

~~ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES~~SIGNATURES

(a)	1. Financial Statements
	Report of Independent Registered Public Accounting Firm	F-1
	Balance Sheets	F-2
	Statements of Operations	F-3
	Statements of Partnership Equity	F-4
	Statements of Cash Flows	F-5
	Notes to Financial Statements	F-6
	2. Financial Statement Schedules	None
	3. Exhibits

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.

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.

Date: March 31, 2015

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


	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner


	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner


	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)

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~~SIGNATURES~~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
	Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the Partnership (Principal Executive Officer)
/s/ Michael J. Mauceli		March 31, 2015
Michael J. Mauceli


/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of Reef Exploration, L.P. (Principal Financial and Accounting Officer)	March 31, 2015
Daniel C. Sibley

Date:March 31, 2014
	REEF OIL & GAS INCOME
	AND DEVELOPMENT FUND III, L.P.
	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner
	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner
	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)

38Table of Contents

~~Table of Contents~~EXHIBIT INDEX

~~Pursuant~~The tofollowing ~~the~~documents ~~requirements~~are ofincorporated ~~the Securities Exchange Act of 1934, this report has been signed below~~ by ~~the~~reference ~~following persons on behalf of the registrant and~~ in ~~the~~response ~~capacities~~to ~~and~~Item on15 ~~the dates indicated~~(b).

Signature	Title	Date
Exhibit
/s/ Michael J. Mauceli	Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the	March 31, 2014
Number	Description
Michael J. Mauceli	Partnership
3.1	Certificate of Formation of Reef Oil & Gas Income and Development Fund III, L.P. dated November 27, 2007(incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
	(Principal Executive Officer)
4.1	Second Amendment and Restated Agreement of Limited Partnership of Reef Oil & Gas Income and Development Fund III, L.P., dated June 4, 2008 (incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of Reef Exploration, L.P.	March 31, 2014
10.1	Operating Agreement dated January 7, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
Daniel C. Sibley	(Principal Financial and Accounting Officer)
10.2	Operating Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 10.2 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.3	Purchase and Sale Agreement dated January 7, 2008 by and among Sierra-Dean Production Company L.P., Reef Oil & Gas Income and Development Fund III, L.P., Reef Exploration L.P. and SPI Operations LLC, as amended on January 8, 2008 (incorporated by reference to Exhibit 10.3 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.4	Assignment, dated May 1, 2008, by and between Davric Corporation and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.4 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.5	Crude Oil Contract, dated March 13, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc., as amended by Amendment No. 1, dated June 24, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc. (incorporated by reference to Exhibit 10.5 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.6	Consulting Agreement, dated September 1, 2006, by between Reef Exploration, L.P. and William R. Dixon (incorporated by reference to Exhibit 10.6 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.7	Casinghead Gas Sales Contract, dated January 1, 1978, by and between Amoco Production Company and Amoco Production Company (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.8	Purchase and Sale Agreement, dated January 19, 2010, by and between Azalea Properties Ltd. And RCWI, LP. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

3935

Table of Contents

EXHIBIT INDEX

10.9		Purchase and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P., and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.10		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing PUDs (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.11		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing Properties/Title Defect Notice (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.12		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Third Party Consents (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

10.13		Purchase and Sale Agreement by and between Lett Oil & Gas, L.P., as seller and RCWI, L.P., as buyer dated as of June 23, 2010 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.14		Assignment, Conveyance and Bill of Sale between Lett Oil & Gas, L.P. (“Assignor”) and Reef Oil & Gas Income and Development Fund III, L.P. (“Assignee”) executed June 30, 2010 and dated effective June 1, 2010 (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.15		$50,000,000 Credit Agreement dated June 30, 2010 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.16		Form of Security Agreement (General) dated June 30, 2010 by Reef Oil & Gas Income and Development Fund III, L.P., in favor of Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.17		Promissory Note in the principal amount of up to $50,000,000 dated June 30, 2010 payable to Texas Capital Bank, N.A. (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).

10.18		Purchase and Sale Agreement, effective June 1, 2011, between the Partnership and Reef 2010 -A Income Fund, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).

10.19		First Amendment to the Credit Agreement dated May 20, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated May 20, 2011).

10.20		Second Amendment to the Credit Agreement dated June 30, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).

10.21		Third Amendment to the Credit Agreement dated April 30, 2013 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as

~~The following documents are incorporated by reference in response to Item 15 (b).~~36

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

Table of Contents

40lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 10-Q, dated May 15, 2013.

Table of Contents

23.2	*	Consent of Forrest A. Garb & Associates, Inc.

31.1	*	Certification of Principal Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2	*	Certification of Principal Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1	*	Certification of Principal Executive Officer pursuant to 18 U.S.C. §1350.

32.2	*	Certification of Principal Financial Officer pursuant to 18 U.S.C. §1350.

99.1	*	Summary Reserve report of Forrest A. Garb & Associates, Inc.

101.INS	*	XBRL Instance Document

101.SCH	*	XBRL Taxonomy Extension Schema Document

101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	*	XBRL Taxonomy Extension Labels Linkbase Document

101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	*	XBRL Taxonomy Extension Definition Linkbase Document

10.9		Purchase and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P., and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.10		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing PUDs (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.11		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing Properties/Title Defect Notice (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.12		Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Third Party Consents (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.13		Purchase and Sale Agreement by and between Lett Oil & Gas, L.P., as seller and RCWI, L.P., as buyer dated as of June 23, 2010 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.14		Assignment, Conveyance and Bill of Sale between Lett Oil & Gas, L.P. (“Assignor”) and Reef Oil & Gas Income and Development Fund III, L.P. (“Assignee”) executed June 30, 2010 and dated effective June 1, 2010 (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.15		$50,000,000 Credit Agreement dated June 30, 2010 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.16		Form of Security Agreement (General) dated June 30, 2010 by Reef Oil & Gas Income and Development Fund III, L.P., in favor of Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.17		Promissory Note in the principal amount of up to $50,000,000 dated June 30, 2010 payable to Texas Capital Bank, N.A. (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.18		Purchase and Sale Agreement, effective June 1, 2011, between the Partnership and Reef 2010 -A Income Fund, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).
10.19		First Amendment to the Credit Agreement dated May 20, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated May 20, 2011).
10.20		Second Amendment to the Credit Agreement dated June 30, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).
10.21		Third Amendment to the Credit Agreement dated April 30, 2013 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as

* Filed herewith

4137

Table of Contents

			lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 10-Q, dated May 15, 2013.
23.2*			Consent of Forrest A. Garb. & Associates, Inc.
31.1*			Certification of Principal Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*			Certification of Principal Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1*			Certification of Principal Executive Officer pursuant to 18 U.S.C. §1350.
32.2*			Certification of Principal Financial Officer pursuant to 18 U.S.C. §1350.
99.1*			Summary Reserve Report of Forrest A. Garb & Associates, Inc.
101.INS*			XBRL Instance Document
101.SCH*			XBRL Taxonomy Extension Schema Document
101.CAL*			XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*			XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*			XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*			XBRL Taxonomy Extension Definition Linkbase Document

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

*Financial ~~Filed herewith~~Statements

42Years Ended December 31, 2014, 2013, and 2012

~~Table of~~ Contents

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

Report of Independent Registered Public Accounting Firm	F-1

Audited Financial Statements

Balance sheets	F-2
Statements of operations	F-3
Statements of partnership equity	F-4
Statements of cash flows	F-5
Notes to financial statements	F-6

~~Financial~~Table ~~Statements~~of Contents

~~Years~~Report ~~Ended~~of ~~December 31,~~Independent ~~2013,~~Registered ~~2012,~~Public ~~and~~Accounting ~~2011~~Firm

~~Contents~~Partners

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

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

~~Table~~Richardson, ~~of Contents~~TX

~~Report~~We have audited the accompanying balance sheets of ~~Independent~~Reef ~~Registered~~Oil & ~~Public~~Gas ~~Accounting~~Income ~~Firm~~and Development Fund III, L.P. (“the Partnership”) as of December 31, 2014 and 2013 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, 2014. 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.

~~Partners~~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 audits 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

~~Richardson~~/S/ BDO USA, TXLLP

~~We have audited the accompanying balance sheets of Reef Oil & Gas Income and Development Fund III~~Dallas, L.P. (“the Partnership”) as of December 31, 2013 and 2012 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, 2013. 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.Texas

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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to haveMarch 31, 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.2015

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, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.F-1

~~/S/~~Table ~~BDO~~of ~~USA, LLP Dallas, Texas March 31, 2014~~Contents

~~F-1~~Reef Oil & Gas Partners Income and Development Fund III, L.P.

~~Table~~Balance ~~of Contents~~Sheets

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

December 31,	2014		2013

Assets
Current assets:
Cash and cash equivalents	$	368,620	$	651,936
Accounts receivable from affiliates	183,078		509,271
Deferred financing fees, net	—		10,056
Total current assets	551,698		1,171,263

Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $66,651,471 and $63,825,425	11,116,897		13,384,631
Unproved properties, excluded from amortization	—		389,672
Net oil and gas properties	11,116,897		13,774,303

Deferred financing fees, net	—		4,184

Total assets	$	11,668,595	$	14,949,750

Liabilities and partnership equity

Current liabilities:
Accounts payable	$	10,479	$	8,387
Accrued liabilities	6,247		—
Current portion of long term note payable	—		360,000
Total current liabilities	16,726		368,387

Long term liabilities
Note payable	—		330,000
Asset retirement obligation	2,528,422		2,463,175
Total long term liabilities	2,528,422		2,793,175

Commitments and contingencies (Note 6)

Partnership equity
General partners	5,230,521		6,709,582
Limited partners	3,645,712		4,841,706
Managing general partner	247,214		236,900
Total partnership equity	9,123,447		11,788,188

Total liabilities and partnership equity	$	11,668,595	$	14,949,750

~~Balance~~See ~~Sheets~~accompanying notes to financial statements.

December 31,	2013		2012
Assets
Current assets:
Cash and cash equivalents	$	651,936	$	495,244
Accounts receivable	—		1,986
Accounts receivable from affiliates	509,271		679,422
Deferred financing fees, net	10,056		12,299
Total current assets	1,171,263		1,188,951
Oil and gas properties, full cost method of accounting:
Accounting:
Proved properties, net of accumulated depletion of $63,825,425 and $62,728,480	13,384,631		14,023,909
Unproved properties	389,672		524,357
Net oil and gas properties	13,774,303		14,548,266
Deferred financing fees, net	4,184		—
Total assets	$	14,949,750	$	15,737,217
Liabilities and partnership equity
Current liabilities:
Accounts payable	$	8,387	$	5,595
Current portion of long-term note payable	360,000		1,315,000
Total current liabilities	368,387		1,320,595
Long term liabilities:
Note payable	330,000		—
Asset retirement obligation	2,463,175		2,366,899
Total long term liabilities	2,793,175		2,366,899
Commitments and contingencies (Note 6)
Partnership equity
General partners	6,709,582		6,899,244
Limited partners	4,841,706		4,995,071
Managing general partner	236,900		155,408
Total partnership equity	11,788,188		12,049,723
Total liabilities and partnership equity	$	14,949,750	$	15,737,217

F-2

~~See~~Table ~~accompanying~~of ~~notes to financial statements.~~Contents

~~F-2~~Reef Oil & Gas Partners Income and Development Fund III, L.P.

~~Table~~Statements of ~~Contents~~Operations

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

	For the Years Ended December 31,
	2014			2013			2012

Oil, gas and NGL sales	$	4,234,581		$	5,112,482		$	5,830,997

Costs and expenses:
Lease operating expenses	2,608,987			2,327,209			2,506,677
Production taxes	252,144			298,815			314,377
Depreciation, depletion and amortization	1,194,107			1,102,611			1,222,493
Accretion of asset retirement obligation	163,490			155,345			119,588
Property impairment	1,841,274			—			—
General and administrative	635,685			736,429			776,523
Total costs and expenses	6,695,687			4,620,409			4,939,658

Income (loss) from operations	(2,461,106		)	492,073			891,339

Other income (expense)
Miscellaneous income	746			463			69
Interest expense	(17,954		)	(56,334		)	(80,632		)
Amortization of deferred financing fees	(15,556		)	(14,902		)	(24,776		)
Total other income (expense)	(32,764		)	(70,773		)	(105,339		)

Net income (loss)	$	(2,493,870	)	$	421,300		$	786,000

Net income (loss) per general partner unit	$	(2,841.31	)	$	298.08		$	650.10
Net income (loss) per limited partner unit	$	(2,841.31	)	$	298.08		$	650.10
Net income per managing partner unit	$	3,256.80		$	17,459.23		$	23,268.23

~~Statements~~See ofaccompanying ~~Operations~~notes to financial statements.

	For the Years Ended December 31,
	2013			2012			2011
Oil, gas and NGL sales	$	5,112,482		$	5,830,997		$	6,048,932
Costs and expenses:
Lease operating expenses	2,327,209			2,506,677			2,803,824
Production taxes	298,815			314,377			394,160
Depreciation, depletion and amortization	1,102,611			1,222,493			1,128,514
Accretion of asset retirement obligation	155,345			119,588			78,030
General and administrative	736,429			776,523			1,382,040
Total costs and expenses	4,620,409			4,939,658			5,786,568
Income from operations	492,073			891,339			262,364
Other income (expense)
Miscellaneous income (expense)	463			69			16
Interest expense	(56,334		)	(80,632		)	(160,720		)
Amortization of deferred financing fees	(14,902		)	(24,776		)	(13,553		)
Total other income (expense)	(70,773		)	(105,339		)	(174,257		)
Net income	$	421,300		$	786,000		$	88,107
Net income (loss) per general partner unit	$	298.08		$	650.10		$	(27.55	)
Net income (loss) per limited partner unit	$	298.08		$	650.10		$	(27.55	)
Net income per managing general partner unit	$	17,459.23		$	23,268.23		$	12,549.94

F-3

~~See~~Table ~~accompanying~~of ~~notes to financial statements.~~Contents

~~F-3~~Reef Oil & Gas Partners Income and Development Fund III, L.P.

~~Table~~Statements of ~~Contents~~Partnership Equity

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

	General Partners				Limited Partners				Managing General Partner				Total
	Units	Amount			Units	Amount			Units	Amount			Units	Amount

Balance at December 31, 2011	490.9827	$	6,902,531		397.0172	$	4,997,729		8.9697	$	18,784		896.9696	$	11,919,044
Partner distributions	—	(322,476		)	—	(260,760		)	—	(72,085		)	—	(655,321		)
Net income	—	319,189			—	258,102			—	208,709			—	786,000
Balance at December 31, 2012	490.9827	$	6,899,244		397.0172	$	4,995,071		8.9697	$	155,408		896.9696	$	12,049,723

Distribution amount per partnership unit		$	656.80			$	656.80			$	8,036.50

Balance at December 31, 2012	490.9827	$	6,899,244		397.0172	$	4,995,071		8.9697	$	155,408		896.9696	$	12,049,723
Partner distributions	—	(336,015		)	—	(271,708		)	—	(75,112		)	—	(682,835		)
Net income	—	146,353			—	118,343			—	156,604			—	421,300
Balance at December 31, 2013	490.9827	$	6,709,582		397.0172	$	4,841,706		8.9697	$	236,900		896.9696	$	11,788,188

Distribution amount per partnership unit		$	684.37			$	684.37			$	8,373.97

Balance at December 31, 2013	490.9827	$	6,709,582		397.0172	$	4,841,706		8.9697	$	236,900		896.9696	$	11,788,188
Partner distributions	—	(84,027		)	—	(67,946		)	—	(18,898		)	—	(170,871		)
Net income (loss)	—	(1,395,034		)	—	(1,128,048		)	—	29,212			—	(2,493,870		)
Balance at December 31, 2014	490.9827	$	5,230,521		397.0172	$	3,645,712		8.9697	$	247,214		896.9696	$	9,123,447

Distribution amount per partnership unit		$	171.14			$	171.14			$	2,106.87

~~Statements~~See ofaccompanying ~~Partnership~~notes ~~Equity~~to financial statements

	General Partners				Limited Partners				Managing General Partner				Total
	Units	Amount			Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 2010	490.9827	$	7,336,215		397.0172	$	5,348,414		8.9697	$	13,679		896.9696	$	12,698,308
Partner distributions	—	(420,159		)	—	(339,748		)	—	(107,464		)	—	(867,371		)
Net income (loss)	—	(13,525		)	—	(10,937		)	—	112,569			—	88,107
Balance at December 31, 2011	490.9827	$	6,902,531		397.0172	$	4,997,729		8.9697	$	18,784		896.9696	$	11,919,044
Distribution amount per partnership unit		$	855.75			$	855.75			$	11,980.78
Balance at December 31, 2011	490.9827	$	6,902,531		397.0172	$	4,997,729		8.9697	$	18,784		896.9696	$	11,919,044
Partner distributions	—	(322,476		)	—	(260,760		)	—	(72,085		)	—	(655,321		)
Net income	—	319,189			—	258,102			—	208,709			—	786,000
Balance at December 31, 2012	490.9827	$	6,899,244		397.0172	$	4,995,071		8.9697	$	155,408		896.9696	$	12,049,723
Distribution amount per partnership unit		$	656.80			$	656.80			$	8,036.50
Balance at December 31, 2012	490.9827	$	6,899,244		397.0172	$	4,995,071		8.9697	$	155,408		896.9696	$	12,049,723
Partner distributions	—	(336,015		)	—	(271,708		)	—	(75,112		)	—	(682,835		)
Net income	—	146,353			—	118,343			—	156,604			—	421,300
Balance at December 31, 2013	490.9827	$	6,709,582		397.0172	$	4,841,706		8.9697	$	236,900		896.9696	$	11,788,188
Distribution amount per partnership unit		$	684.37			$	684.37			$	8,373.97

F-4

~~See~~Table ~~accompanying~~of ~~notes to financial statements.~~Contents

~~F-4~~Reef Oil & Gas Partners Income and Development Fund III, L.P.

~~Table~~Statements of ~~Contents~~Cash Flows

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

	For the Years Ended December 31,
	2014			2013			2012

Cash flows from operating activities
Net income (loss)	$	(2,493,870	)	$	421,300		$	786,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
*Adjustments for non-cash transactions:*
Depletion, depreciation and amortization	1,194,107			1,102,611			1,222,493
Accretion of asset retirement obligation	163,490			155,345			119,588
Amortization of deferred financing fees	15,556			14,902			24,776
Plugging and abandonment costs paid from ARO	(53,894		)	(55,893		)	(30,835		)
Property impairment	1,841,274			—			—
*Changes in operating assets and liabilities*
Accounts receivable	—			1,986			(186		)
Accounts receivable from affiliates	326,193			170,151			(35,301		)
Accounts payable	65			2,792			1,998
Accrued liabilities	6,247			—			—

Net cash provided by operating activities	999,168			1,813,194			2,088,533

Cash flows from investing activities:
Proceeds from sale of oil & gas properties	134,839			253,760			93,451
Property development	(557,163		)	(585,584		)	(1,094,017		)

Net cash used in investing activities	(422,324		)	(331,824		)	(1,000,566		)

Cash flows from financing activities:
Payment of note payable	(690,000		)	(625,000		)	(450,000		)
Payment of debt issuance costs	(1,316		)	(16,843		)	(812		)
Distributions to partners	(168,844		)	(682,835		)	(655,321		)

Net cash used in financing activities	(860,160		)	(1,324,678		)	(1,106,133		)

Net increase (decrease) in cash and cash equivalents	(283,316		)	156,692			(18,166		)
Cash and cash equivalents, beginning of year	651,936			495,244			513,410

Cash and cash equivalents, end of year	$	368,620		$	651,936		$	495,244

Supplemental cash flow disclosure
Cash paid for interest expense on note payable	$	17,954		$	56,103		$	80,592
Supplemental disclosure of non-cash investing transactions
Asset retirement obligation reduction resulting from sale and disposition of proved properties	$	(4,692	)	$	(5,859	)	$	(1,605	)
Property sales included in accounts receivable from affiliates	$	—		$	—		$	45,522
Additions to property and asset retirement obligation	$	2,014		$	2,683		$	446,189
Asset retirement obligation in excess of liability	$	(41,671	)	$	—		$	—
Supplemental disclosure of non-cash financing transactions
Partner distributions included in accounts payable	$	2,027		$	—		$	—

~~Statements~~See ofaccompanying ~~Cash~~notes ~~Flows~~to financial statements.

	For the Years Ended December 31,
	2013			2012			2011
Cash flows from operating activities
Net income	$	421,300		$	786,000		$	88,107
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments for non-cash transactions:
Depletion, depreciation and amortization	1,102,611			1,222,493			1,128,514
Accretion of asset retirement obligation	155,345			119,588			78,030
Amortization of deferred financing fees	14,902			24,776			13,553
Plugging and abandonment costs paid from ARO	(55,893		)	(30,835		)	(15,230		)
Changes in operating assets and liabilities
Accounts receivable	1,986			(186		)	—
Accounts receivable from affiliates	170,151			(35,301		)	277,711
Accounts payable	2,792			1,998			3,550
Accrued liabilities	—			—			(9,819		)
Net cash provided by operating activities	1,813,194			2,088,533			1,564,416
Cash flows from investing activities:
Proceeds from sale of oil and gas properties	253,760			93,451			3,059,455
Property development	(585,584		)	(1,094,017		)	(1,344,956		)
Net cash provided by (used in) investing activities	(331,824		)	(1,000,566		)	1,714,499
Cash flows from financing activities:
Payment of note payable	(625,000		)	(450,000		)	(2,985,000		)
Payment of debt issuance costs	(16,843		)	(812		)	(49,816		)
Distributions to partners	(682,835		)	(655,321		)	(867,371		)
Net cash used in financing activities	(1,324,678		)	(1,106,133		)	(3,902,187		)
Net increase (decrease) in cash and cash equivalents	156,692			(18,166		)	(623,272		)
Cash and cash equivalents, beginning of year	495,244			513,410			1,136,682
Cash and cash equivalents, end of year	$	651,936		$	495,244		$	513,410
Supplemental cash flow disclosure
Cash paid for interest expense on note payable	$	56,103		$	80,592		$	160,663
Supplemental disclosure of non-cash investing transactions
Property sales included in accounts receivable from affiliates	$	—		$	45,522		$	—
Additions to property and asset retirement obligation	$	2,683		$	446,189		$	873,886
Adjustment to property and asset retirement obligation	$	—		$	—		$	5,517

F-5

~~See~~Table ~~accompanying~~of ~~notes to financial statements.~~Contents

~~F-5~~Reef Oil & Gas Income and Development Fund III, L.P.

~~Table~~Notes ofto ~~Contents~~Financial Statements

~~Reef~~1. ~~Oil &~~Organization ~~Gas Income~~ and ~~Development~~Basis ~~Fund~~of ~~III, L.P.~~Presentation

~~Notes~~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 ~~Financial~~purchase ~~Statements~~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.

1Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000 each) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated there under, with a maximum offering amount of $90,000,000 (900 units). On ~~Organization~~June 12, 2008, the offering of units of limited and ~~Basis~~general partner interests in the Partnership was closed, with interests aggregating to $88,648,094 being sold to accredited investors, of ~~Presentation~~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.

Reef, ~~Oil &~~as ~~Gas~~managing ~~Income~~general ~~and Development Fund III~~partner, ~~L.P.~~received ~~(the “Partnership”) is~~ a ~~limited~~10% ~~partnership~~general ~~formed~~partner ~~under~~interest in the ~~laws~~Partnership ofas ~~Texas~~compensation onfor ~~November 27,~~forming ~~2007~~the Partnership. ~~The~~This ~~Partnership~~10% ~~was~~interest ~~formed~~is tonot ~~purchase~~represented ~~working~~by ~~interests~~Partnership inunits. ~~oil~~Reef ~~and~~also ~~gas~~acquired ~~properties~~a ~~with~~1% ~~the~~general ~~purposes~~partner ofinterest ~~(i) growing~~as ~~the~~a ~~value~~result of ~~properties~~purchasing ~~through~~1% ~~the development~~ of ~~proved~~total ~~undeveloped~~Partnership ~~reserves,~~units (ii8.9697 units) ~~generating~~. ~~revenue~~The ~~from~~purchase ~~the~~price ~~production~~paid ofby ~~crude~~Reef ~~oil~~for ~~and~~the ~~natural~~units ~~gas,~~it ~~(iii) distributing~~purchased ~~cash~~was tonet ~~the partners~~ of the ~~Partnership,~~15% ~~and~~management ~~(iv) selling~~fee ~~the~~paid ~~properties~~by noinvestors. ~~later~~The ~~than~~units ~~2015,~~purchased inby ~~order~~investor ~~to maximize return to the~~ partners ofrepresented ~~the~~an ~~Partnership. Reef~~89% ~~Oil &~~interest ~~Gas~~in ~~Partners, L.P. (“Reef”) is~~ the ~~managing general partner of the~~ Partnership.

~~Units~~Under ~~of limited and general partner interests in~~ the ~~Partnership~~terms ~~were offered at $100,000 each (with a minimum investment~~ of ¼the ~~unit~~partnership ~~at $25~~agreement,~~000~~ ~~each)~~certain toincome ~~accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933~~ and ~~Regulation~~expense Ditems ~~promulgated~~are ~~there~~allocated ~~under,~~differently ~~with~~between ~~a maximum offering amount of $90,000,000 (900 units). On June 12, 2008,~~ the ~~offering~~managing ~~of units of limited and~~ general partner ~~interests~~and in the ~~Partnership~~investor ~~was~~partners. Allocations ~~closed, with interests aggregating to $88,648,094 being sold to accredited investors,~~ of ~~which~~income ~~$48,984,933 were sold to accredited investors as units of general partner interest~~ and ~~$39,663,161~~expense ~~were sold~~ to ~~accredited~~the ~~investors as units of limited partner interest. As~~ managing general partner, ~~Reef~~and ~~contributed~~investor ~~$762,425~~partners ~~(approximately~~are ~~one~~made ~~percent~~quarterly ~~1%)~~based ofupon the ~~total~~number ~~contributions of the non-Reef general partners~~ and ~~limited~~type ~~partners)~~of topartnership ~~the Partnership in exchange for 8.9697~~ units ofheld ~~general~~at ~~partner~~the ~~interest,~~end ~~resulting in a total capitalization~~ of the ~~Partnership of $89,410,519 before organization and offering costs~~quarter.

~~Reef,~~Cash asdistributions ~~managing~~to ~~general~~partners ~~partner,~~of ~~received~~the anet ~~10%~~cash ~~general~~flow ~~partner~~from ~~interest~~crude inoil ~~the~~and ~~Partnership~~natural asgas ~~compensation~~sales, ~~for~~less ~~forming~~operating, ~~the~~general ~~Partnership.~~and ~~This~~administrative, ~~10%~~and ~~interest~~other iscosts ~~not~~were ~~represented~~previously bydistributed ~~Partnership~~11% ~~units.~~to Reef ~~also~~and ~~acquired~~89% ato 1%investor ~~general~~partners. ~~partner~~Effective ~~interest~~October as1, a2013, ~~result~~Reef ofpurchased ~~purchasing~~0.60 1%units of ~~total~~limited ~~Partnership~~partner ~~units~~interest ~~(8.9697~~from ~~units).~~one ~~The~~of ~~purchase~~the ~~price~~Partnership’s ~~paid~~investor bypartners. ~~Reef~~Thus, ~~for~~effective ~~the~~October 1, ~~units~~2013 itReef ~~purchased~~also ~~was~~receives ~~net~~0.06% of the ~~15%~~distributions ~~management fee~~ paid byto ~~investors~~investor partners. ~~The~~As ~~units~~such, ~~purchased~~effective byOctober 1, 2013 Reef receives 11.06% and investor partners ~~represented~~receive ~~an 89~~88.94% ~~interest~~of intotal ~~the~~cash ~~Partnership~~distributions.

~~Under~~The ~~the~~Partnership ~~terms~~operates ofin ~~the~~only ~~partnership~~one ~~agreement~~industry segment, ~~certain~~which ~~income~~is ~~and expense items are allocated differently between~~ the ~~managing~~exploration, ~~general~~development ~~partner~~ and ~~the~~production ~~investor partners. Allocations~~ of ~~income~~oil, ~~and~~condensate, ~~expense~~natural togas ~~the managing general partner~~ and ~~investor~~natural ~~partners~~gas ~~are~~liquids ~~made~~(“NGL’s”) ~~quarterly~~in ~~based upon~~ the ~~number~~United ~~and type of partnership units held at the end of the quarter~~States.

Cash distributions to partners of the net cash flow from crude oil and natural gas sales, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners2. ~~During~~Summary ~~2013, Reef purchased 0.60 units~~ of ~~limited~~Significant ~~partner~~Accounting interest from one of the investor partners (representing 0.067% of investor partner units). Thus, effective October 1, 2013 Reef also holds 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units, and receives 0.060% of the distributions paid to investor partners. At December 31, 2013, Reef has a total interest in the Partnership of 11.06%.Policies

2.Use ~~Summary~~ of ~~Accounting Policies~~Estimates

~~Use~~The preparation of ~~Estimates~~financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.

~~The~~Cash ~~preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates~~ and ~~judgments~~Cash that affect the amounts reported in the financial statements and accompanying notes. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.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~~cash ~~Equivalents~~equivalents consist of demand deposits and money market

~~The Partnership considers all highly liquid investments with maturity dates of no more than three months from the~~F-6

~~F-6~~Table of Contents

~~Table~~Reef ofOil & ~~Contents~~Gas Income and Development Fund III, L.P.

~~Reef~~Notes ~~Oil &~~to ~~Gas~~Financial ~~Income~~Statements ~~and Development Fund III, L.P.~~(continued)

~~Notes~~investments toinvested ~~Financial~~with ~~Statements~~a ~~(continued)~~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.

~~purchase~~Risks ~~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.Uncertainties

~~Risks~~Historically, the oil and ~~Uncertainties~~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.

~~Historically,~~The ~~the~~Partnership ~~oil~~has ~~and~~not ~~gas~~engaged ~~market~~in commodity futures trading or hedging activities and has ~~experienced~~not ~~significant~~entered ~~price~~into ~~fluctuations.~~derivative ~~Prices~~financial ~~are~~instrument ~~impacted~~transactions byfor ~~local~~trading ~~weather,~~or ~~supply~~other inspeculative ~~the~~purposes. ~~area~~Accordingly, ~~availability~~the ~~and~~Partnership ~~price~~is ofat ~~competitive~~risk ~~fuels,~~for ~~seasonal~~the ~~variations~~volatility in ~~local~~commodity ~~demand,~~prices ~~limited~~inherent ~~transportation~~in ~~capacity~~the tooil ~~other~~and ~~regions~~gas industry, and the ~~worldwide~~level ~~supply~~of ~~and~~commodity ~~demand~~prices ~~for~~has ~~crude~~a ~~oil~~significant impact on the Partnership’s results of operations.

~~The~~Oil ~~Partnership has not engaged in commodity futures trading or hedging activities~~ and ~~has~~Gas 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.Properties

~~Oil~~The Partnership follows the full cost method of accounting for oil and ~~Gas~~gas ~~Properties~~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 barrels of oil equivalent (“BOE”) at a rate of 6 Mcf to 1 Bbl. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

~~The~~In ~~Partnership~~applying ~~follows~~ the full cost method, ofthe ~~accounting~~Partnership ~~for~~performs ~~its~~a ~~oil~~quarterly ~~and~~ceiling ~~gas~~test ~~activities.~~on ~~Under~~the ~~this~~capitalized ~~method,~~costs ~~all~~of ~~direct~~oil ~~costs~~ and ~~certain~~gas ~~indirect~~properties, ~~costs~~whereby ~~associated~~the ~~with~~capitalized ~~acquisition~~costs of ~~properties~~oil and ~~successful~~gas asproperties ~~well~~are aslimited ~~unsuccessful~~to ~~exploration~~the ~~and~~lower ~~development~~of ~~activities~~unamortized ~~are~~cost ~~capitalized.~~or ~~Depreciation,~~the ~~depletion~~cost ceiling, ~~and~~which ~~amortization~~is defined as the sum of ~~capitalized~~the ~~oil~~estimated ~~and~~future ~~gas~~net ~~properties~~revenues ~~and~~from ~~estimated~~the ~~future~~Partnership’s ~~development~~proved ~~costs,~~reserves ~~excluding~~using ~~unproved~~prices ~~properties,~~that are ~~based~~the onpreceding 12-month un-weighted arithmetic average of the ~~unit~~first-day-of-~~production~~the-month ~~method~~price ~~using~~for ~~estimated~~crude ~~proved~~oil ~~reserves. For~~and ~~these~~natural ~~purposes~~gas held constant and discounted at 10%, ~~proved~~plus ~~natural~~the ~~gas~~lower ~~reserves~~of ~~are~~cost ~~converted~~or toestimated ~~barrels~~fair value of ~~oil~~unproved ~~equivalent~~properties, ~~(“BOE”)~~if atany. aIf ~~rate~~capitalized ofcosts 6exceed ~~Mcf~~the toceiling, 1an ~~Bbl.~~impairment ~~Under~~loss is recognized for the ~~full~~amount ~~cost~~by ~~method~~which ofthe ~~accounting~~capitalized costs exceed the ceiling, ~~sales~~and oris ~~other~~shown ~~dispositions~~as a reduction of oil and gas properties ~~are~~and ~~accounted~~as ~~for~~property asimpairment ~~adjustments~~expense toon ~~capitalized~~the ~~costs~~Partnership’s statements of operations. During the year ended December 31, ~~with~~2014, nothe ~~gain~~Partnership orrecognized ~~loss~~$1,841,274 ~~recorded~~of ~~unless~~impairment ~~such~~expense ~~disposition~~of ~~would~~proved ~~significantly~~properties. ~~alter~~During the ~~relationship~~years ~~between~~ended ~~capitalized~~December 31, ~~costs~~2013, and 2012, the Partnership recognized no property impairment expense of proved ~~reserves~~properties.

InUnproved ~~applying~~property ~~the~~consists ~~full~~of ~~cost~~undrilled ~~method,~~infill ~~the~~and ~~Partnership~~offset isacreage ~~required~~acquired toin ~~perform~~connection awith ~~quarterly~~the ~~ceiling~~purchase ~~test~~of on the ~~capitalized~~Azalea ~~costs~~Properties ofin ~~oil~~2010. ~~and~~Investments ~~gas~~in ~~properties,~~unproved ~~whereby~~property ~~the~~are ~~capitalized~~not ~~costs~~subject ofto ~~oil~~depletion ~~and~~until ~~gas~~they ~~properties~~ are ~~limited~~either toimpaired ~~the~~or ~~sum~~developed. Unproved property is assessed for impairment quarterly as of the ~~estimated~~balance ~~future~~sheet ~~net~~date. ~~revenues~~In ~~from~~determining ~~proved~~whether ~~reserves~~an ~~using~~unproved ~~prices~~property ~~that~~is ~~are~~impaired, the ~~preceding~~Partnership ~~12-month~~considers ~~un-weighted~~numerous ~~arithmetic~~factors ~~average~~including, ofbut ~~the~~not ~~first-day-of-~~limited to, the~~-month~~ ~~price~~following ~~for~~items: ~~crude~~intent ~~oil~~to ~~and~~drill; ~~natural~~remaining ~~gas~~primary ~~held~~lease ~~constant~~term; ~~and~~drilling ~~discounted~~results atand ~~10%,~~activity ~~plus~~in the ~~lower~~immediate area of ~~cost~~the orproperty; ~~estimated~~the ~~fair~~holding ~~value~~period of ~~unproved~~the ~~properties~~property, ifgeological ~~any~~and geophysical evaluation and current market conditions. IfTo ~~capitalized~~the ~~costs~~extent ~~exceed~~that the ~~ceiling~~assessment indicates a property is impaired, anthe impairment ~~loss~~amount is ~~recognized~~re-classed ~~for~~from unproved property to the ~~amount~~proved byproperty ~~which~~full ~~the~~cost ~~capitalized~~pool ~~costs~~and ~~exceed~~subjected to depletion and the quarterly full cost ceiling, ~~and~~test. isAfter ~~shown~~considering asthe aholding ~~reduction~~period of ~~oil~~the ~~and~~Azalea ~~gas~~unproved properties ~~and~~as well as ~~property~~current ~~impairment~~market ~~expense~~conditions onat December 31, 2014, the Partnership’s ~~statements~~impaired unproved property totaling $361,865 during the fourth quarter of ~~operations~~2014. This amount was re-classed from unproved property to the proved property full cost pool and subjected to depletion and the full cost ceiling test at December 31, 2014. During the years ended December 31, 2013, ~~2012,~~ and ~~2011~~2012, the Partnership recognized no property impairment ~~expense~~ of ~~proved~~unproved ~~properties~~property.

~~Unproved~~Estimates ~~property consists~~ of ~~undrilled~~Proved ~~infill~~Oil and ~~offset~~Gas acreage acquired in connection with the purchase of the Azalea Properties. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date. The assessment includes consideration of the following factors, among others: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property; and geological and geophysical evaluation. To the extent that the assessment indicates a property is impaired, the amount of impairment is added to the capitalized costs of oil and gas properties which are subject to the quarterly ceiling test. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment of unproved properties.Reserves

FThe estimates of the Partnership’s proved reserves at December 31, 2014, 2013, and 2012 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-7weighted arithmetic average of the first-day-of-the-month

~~Table of Contents~~F-7

~~Reef~~Table ~~Oil &~~of ~~Gas Income and Development Fund III, L.P.~~Contents

~~Notes~~Reef toOil & ~~Financial~~Gas ~~Statements~~Income ~~(continued)~~and Development Fund III, L.P.

~~The~~Notes ~~Partnership excludes from amortization the cost of unproved properties. The Partnership expects that all unproved property costs incurred will be transferred~~ to ~~proved~~Financial ~~property~~Statements cost within 10 years of their acquisition. The following schedule shows, by the year in which they were incurred, the amount of all unproved property cost not currently being amortized as of December 31, 2013.(continued)

	Total		2010
Acquisition costs — unproved property	$	389,672	$	389,672
Total costs withheld from amortization	$	389,672	$	389,672

commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by independent petroleum engineers.

~~Estimates~~Reservoir engineering, which is the process of ~~Proved~~estimating ~~Oil~~quantities of crude oil and ~~Gas~~natural ~~Reserves~~gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

~~The~~Reserves ~~estimates~~and oftheir ~~the~~relation ~~Partnership’s~~to ~~proved~~estimated ~~reserves~~future atnet ~~December 31,~~cash ~~2013,~~flows ~~2012,~~impact ~~and~~the ~~2011~~Partnership’s ~~have~~depletion ~~been~~and ~~prepared~~impairment ~~and~~calculations. ~~presented~~As ina ~~accordance~~result, ~~with~~adjustments ~~SEC~~to ~~rules~~ depletion and ~~accounting~~impairment ~~standards~~are ~~which~~made ~~require~~concurrently ~~SEC~~with ~~reporting~~changes ~~entities~~ to ~~prepare their~~ reserve estimates. ~~using~~If ~~pricing~~proved ~~based~~reserve ~~upon~~estimates decline, the ~~un-weighted~~rate ~~arithmetic~~at ~~average~~which ofdepletion ~~the~~expense ~~first-day-of-the-month~~is ~~commodity~~recorded ~~prices~~increases, ~~over~~reducing ~~the~~future ~~preceding~~net ~~12-month~~income. ~~period~~A ~~and~~decline ~~year~~in ~~end~~estimated ~~costs.~~proved ~~Future~~reserves ~~prices~~ and ~~costs~~future ~~may~~cash beflows, ~~materially~~whether ~~higher~~caused orby ~~lower~~declining ~~than~~commodity ~~these~~ prices ~~and~~or ~~costs,~~downward ~~which~~adjustments ~~would~~to ~~impact~~ the ~~estimate~~rate of ~~reserves~~production ~~and~~from ~~future cash flows. The~~ Partnership’s ~~proved~~wells, ~~reserve~~also ~~information~~reduces ~~included~~the incapitalized ~~this~~cost ~~report~~ceiling ~~was~~and ~~based~~may ~~upon~~result ~~evaluations~~in ~~prepared~~increased byimpairment ~~independent petroleum engineers~~expense.

~~Reservoir engineering~~Restoration, ~~which is the process of estimating quantities of crude oil and natural gas reserves~~Removal, ~~is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering,~~ and ~~economic~~Environmental data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.Liabilities

~~Reserves~~The ~~and~~Partnership ~~their~~is ~~relation~~subject to ~~estimated~~extensive ~~future~~Federal, ~~net~~state ~~cash~~and ~~flows~~local ~~impact~~environmental ~~the~~laws ~~Partnership’s depletion~~ and ~~impairment calculations~~regulations. AsThese alaws ~~result,~~regulate ~~adjustments~~the todischarge ~~depletion~~of ~~and~~materials ~~impairment~~into ~~are~~the ~~made~~environment ~~concurrently~~and ~~with~~may ~~changes~~require the Partnership to ~~reserve~~remove ~~estimates.~~or Ifmitigate ~~proved~~the ~~reserve~~environmental ~~estimates~~effects ~~decline,~~of the ~~rate~~disposal ator ~~which~~release ~~depletion~~of ~~expense~~petroleum issubstances ~~recorded~~at ~~increases,~~various ~~reducing~~sites. ~~net~~Environmental ~~income.~~expenditures Aare ~~decline~~expensed inor ~~estimated~~capitalized ~~proved~~depending ~~reserves~~on ~~and~~their future ~~cash~~economic ~~flows~~benefit. ~~also~~Expenditures ~~reduces~~that ~~the~~relate ~~capitalized~~to ~~cost~~an ~~ceiling~~existing condition caused by past operations and ~~may~~that ~~result~~have inno ~~increased~~future ~~impairment~~economic ~~expense~~benefit are expensed.

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

The Partnership ishas ~~subject~~recognized toan ~~extensive~~estimated ~~Federal,~~liability ~~state~~for ~~and~~future ~~local~~plugging ~~environmental laws~~ and ~~regulations~~abandonment costs. ~~These~~A ~~laws~~liability ~~regulate~~for the ~~discharge~~estimated offair ~~materials~~value ~~into~~of the ~~environment~~future plugging and ~~may~~abandonment ~~require~~costs ~~the~~is ~~Partnership~~recorded towith ~~remove~~a orcorresponding ~~mitigate~~increase ~~the~~in ~~environmental effects of~~ the ~~disposal~~full orcost ~~release~~pool ~~of petroleum substances~~ at ~~various~~the ~~sites.~~time ~~Environmental~~a ~~expenditures~~new ~~are~~well ~~expensed~~is drilled or ~~capitalized depending on their future economic benefit~~acquired. Depreciation ~~Expenditures~~expense ~~that~~associated ~~relate~~with toestimated anplugging ~~existing~~and ~~condition~~abandonment ~~caused~~costs byis ~~past~~recognized ~~operations~~in ~~and~~accordance ~~that~~with ~~have~~the nofull ~~future~~cost ~~economic benefit are expensed~~methodology.

~~Liabilities~~The ~~for~~Partnership ~~expenditures~~estimates of a ~~non-capital~~liability ~~nature~~for ~~are~~plugging ~~recorded~~and ~~when~~abandonment ~~environmental~~costs ~~assessments~~based on historical experience and~~/or~~ ~~remediation~~estimated well life. The liability is ~~probable,~~discounted ~~and~~using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs ~~can~~or bewell ~~reasonably~~useful ~~estimated.~~lives, ~~Such~~or ~~liabilities~~if ~~are~~federal ~~generally~~or ~~undiscounted~~state ~~values~~regulators ~~unless~~enact ~~the~~new ~~timing~~well ofrestoration ~~cash~~requirements. ~~payments~~The ~~for~~Partnership recognizes accretion expense in connection with the discounted liability orover ~~component~~the isremaining ~~fixed~~life orof ~~reliably~~the ~~determinable~~well.

The ~~Partnership~~following ~~has~~table ~~recognized~~summarizes anthe ~~estimated~~Partnership’s ~~liability~~asset ~~for~~retirement ~~future~~obligation ~~plugging and abandonment costs. A liability~~ for the ~~estimated~~periods ~~fair~~ended ~~value~~December 31, of2014 ~~the future plugging~~ and ~~abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired~~2013. ~~Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.~~

	2014			2013
Beginning asset retirement obligation	$	2,463,175		$	2,366,899
Additions related to new properties	2,014			2,683
Retirement related to sale and disposition of proved properties	(4,692		)	(5,859		)
Retirement related to property abandonment and restoration	(95,565		)	(55,893		)
Accretion expense	163,490			155,345
Ending asset retirement obligation	$	2,528,422		$	2,463,175

F-8

Table of Contents

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

Notes to Financial Statements (continued)

~~regulators~~Recognition ~~enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life~~ of ~~the well.~~Revenue

The ~~following~~Partnership ~~table~~has ~~summarizes~~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 Partnership’s ~~asset~~share ~~retirement~~of ~~obligation~~metered ~~for~~volumes ~~the~~delivered ~~periods~~to ~~ended~~its purchasers each month. The Partnership had no material gas imbalances at December 31, 2014, 2013, and 2012.

	2013			2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	2,683			7,579
Revisions related to existing properties	—			438,610
Retirement related to property sales	(5,859		)	(1,605		)
Retirement related to property abandonment and restoration	(55,893		)	(32,388		)
Accretion expense	155,345			119,588
Ending asset retirement obligation	$	2,463,175		$	2,366,899

Income Taxes

~~Recognition~~The Partnership’s net income or loss flows directly through to its partners, who are responsible for the payment of ~~Revenue~~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.

~~The~~As ~~Partnership~~of ~~has~~December 31, ~~entered~~2014, ~~into~~the ~~sales~~tax ~~contracts~~basis ~~for~~of ~~disposition~~the ofPartnership’s ~~its~~assets ~~share~~exceeds ofthe ~~crude~~financial ~~oil~~reporting ~~and~~basis ~~natural~~of ~~gas~~the ~~production~~assets ~~from~~by ~~productive~~approximately ~~wells~~$19.6 ~~Revenue~~million, isprimarily ~~recognized~~due ~~based~~to ~~upon~~ the ~~Partnership’s~~difference ~~share~~between ofproperty ~~metered~~impairment ~~volumes~~costs ~~delivered~~deducted tofor ~~its~~financial ~~purchasers~~reporting ~~each~~purposes ~~month.~~and ~~The~~intangible ~~Partnership~~drilling ~~had~~costs nodeducted ~~material~~for ~~gas~~income ~~imbalances~~tax ~~at December 31, 2013, 2012, and 2011~~purposes.

Accounting for Uncertainty in Income Taxes

~~The~~Accounting ~~Partnership’s~~Standards ~~net~~Codification ~~income~~(“ASC”) orsection ~~loss~~740 ~~flows~~provides ~~directly~~guidance ~~through~~on toaccounting ~~its~~for ~~partners,~~uncertainty ~~who~~in ~~are~~income ~~responsible~~taxes. ~~for~~ASC 740 is intended to clarify the ~~payment~~accounting offor ~~Federal~~uncertainty in income taxes onrecognized ~~their~~in ~~respective~~a ~~share~~company’s financial statements and prescribes the recognition and measurement of ~~any~~a ~~income~~tax position taken or ~~loss~~expected to be taken in a tax return. ~~Therefore,~~ASC ~~there~~740 isalso noprovides ~~provision~~guidance ~~for~~on ~~federal~~de-recognition, ~~income~~classification, ~~taxes~~interest and penalties, accounting in ~~the~~interim ~~accompanying~~periods, ~~financial~~and ~~statements~~disclosure.

AsUnder ofASC ~~December 31~~740, ~~2013,~~evaluation ~~the~~of a tax ~~basis~~position ofis ~~the~~a ~~Partnership’s~~two-step ~~assets~~process. ~~exceeds~~The ~~the~~first ~~financial~~step ~~reporting~~is ~~basis~~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 ~~assets~~technical bymerits ~~approximately~~of ~~$20~~that position.1 ~~million,~~The ~~primarily~~second ~~due~~step is to measure a tax position that meets the ~~difference~~more-likely-than-not ~~between~~threshold ~~property~~to ~~impairment~~determine ~~costs~~the ~~deducted~~amount ~~for~~of benefit to be recognized in the financial ~~reporting~~statements. ~~purposes~~A ~~and~~tax ~~intangible~~position ~~drilling~~is ~~costs~~measured ~~deducted~~at ~~for~~the ~~income~~largest ~~tax~~amount ~~purposes~~of benefit that is greater than 50% likely of being realized upon ultimate settlement.

~~Accounting~~Tax ~~for~~positions ~~Uncertainty~~that previously failed to meet the more-likely-than-not recognition threshold should be recognized in ~~Income~~the ~~Taxes~~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.

~~The~~Based ~~Financial~~on ~~Accounting~~the ~~Standards~~Partnership’s ~~Board~~assessment, ~~(“FASB”)~~there ~~provides~~are ~~guidance~~no onmaterial ~~accounting~~uncertain ~~for~~tax ~~uncertainty~~positions inas ~~income~~of ~~taxes.~~December 31, ~~This~~2014 ~~guidance~~and 2013. The Partnership is ~~intended~~subject to ~~clarify~~examination ~~the~~of ~~accounting for uncertainty in~~ income ~~taxes~~tax ~~recognized~~filings in ~~a company’s financial statements and prescribes~~ the ~~recognition~~U.S. and ~~measurement~~various ofstate ajurisdictions ~~tax~~for ~~position~~the ~~taken~~years orended ~~expected~~December 31, to2014, be2013, ~~taken~~and ~~in a tax return~~2012. The ItPartnership ~~also~~has ~~provides~~not ~~guidance~~been onsubjected ~~de-recognition,~~to ~~classification,~~any ~~interest~~audits ~~and~~by ~~penalties,~~the ~~accounting~~Internal inRevenue ~~interim~~Service ~~periods,~~for ~~and~~these ~~disclosure~~periods.

~~Under~~Fair ~~this~~Value ~~guidance, evaluation~~ of aFinancial 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.Instruments

~~Tax~~The ~~positions~~estimated ~~that~~fair ~~previously~~values ~~failed~~for tofinancial ~~meet~~instruments ~~the~~have ~~more-likely-than-not~~been ~~recognition~~determined ~~threshold~~at ~~should~~discrete bepoints ~~recognized~~ in ~~the~~time ~~first~~based ~~subsequent~~on ~~period~~relevant inmarket ~~which~~information. ~~the~~These ~~threshold~~estimates isinvolve ~~met~~uncertainties and cannot be determined with precision. The ~~Previously~~estimated ~~recognized~~fair ~~tax~~value ~~positions~~of ~~that~~cash, noaccounts ~~longer~~receivable ~~meet~~from ~~the~~affiliates, ~~more~~accounts payable and accrued liabilities approximates their carrying value due to their short-~~likely-than-not~~term ~~criteria~~nature. The ~~should~~fair bemarket devalue of the Partnership’s long-~~recognized~~term indebt approximates the ~~first~~carrying ~~subsequent~~value ~~reporting~~at ~~period~~December 31, in2013, ~~which~~as it is subject to short-term floating interest rates that approximate the ~~threshold~~rates isavailable noto ~~longer~~the ~~met.~~Partnership ~~Penalties~~for ~~and~~those ~~interest~~periods, ~~are~~and is classified as ~~income~~Level ~~tax~~2 ~~expense~~within the fair value hierarchy.

~~Based~~Comprehensive on the Partnership’s assessment, there are no material uncertain tax positions as of December 31, 2013 and 2012. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2013 and 2012. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.Income

FComprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-9owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the

~~Table of Contents~~F-9

~~Reef~~Table ~~Oil &~~of ~~Gas Income and Development Fund III, L.P.~~Contents

~~Notes~~Reef toOil & ~~Financial~~Gas ~~Statements~~Income ~~(continued)~~and Development Fund III, L.P.

~~Fair~~Notes ~~Value~~to of Financial ~~Instruments~~Statements (continued)

~~The~~statements 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,~~operations ~~accounts~~equals ~~receivable,~~comprehensive ~~accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature~~income. The fair market value of the Partnership’s long-term debt approximates the carrying value at December 31, 2013 and 2012, as it is subject to short-term floating interest rates that approximate the rates available to the Partnership for those periods, and is classified as Level 2 within the fair value hierarchy.

~~Comprehensive~~Recent ~~Income~~Accounting Developments

~~Comprehensive~~The ~~income~~following isrecently ~~defined~~issued asaccounting apronouncement ~~change~~has inbeen ~~equity~~adopted ofor amay ~~business~~impact ~~enterprise~~the during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership ~~has no items of comprehensive income other than net income~~ in ~~any~~future ~~period~~periods: ~~presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.~~

Revenue Recognition. The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenues arising from contracts to provide goods or services to customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following five steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract(s); (5) recognize revenue when (or as) the entity satisfies a performance obligation. ~~Long~~The requirements from the new ASU will supersede prior revenue recognition requirements and most prior industry-~~Term~~specific ~~Debt~~guidance throughout the FASB’s ASC, and will be effective for all interim and annual periods beginning after December 15, 2016. The Partnership is still considering the method of adoption but does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flow.

~~On June 30, 2010, the Partnership and Texas Capital Bank, N~~3.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding an acquisition. The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. At December 31, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable. The Credit Agreement is a reducing revolving credit facility, and is subject to semiLong-~~annual~~Term redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans. At December 31, 2013, the borrowing base and the current outstanding loan balance are $690,000, and the borrowing base reduces at a rate of $30,000 per month. Therefore, the Partnership has recognized $360,000 of the note payable balance due as a current liability on the accompanying balance sheet. The Partnership has no plans to request any additional borrowing or changes to the borrowing base, and does not expect to extend the term of the loan beyond its current expiration date of June 30, 2015. The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.Debt

~~The~~On June 30, 2010, the Partnership ~~has~~and ~~paid~~Texas ~~TCB~~Capital ~~certain~~Bank, ~~facility~~N.A. ~~fees~~(“TCB”) ~~and~~entered ~~engineering~~into ~~fees~~a inCredit ~~connection~~Agreement ~~with~~(the ~~prior~~“Credit ~~year~~Agreement”) ~~redeterminations~~with ofa ~~the~~$5,000,000 borrowing base~~. The~~, ~~Partnership~~and isa ~~obligated~~related topromissory ~~pay~~note ~~additional~~and ~~facility~~security ~~fees~~agreement ~~upon~~for ~~each~~purposes ~~determination~~ of anfunding ~~increase~~a inproperty ~~the~~acquisition. ~~borrowing~~The ~~base,~~per ~~and~~annum ~~additional~~interest ~~engineering~~rate ~~fees~~was ifequal ~~TCB’s~~to ~~internal~~the ~~engineers~~U.S. ~~perform~~prime anrate ~~engineering~~as ~~review~~published ofby the ~~collateral,~~Wall orStreet ~~the~~Journal’s ~~actual~~“Monday ~~fees~~Rates” ~~and~~plus ~~expenses~~0.5%, with a minimum interest rate of ~~any~~5%, ~~third-party~~payable ~~engineers~~monthly. The ~~retained~~obligations byof TCB to ~~prepare~~the anPartnership ~~engineering~~under ~~report,~~the ~~payable~~Credit atAgreement ~~the~~were ~~time~~to ofexpire aon ~~redetermination~~June 30, of2015, ~~the~~at ~~borrowing~~which ~~base.~~point ~~The~~the ~~Partnership~~promissory ~~has~~note nowas ~~plans~~ to ~~request~~mature, aand ~~redetermination~~any ofunpaid ~~the~~principal ~~borrowing~~and ~~base.~~interest ~~The~~would ~~fees~~have ~~paid~~become indue ~~connection~~and ~~with~~payable. The ~~prior~~Credit ~~borrowing~~Agreement ~~base~~was ~~redeterminations~~a ~~have~~reducing ~~been~~revolving ~~capitalized~~credit byfacility, ~~the~~and ~~Partnership~~was assubject ~~Deferred~~to ~~Financing~~semi-annual ~~Fees~~redetermination onof the ~~accompanying~~borrowing ~~balance~~base ~~sheets,~~in ~~and~~accordance ~~are~~with ~~being~~the ~~amortized~~TCB’s ~~over~~customary ~~the~~practices ~~remaining~~for ~~term~~oil ofand ~~the~~gas ~~Credit Agreement~~loans.

The ~~Credit~~Partnership ~~Agreement~~had isthe ~~guaranteed~~right byto ~~two~~prepay ~~Reef~~principal ~~affiliated~~and ~~entities.~~accrued ~~Borrowings~~interest ~~under~~thereon ~~the~~in ~~Credit~~whole ~~Agreement~~or ~~are~~in ~~secured~~part byat aany ~~first~~time ~~priority~~without ~~lien~~premium onor nopenalty. ~~less~~During ~~than~~2014, ~~90% of~~ the ~~oil~~Partnership ~~and~~made ~~gas~~various ~~properties~~pre-payments ~~utilized~~of inprincipal ~~determining~~on the ~~borrowing~~promissory ~~base~~note, ~~based~~utilizing onproceeds ~~the~~from ~~net~~property ~~present~~sales ~~value~~and ofcurrent ~~the~~cash ~~crude~~flows. ~~oil~~The ~~and~~Partnership ~~natural~~completed ~~gas~~repayment toof ~~be produced from~~ the ~~oil~~promissory ~~and~~note ~~gas~~balance ~~properties~~during ~~calculated~~December 2014 ~~using~~and aterminated ~~discount~~the ~~rate~~Credit ofAgreement ~~nine~~with ~~percent~~TCB ~~(9.00%)~~on ~~per~~December 31, ~~annum~~2014.

OnThe ~~April 30, 2013, the~~ Partnership ~~entered~~paid ~~into~~TCB ~~the~~certain ~~Third~~facility ~~Amendment~~fees toand ~~the~~engineering ~~Credit~~fees ~~Agreement~~in ~~(“Third~~connection ~~Amendment”),~~ with ~~TCB. The~~prior ~~Third~~year ~~Amendment~~redeterminations ~~extended the final maturity date~~ of the ~~Credit~~borrowing ~~Agreement and the obligations thereunder from June 30, 2013 to June 30, 2015~~base. ~~During~~ ~~May 2013,~~The ~~the~~fees ~~Partnership~~ paid ~~TCB fees of $13,150~~ in connection with ~~the~~these ~~Third~~prior ~~Amendment. These~~borrowing ~~fees,~~base asredeterminations ~~well~~were ascapitalized ~~attorney~~by ~~fees paid in connection with~~ the ~~Third~~Partnership ~~Amendment, have been capitalized~~ as Deferred Financing Fees ~~on the accompanying balance sheet~~ and ~~are being~~ amortized over the ~~remaining~~ term of the Credit Agreement.

~~The~~4. ~~Credit~~Transactions ~~Agreement~~with ~~contains various covenants, including among others:~~Affiliates

F-Reef purchased 1% of the Partnership units, and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. Cash distributions to partners of the net cash flow from crude oil and natural gas sales revenues, less operating, general and administrative, and other costs were previously distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. Thus, effective October 1, 2013 Reef also receives 0.06% of the distributions paid to investor partners. As such, effective October 1, 2013 Reef receives 11.06% and investor partners receive 88.94% of total cash distributions. During the years ended December 31, 2014, 2013 and 2012, Reef received $18,796, $75,112, and $72,085, respectively, in cash distributions related to its 11% interest, and received $103 and $142 during the years ended December 31, 2014 and 2013 related to its 0.06% limited partner interest. From funds generated by its carried interest and management fee, Reef pays to specific FINRA-licensed broker-dealers on a quarterly basis a fee in an 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 fee is recorded as a commission expense by Reef.

~~Table~~Reef Exploration, L.P. (“RELP”), an affiliate of ~~Contents~~Reef, the managing general partner of the Partnership, receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the

~~Reef Oil & Gas Income and Development Fund III, L.P.~~F-10

~~Notes~~Table toof ~~Financial Statements (continued)~~Contents

~~· restrictions~~Reef onOil & ~~liens;~~Gas Income and Development Fund III, L.P.

~~· restrictions~~Notes onto ~~incurring~~Financial ~~other~~Statements ~~indebtedness without the lenders’ consent;~~ (continued)

~~· restrictions~~Partnership onfor ~~distributions~~non-operated wells. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point. In addition, total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other ~~restricted~~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, 2014, 2013 and 2012, RELP received $21,201, $25,602, and $39,856, respectively, in drilling compensation. Drilling compensation payments; are included in oil and gas properties in the financial statements.

~~· maintenance~~Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket aexpenses ~~current~~incurred ~~ratio~~on asbehalf of the ~~end~~Partnership. ofDuring ~~each~~the ~~fiscal~~year ~~quarter~~ended December 31, 2014, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket ~~not~~expenses ~~less~~of ~~than~~$96,804 and $1,130, respectively.0 toDuring the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively.0 During the year ended December 31, as2012, ~~adjusted;~~Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively.

~~· maintenance~~RELP ofallocates anits ~~interest~~general ~~coverage~~and ~~ratio~~administrative expenses as overhead to all of ~~cash~~the ~~flow~~partnerships to ~~fixed~~which ~~charges~~it asprovides services, and this allocation is a significant portion of the ~~end~~Partnership’s general and administrative expenses. The allocation of ~~each~~RELP’s ~~fiscal~~overhead ~~quarter~~to the partnerships to which it provides services is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to bethe attotal ~~least~~levels 3of all partnerships.0 During the years ended December 31, 2014, 2013, and 2012, the administrative overhead charged by RELP to 1the Partnership totaled $431,793, $489,183, and $567,424, respectively.0 The administrative overhead charged by RELP is included in general and administrative expense in the accompanying statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

~~All~~RELP ~~outstanding~~processes ~~amounts~~joint ~~owed~~interest ~~under~~billings and revenues on behalf of the ~~Credit~~Partnership. ~~Agreement~~At ~~become~~December 31, ~~due~~2014 and ~~payable~~2013, ~~upon~~RELP owed the ~~occurrence~~Partnership $183,078 and $509,271, respectively, for net revenues processed in excess of ~~certain~~net ~~usual~~joint interest and ~~customary~~technical ~~events~~and ofadministrative ~~default,~~service ~~including~~charges. The ~~among~~cash ~~others:~~associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.

~~· failure~~In September 2012, the Partnership sold leasehold interests related to ~~make~~a ~~payments~~non-operated ~~under~~three well drilling program in the ~~Credit~~Covington ~~Agreement;~~Prospect in Ward County, Texas to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“Reef 2012-A”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells. The sales price was $201,573, of which $93,451 was received in 2012 and the remainder during 2013. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to this transaction, as it did not significantly affect the unit-of-production amortization rate.

~~· non-performance~~5. ofMajor ~~covenants and obligations continuing beyond any applicable grace period; and~~ Customers

~~· the~~The ~~occurrence~~Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of apetroleum ~~“Change~~commodities. inRevenues ~~Control”~~are ~~(as~~received ~~defined~~directly from these parties or, in certain circumstances, paid to the ~~Credit~~operator ~~Agreement)~~of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, 2014, one marketer and one operator accounted for 37.5% and 36.0% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2013, one marketer and one operator accounted for 38.0% and 32.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2012, one marketer and one operator accounted for 34.6% and 26.8% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

At December 31, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into a Partnership bank account maintained at the lender. A waiver of this requirement has been obtained.F-11

4.Table ~~Transactions~~of ~~with Affiliates~~Contents

Reef purchased 1% of the Partnership units, and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. Cash distributions to partners of the net cash flow from crude oil and natural gas sales revenues, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners. In addition, effective OctoberOil 1,& ~~2013,~~Gas asIncome a result of Reef’s purchase of 0.60 units of limited partner interest from an investor, Reef receives 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units. During the years ended December 31, 2013, 2012 and ~~2011,~~Development ~~Reef~~Fund ~~received $75~~III,~~112,~~ ~~$72,085, and $107,464, respectively, in cash distributions related to its 11% interest, and received $142 during the year ended December 31, 2013 related to its units of limited partner interest~~L. 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 unitsP. ~~This was recorded as a commission expense by Reef.~~

~~Reef~~Notes ~~Exploration, L.P. (“RELP”), an affiliate of Reef, the managing general partner of the Partnership, receives drilling compensation in an amount equal~~ to ~~15%~~Financial ofStatements the total well costs paid by the Partnership for wells operated by RELP. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point. In addition, total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion. Total well costs do not include costs relating to lease acquisitions. During the years ended December 31, 2013, 2012 and 2011, RELP received $25,602, $39,856, and $54,005, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.(continued)

~~Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership~~6. ~~During~~Commitments ~~the year ended December 31, 2013, Reef~~ and ~~its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively.~~Contingencies

~~F-11~~The Partnership is not currently involved in any legal proceedings.

~~Table~~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 Properties. During the years ended December 31, 2014, 2013, and 2012, William R. Dixon received $19,379, $17,147, and $23,819, respectively, related to this overriding royalty interest. At December 31, 2014, the estimated net proved reserves of ~~Contents~~the Slaughter Dean Properties, as determined by the independent engineering firm used by the Partnership, had a remaining economic life of 27 years.

~~Reef~~7. ~~Oil &~~Partnership ~~Gas Income and Development Fund III, L.P.~~Equity

~~Notes~~Information toregarding ~~Financial~~the ~~Statements~~number of units outstanding and the net income (~~continued~~loss) per type of Partnership unit for the years ended December 31, 2014, 2013 and 2012 is detailed below:

~~During~~For the year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively. During the year ended December 31, 2011, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $342,271 and $2,818, respectively.2014

Prior to January 1, 2012, RELP received 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, totaling $74,740 per month. During the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from the fixed monthly amount referenced above to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the years ended December 31, 2013, 2012, and 2011, RELP received administrative fees totaling $489,183, $567,424, and $896,880, respectively. Administrative fees are included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

Type of Unit	Number of Units	Net income (loss)			Net income (loss) per unit
Managing general partner	8.9697	$	29,212		$	3,256.80
General partner	490.9827	(1,395,034		)	$	(2,841.31	)
Limited partner	397.0172	(1,128,048		)	$	(2,841.31	)
Total	896.9696	$	(2,493,870	)

~~RELP~~For ~~processes joint interest billings and revenues on behalf of~~ the ~~Partnership.~~year Atended December 31, 2013 and 2012, RELP owed the Partnership $509,271 and $633,900, respectively, for net revenues processed in excess of net joint interest and technical and administrative service charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.

In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The Partnership received $350,000 in cash in exchange for these interests. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P. The Partnership received $2,650,000 in cash in exchange for these additional interests. These sales transactions reduced the full cost pool of capitalized oil and gas properties. The Partnership recorded no gain or loss associated with these transactions.

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	156,604	$	17,459.23
General partner	490.9827	146,353		$	298.08
Limited partner	397.0172	118,343		$	298.08
Total	896.9696	$	421,300

InFor ~~September 2012,~~ the ~~Partnership~~year ~~sold~~ended leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“purchaser”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three new drilled wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this transaction.

5. Major Customers

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	208,709	$	23,268.23
General partner	490.9827	319,189		$	650.10
Limited partner	397.0172	258,102		$	650.10
Total	896.9696	$	786,000

~~F-12~~We have evaluated subsequent events and determined that no subsequent events have occurred that would require recognition in the financial statements or disclosure in the notes thereto other than as discussed in the accompanying notes.

~~Table of Contents~~F-12

~~Reef~~Table ~~Oil &~~of ~~Gas Income and Development Fund III, L.P.~~Contents

~~Notes~~Reef toOil & ~~Financial~~Gas ~~Statements~~Income ~~(continued)~~and Development Fund III, L.P.

~~crude~~Notes oil and natural gas revenues, respectively. During the year ended December 31, 2011, one marketer and one operator accounted for 34.9% and 29.4% of the Partnership’s crude oil and natural gas revenues, respectively. Due to ~~the~~Financial ~~competitive~~Statements ~~nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.~~(continued)

69. ~~Commitments~~Supplemental Information on Oil & Natural Gas Exploration and ~~Contingencies~~Production Activities (unaudited)

~~The~~Capitalized ~~Partnership is not currently involved in any legal proceedings.~~Costs

The ~~Partnership~~following ~~entered~~table ~~into~~presents ~~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~~aggregate ~~interest,~~capitalized tocosts ~~William~~relating ~~R. Dixon in exchange for Dixon’s agreement~~ to ~~“review~~oil and ~~evaluate~~gas ~~exploration,~~activities ~~exploitation,~~at ~~and development drilling opportunities.” This overriding royalty interest burdens~~ the ~~Partnership’s~~end ~~working~~of ~~interest in~~ the ~~Slaughter~~periods ~~Dean wells. During the years ended December 31, 2013, 2012, and 2011, William R. Dixon received $17,147, $23,819, and $21,914, respectively, related to this overriding royalty interest.~~indicated:

7. Partnership Equity

	December 31, 2014			December 31, 2013			December 31, 2012

Oil and natural gas properties:
Unproved properties	$	—		$	389,672		$	524,357
Proved properties	75,650,205			75,083,374			74,628,075
Capitalized asset retirement cost	2,118,163			2,126,682			2,124,314
	77,768,368			77,599,728			77,276,746
Less:
Accumulated depreciation, depletion and amortization	(6,197,743		)	(5,212,971		)	(4,116,026		)
Property impairment	(60,453,728		)	(58,612,454		)	(58,612,454		)
	(66,651,471		)	(63,825,425		)	(62,728,480		)

Total	$	11,116,897		$	13,774,303		$	14,548,266

~~Information~~Costs ~~regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the years ended December 31, 2013, 2012 and 2011 is detailed below:~~Incurred

~~For~~The following table sets forth the ~~year~~costs incurred in oil and gas exploration and development activities during the years ended December 31, 2014, 2013, and 2012.

Type of Unit	Number of Units		Net income			Net income per unit
	2014			2013			2012
Managing general partner	8.9697		$	156,604		$	17,459.23
Oil and natural gas properties:
General partner	490.9827		146,353			$	298.08
Exploration	$	—		$	—		$	—
Limited partner	397.0172		118,343			$	298.08
Development	559,177			588,267			1,540,206
Total	~~896.9696~~$	559,177	$	~~421,300~~$	588,267		$	1,540,206

~~For~~Results ~~the~~of ~~year ended December 31, 2012~~Operations

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	208,709	$	23,268.23
General partner	490.9827	319,189		$	650.10
Limited partner	397.0172	258,102		$	650.10
Total	896.9696	$	786,000

The following table sets forth the results of operations from oil and gas producing activities for the years ended December 31, 2014, 2013 and 2012

For the year ended December 31, 2011

	2014			2013			2012

Oil and gas producing activities:
Oil sales	$	3,852,681		$	4,746,601		$	5,358,144
Natural gas sales	381,900			365,881			472,853
Production expenses	(2,861,131		)	(2,626,024		)	(2,821,054		)
Accretion of asset retirement obligation	(163,490		)	(155,345		)	(119,588		)
Depreciation, depletion and amortization	(1,194,107		)	(1,102,611		)	(1,222,493		)
Property impairment	(1,841,274		)	—			—
Results of operations from oil and gas producing activities	$	(1,825,421	)	$	1,228,502		$	1,667,862

Depletion rate per BOE	$	18.98		$	16.16		$	14.40

Type of Unit	Number of Units	Net income (loss)			Net income (loss) per unit
Managing general partner	8.9697	$	112,569		$	12,549.94
General partner	490.9827	(13,525		)	$	(27.55	)
Limited partner	397.0172	(10,937		)	$	(27.55	)
Total	896.9696	$	88,107

F-13

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

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

~~The~~Notes ~~following table presents the Partnership’s aggregate capitalized costs relating~~ to ~~oil~~Financial ~~and~~Statements ~~gas activities at the end~~(continued)

~~F-13~~BOE = Barrels of Oil Equivalent (6 MCF equals 1 BOE)

~~Table~~Crude ofOil ~~Contents~~and Natural Gas Reserves

~~Reef~~Net ~~Oil &~~Proved ~~Gas~~Reserve ~~Income and Development Fund III, L.P.~~Summary

~~Notes~~The toreserve ~~Financial~~information ~~Statements~~presented ~~(continued)~~below is based upon estimates of net proved oil and gas reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014, 2013 and 2012. All of the Partnership’s reserves are located in the United States.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs as of the ~~periods~~date ~~indicated:~~the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time. At December 31, 2014, all of the Partnership’s reserves are classified as proved developed reserves. At December 31, 2013, 99.83% of the Partnership’s proved reserves are classified as proved developed reserves, and 0.17% are classified as proved undeveloped reserves. At December 31, 2013, future development costs were estimated to be approximately $23,970 in connection with the Partnership’s proved developed non-producing and proved undeveloped reserves.

	December 31, 2013			December 31, 2012			December 31, 2011
Oil and natural gas properties:
Unproved properties	$	53,556,544		$	53,691,229		$	54,875,297
Proved properties	21,916,502			21,461,203			20,036,869
Capitalized asset retirement obligation	2,126,682			2,124,314			1,679,480
	77,599,728			77,276,746			76,591,646
Less:
Accumulated depreciation, depletion and amortization	(5,212,972		)	(4,116,026		)	(3,606,508		)
Property impairment	(58,612,453		)	(58,612,454		)	(58,612,454		)
	(63,825,425		)	(62,728,480		)	(62,218,962		)
Total	$	13,774,303		$	14,548,266		$	14,372,684

~~Costs~~The ~~Incurred~~following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012.

The following table sets forth the costs incurred in oil and gas exploration and development activities during the years ended December 31, 2013, 2012, and 2011.

	Oil (BBL) (1)		Gas (mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2011	679,860		1,172,750		875,318
Reserves sold	(5,117	)	(5,873	)	(6,096	)
Revisions of previous estimates	152,765		(57,161	)	143,238
Production	(61,718	)	(138,956	)	(84,878	)
Reserves at December 31, 2012	765,790		970,760		927,582

Reserves sold	—		(800	)	(133	)
New Discoveries	3,540		22,520		7,294
Revisions of previous estimates	(172,746	)	7,406		(171,511	)
Production	(52,584	)	(93,936	)	(68,240	)
Reserves at December 31, 2013	544,000		905,950		694,992

Reserves sold	(710	)	(16,090	)	(3,392	)
New Discoveries	1,700		7,700		2,983
Revisions of previous estimates	29,245		(147,761	)	4,618
Production	(47,555	)	(92,149	)	(62,913	)
Reserves at December 31, 2014	526,680		657,650		636,288

	2013		2012		2011
Oil and natural gas properties:
Exploration	$	—	$	—	$	—
Development	588,267		1,540,206		2,213,864
Total	$	588,267	$	1,540,206	$	2,213,864

F-14

~~Results~~Table of ~~Operations~~Contents

~~The~~Reef ~~following~~Oil & ~~table~~Gas ~~sets~~Income ~~forth the other results of operations from oil~~ and ~~gas~~Development ~~producing~~Fund ~~activities for the years ended December 31~~III, ~~2013, 2012 and 2011~~L.P.

	2013			2012			2011
Oil and gas producing activities:
Oil sales	$	4,746,601		$	5,358,144		$	5,452,219
Natural gas sales	365,881			472,853			596,713
Production expenses	(2,626,024		)	(2,821,054		)	(3,197,984		)
Accretion of asset retirement obligation	(155,345		)	(119,588		)	(78,030		)
Depreciation, depletion and amortization	(1,102,611		)	(1,222,493		)	(1,128,514		)
Property impairment	—			—			—
Results of operations from producing activities	$	1,228,502		$	1,667,862		$	1,644,404
Depletion rate per BOE	$	16.16		$	14.40		$	13.53

Notes to Financial Statements (continued)

~~BOE = Barrels of~~ (1) Oil ~~Equivalent~~includes (6both ~~MCF~~oil ~~equals~~and 1natural ~~BOE)~~gas liquids

~~F-14~~(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.

~~Table~~Standardized Measure of ~~Contents~~Discounted Future Net Cash Flows

~~Reef~~Certain ~~Oil &~~information ~~Gas~~concerning ~~Income~~the assumptions used in computing the valuation of proved reserves and ~~Development~~their ~~Fund~~inherent ~~III,~~limitations Lare discussed below.P The Partnership believes such information is essential for a proper understanding and assessment of the data presented.

~~Notes~~For tothe ~~Financial~~years ~~Statements~~ended ~~(continued)~~December 31, 2014, 2013, and 2012, calculations were made using average prices of $93.63, $96.90, and $94.68 per barrel of crude oil, respectively, and $4.22, $3.67, and $2.76 per MCF of natural gas, respectively. 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.

~~Crude~~These ~~Oil~~assumptions used to compute the standardized measure are those prescribed by the FASB and ~~Natural~~the ~~Gas~~SEC, ~~Reserves~~and do not necessarily reflect Reef’s expectations of the Partnership’s actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.

~~Net~~Future ~~Proved~~development ~~Reserve~~and ~~Summary~~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.

~~The~~A ~~reserve~~10% ~~information~~annual ~~presented~~discount ~~below~~rate is ~~based~~used ~~upon~~to ~~estimates~~reflect ~~of net proved oil and gas reserves that were prepared by~~ the ~~independent~~timing ~~petroleum engineering firm Forrest A. Garb & Associates, Inc. as~~ of ~~December 31, 2013, 2012 and 2011. All of~~ the ~~Partnership’s~~future ~~reserves~~net ~~are~~cash ~~located~~flows inrelating ~~the~~to ~~United~~proved ~~States~~reserves.

~~Proved~~The ~~oil~~standardized ~~and~~measure ~~gas reserves are those quantities~~ of ~~oil~~discounted ~~and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in~~ future ~~years~~net ~~from~~cash ~~known~~flows ~~reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs~~ as of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time. At December 31, ~~2013~~2014, ~~99.83% of the Partnership’s proved reserves are classified as proved developed reserves, and 0.17% are classified as proved undeveloped reserves. At December 31,~~ 2013, ~~future development costs were estimated to be approximately $23,970 in connection with the Partnership’s proved developed non-producing~~ and ~~proved undeveloped reserves. At December 31,~~ 2012 ~~and 2011, all of the Partnership’s reserves~~ were ~~classified~~ as ~~proved developed reserves.~~follows:

	December 31, 2014			December 31, 2013			December 31, 2012
Future cash inflows	$	50,801,390		$	58,719,780		$	77,852,350
Future production costs	(22,574,330		)	(23,427,730		)	(34,800,440		)
Future development costs	—			(23,970		)	—
Future net cash flows	28,227,060			35,268,080			43,051,910
Effect of discounting net cash flows at 10%	(17,110,163		)	(21,285,710		)	(26,330,380		)
Discounted future net cash flows	$	11,116,897		$	13,982,370		$	16,721,530

~~The~~Changes ~~following~~in ~~information~~the ~~table~~Standardized ~~sets~~Measure ~~forth~~of ~~changes~~Discounted inFuture ~~estimated~~Net ~~net~~Cash ~~proved~~flows ~~developed~~Relating ~~crude~~to ~~oil~~Proved ~~and~~Crude ~~natural~~Oil ~~gas~~and ~~reserves~~Natural ~~for~~Gas ~~the~~Reserves ~~years~~were ~~ended~~as ~~December 31,~~follows ~~2013,~~for ~~2012~~the ~~and~~years ~~2011.~~indicated:

	Oil (BBL) (1)		Gas (mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2010	838,200		1,217,840		1,041,174
Reserves sold	(115,154	)	(39,980	)	(121,817	)
Revisions of previous estimates	19,069		121,929		39,389
Production	(62,255	)	(127,039	)	(83,428	)
Reserves at December 31, 2011	679,860		1,172,750		875,318
Reserves sold	(5,117	)	(5,873	)	(6,096	)
Revisions of previous estimates	152,765		(57,161	)	143,238
Production	(61,718	)	(138,956	)	(84,878	)
Reserves at December 31, 2012	765,790		970,760		927,582
Reserves sold	—		(800	)	(133	)
New Discoveries	3,540		22,520		7,294
Revisions of previous estimates	(172,746	)	7,406		(171,511	)
Production	(52,584	)	(93,936	)	(68,240	)
Reserves at December 31, 2013	544,000		905,950		694,992

F-15

~~(1) Oil~~Table ~~includes~~of ~~both oil and natural gas liquids~~Contents

~~F-15~~Reef Oil & Gas Income and Development Fund III, L.P.

~~Table~~Notes ofto ~~Contents~~Financial Statements (continued)

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

	December 31, 2014			December 31, 2013			December 31, 2012
Standardized measure at beginning of period	$	13,982,370		$	16,721,530		$	16,035,470
New Discoveries, net of future production and development cost	97,740			139,290			—
Net change in sales price, net of production costs	(1,797,237		)	1,603,865			1,645,080
Revisions of quantity estimates	92,511			(3,155,972		)	2,318,973
Changes in production timing rates	(1,404,294		)	(665,373		)	(1,688,197		)
Accretion of discount	1,398,237			1,672,153			1,603,547
Sales net of production costs	(1,209,960		)	(2,331,113		)	(2,890,355		)
Sales of minerals in place	(42,470		)	(2,010		)	(302,988		)
Net increase (decrease)	(2,865,473		)	(2,739,160		)	686,060
Standardized measure at end of year	$	11,116,897		$	13,982,370		$	16,721,530

~~Notes to Financial Statements (continued)~~F-16

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

Standardized Measure of Discounted Future Net Cash Flows

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

For the years ended December 31, 2013, 2012, and 2011, calculations were made using average prices of $96.90, $94.68, and $95.84 per barrel of crude oil, respectively, and $3.67, $2.76, and $4.15 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.

These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect Reef’s expectations of the Partnership’s actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.

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, 2013, 2012 and 2011 were as follows:

	December 31, 2013			December 31, 2012			December 31, 2011
Future cash inflows	$	58,719,780		$	77,852,350		$	67,687,020
Future production costs	(23,427,730		)	(34,800,440		)	(31,201,620		)
Future development costs	(23,970		)	—			—
Future net cash flows	35,268,080			43,051,910			36,485,400
Effect of discounting net cash flows at 10%	(21,285,710		)	(26,330,380		)	(20,449,930		)
Discounted future net cash flows	$	13,982,370		$	16,721,530		$	16,035,470

Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Natural Gas Reserves were as follows for the years indicated:

	December 31, 2013		December 31, 2012		December 31, 2011
Standardized measure at beginning of period	$	16,721,530	$	16,035,470	$	14,318,440
New Discoveries, net of future production and development cost	139,290		—		—
Net change in sales price, net of production costs	1,603,865		1,645,080		4,185,204

F-16

Table of Contents

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

Notes to Financial Statements (continued)

Revisions of quantity estimates	(3,155,972		)	2,318,973			559,448
Changes in production timing rates	(665,373		)	(1,688,197		)	254,755
Accretion of discount	1,672,153			1,603,547			1,431,844
Sales net of production costs	(2,331,113		)	(2,890,355		)	(2,769,918		)
Sales of minerals in place	(2,010		)	(302,988		)	(1,944,303		)
Net increase (decrease)	(2,739,160		)	686,060			1,717,030
Standardized measure at end of year	$	13,982,370		$	16,721,530		$	16,035,470

F-17

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