UNITED STATES SECURITIES AND EXCHANGE COMMISSION

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For The Fiscal Year Ended December 31, ~~2014~~2015

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

For the Transition period from to

Commission File Number 000-53795

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

(Exact name of registrant as specified in its charter)

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

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

(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)

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 3130, ~~2015~~2016, the registrant had 490.~~9827~~2327 units of general partner interest outstanding, 89.~~9697~~2197 units of general partner interest and 01.~~6000~~0500 units of limited partner interest held by the managing general partner, and ~~396~~395.~~4172~~4672 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, ~~2014~~2015

TABLE OF CONTENTS

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

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 Accounting Fees and Services

PART IV

Item 15.	Exhibits and Financial Statement Schedules
	Signatures

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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, ~~2014~~2015 (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~~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 (2) 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, subject to certain market conditions, no earlier than 2010, but expected no later than 2015, in order to maximize return to the partners of the Partnership. The term of the Partnership commenced on the effective date and continues until December 31, 2016, unless terminated sooner. 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 November 27, 2007 and 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~~planned 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~~served ~~serves~~ as operator of the wells acquired in the Slaughter Dean acquisition prior to their sale during the second quarter of 2015. 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.

AsWhile one of the original objectives of the Partnership was the sale of properties no later than 2015 in order to maximize return to the investor partners, Reef decided to delay any attempt to sell the properties acquired in the Azalea and Lett acquisitions as of December 31, 2014 as a result of the ~~significant~~ decline in crude oil prices that began during the third quarter of 2014. The ~~and~~Partnership ~~has~~was ~~continued~~focused ~~into~~upon selling the ~~first~~properties ~~quarter~~acquired ofin ~~2015,~~ the ~~Partnership~~Slaughter ~~has~~Dean ~~delayed~~acquisition ~~any~~because ~~attempt~~they towere ~~sell~~operating ~~the~~at ~~properties~~a ~~acquired~~deficit indue ~~the~~to ~~Azalea~~high operating and ~~Lett~~workover ~~acquisitions~~costs. The Partnership ~~continues~~was tosuccessful ~~pursue~~in ~~possible~~selling ~~disposition of~~ the Slaughter Dean acquisition properties (during the ~~“Slaughter~~second ~~Dean~~quarter ~~Properties”)~~of 2015.

However, as the decline in commodity prices continued into the third quarter of 2015, the Partnership saw its results of operations, financial position, and cash flows being severely adversely affected. The Partnership is not engaged in

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commodity futures trading or hedging activities, and does not have significant cash reserves on hand, since cash flows are normally distributed on a regular basis to the investor partners. During the first two quarters of 2015 working capital was being drained because the Slaughter Dean acquisition properties were being operated at a deficit. During the third quarter of 2015, lease operating costs, production taxes, and general and administrative expenses of the remaining Azalea and Lett acquisition properties exceeded revenues. Without a recovery in commodity prices, Reef believes the Partnership must either borrow funds from Reef or sell properties to generate cash to cover the deficits. As Reef is unable to project when or if commodity prices will recover, a decision was made in October 2015 to begin marketing the remaining assets of the Partnership. Several property sales were consummated during the fourth quarter of 2015, and Reef expects to complete the divestiture of all of the Partnership’s oil and gas properties, wind up, and terminate the Partnership during 2016.

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, ~~2014~~2015, one marketer and one operator accounted for 3744.53% and 3618.02% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, ~~2013~~2014, ~~one~~the same 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~~the same marketer and ~~one~~ operator accounted for 3438.60% and 2632.86% of the Partnership’s crude oil and natural gas revenues, respectively. ~~Due~~Nevertheless, due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.

Insurance

The Partnership is a named insured under blowout, pollution, public liability and workmen’s compensation insurance policies obtained by RELP. Such insurance, however, may not be sufficient to cover all liabilities 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. Subject to the foregoing, Reef ~~has~~may, ~~obtained~~in ~~and~~its ~~maintained~~sole discretion, increase or decrease the policy limits and ~~will~~types ~~continue~~of insurance from time to ~~maintain~~time as it deems appropriate under the circumstances, which may vary materially. Prior to August 2015, Reef maintained 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 ofno less than $10,000,000. ~~Subject~~As toa result of the ~~foregoing,~~sale ~~Reef~~of ~~may,~~all inPartnership ~~its~~properties ~~sole~~operated ~~discretion,~~by ~~increase~~RELP oron ~~decrease~~behalf of the ~~policy~~Partnership ~~limits~~during ~~and~~the ~~types~~second quarter of ~~insurance~~2015, ~~from~~as ~~time~~well toas ~~time~~the ascessation itof ~~deems~~drilling ~~appropriate~~activities ~~under~~of the ~~circumstances~~Partnership, ~~which~~the ~~may~~Partnership ~~vary~~now ~~materially~~maintains public liability insurance of $2,000,000 and umbrella liability insurance of $25,000,000 effective August 1, 2015.

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~~The ~~basis and billed through an inter-company charge to the~~ Partnership, asreimburses ~~well~~RELP ~~as other Reef-sponsored partnerships, based upon the premiums charged by the insurance carrier~~ for ~~the~~its ~~specific~~share ~~wells~~of ~~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~~premium. The ~~inter-company~~following ~~balance~~types ~~between RELP~~ and ~~the~~amounts ~~Partnership is settled on at least a quarterly basis. However, in the event~~ of ~~a large~~ insurance ~~reimbursement~~are ~~being~~currently ~~payable to the Partnership, the inter-company balance would be settled earlier, within a reasonable time after receipt of the insurance proceeds.~~maintained:

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 vertically drilled land wells and $1015,000,000 for ~~wet~~horizontally drilled land wells; and

· Umbrella liability insurance (excess of the General liability, Employer’s liability and Automobile liability insurance) with a limit of ~~not less than~~ $5025,000,000.

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

Competition

There are 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;

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· 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.

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

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~~prohibitions~~of ~~were~~natural ~~imposed~~gas oncan ~~the~~currently ~~Partnership~~be ~~for~~made ~~violating~~at ~~such~~unregulated ~~regulations~~market prices, ~~the~~Congress ~~Partnership’s~~could ~~operations~~reenact ~~could~~price becontrols ~~adversely~~in ~~affected~~the future.

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. Local, ~~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~~state, ~~many~~and ~~nations~~national ~~have~~regulatory ~~agreed~~bodies toare ~~limit~~increasingly ~~emissions~~focused ofon “greenhouse ~~gases”~~gas (“GHG’s”) ~~pursuant~~emissions toas ~~the~~contributing ~~United~~to ~~Nations~~climate ~~Framework~~change. The ~~Convention~~United onStates ~~Climate~~Environmental ~~Change~~Protection ~~and~~Agency ~~the~~ (“~~Kyoto Protocol.~~EPA”) ~~Methane,~~has aissued ~~primary component of natural gas, and carbon dioxide,~~ a ~~byproduct~~ruling ofrequiring ~~the~~annual ~~burning~~reporting of ~~oil,~~GHG ~~gas~~emissions, and ~~refined~~it ~~petroleum~~is ~~products,~~possible ~~are~~that ~~considered~~ GHG’s ~~regulated~~emissions bymay ~~the~~be ~~Kyoto~~classified ~~Protocol.~~as ~~The~~pollutants ~~United~~regulated ~~States~~under isthe ~~currently~~federal ~~not~~Clean ~~participating~~Air ~~in the Kyoto Protocol~~Act.

~~While~~In ~~Congress~~December 2015, ~~has~~the ~~from~~United ~~time~~States towas ~~time~~a ~~considered~~participant ~~legislation~~in tothe ~~reduce~~21st Conference ~~emissions~~ of ~~GHG’s, there has not been significant activity in~~ the ~~form~~Parties of ~~adopted~~the ~~legislation~~United toNations ~~reduce~~Framework ~~GHG’s~~Convention aton ~~the~~Climate ~~federal~~Change ~~level~~held in ~~recent~~Paris, ~~years~~France. ~~However,~~The a“Paris ~~number~~Agreement” ofadopted ~~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~~conference ~~require~~calls ~~major sources of GHG emissions to acquire and surrender emission allowances in return~~ for ~~emitting~~nations ~~those GHG’s. While it is not possible at this time~~ to ~~predict~~undertake ~~how~~efforts ~~legislation~~with orrespect ~~new regulations that may be adopted~~ to ~~address~~global ~~GHG~~temperatures ~~emissions would impact the Partnership, any such future laws~~ and ~~regulations that require reporting of~~ GHG’s ~~or limit~~ emissions. ofIf ~~GHG’s~~this ~~from~~agreement ~~oil~~is ~~and~~ratified ~~gas~~by ~~operations~~the ~~could~~Congress ~~require expenditure~~ of ~~funds to reduce such emissions, or, by affecting~~ the ~~demand~~United ~~for refined petroleum products~~States, ~~could~~it ~~affect~~will ~~demand~~take ~~for~~effect ~~oil~~in ~~and~~the ~~gas~~year ~~produced from Partnership wells~~2020.

InWhile ~~January 2015,~~it ~~the~~is ~~Obama~~not ~~Administration~~possible ~~announced~~at ~~its~~this ~~intent~~time to ~~directly~~predict ~~regulate~~how ~~methane~~legislation ~~emissions~~or ~~from~~new ~~the~~regulations ~~oil~~or ~~and~~treaties ~~gas~~that ~~industry~~may asbe aadopted ~~part~~to ofaddress ~~its~~GHG ~~climate~~emissions ~~change~~would ~~strategy.~~impact ~~The~~the ~~EPA~~Partnership, isany ~~expected~~such tofuture ~~propose~~laws ~~in 2015~~ and ~~finalize during 2016 new~~ regulations that ~~will~~require ~~set~~reporting ~~methane~~of ~~emission~~GHG’s ~~standards~~or ~~aimed~~limit atemissions ~~having~~of ~~the~~GHG’s from oil and gas ~~sector~~operations ~~reduce~~could ~~its~~require ~~methane~~expenditure ~~emissions~~of ~~levels~~funds ~~by up~~ to 40reduce tosuch ~~50% from 2012~~ emissions, ~~levels~~or, by affecting the ~~year~~demand ~~2025.~~for ~~Such~~refined ~~regulations~~petroleum products, could ~~adversely~~ affect ~~the~~demand ~~cost~~for ~~of the Partnership’s~~ oil and gas ~~operations~~produced from Partnership wells.

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;7

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· statements regarding the plans and objectives of Reef for future operations, including, without limitation, the timing and sale of Partnership properties, 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~~Annual 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~~The ~~business~~Partnership ~~activities~~is ~~are~~a ~~subject~~“smaller toreporting ~~certain~~company” ~~risks~~as ~~and~~defined ~~hazards,~~by ~~including~~Rule 12b-2 ~~the risks discussed below. If any~~ of ~~these~~the ~~events~~Exchange ~~should occur~~Act, ~~it could materially~~ and ~~adversely~~as ~~affect our business~~such, ~~financial~~is ~~condition, cash flow, or results of operations. The risks below are~~ not ~~the~~required ~~only risks we face. We may experience additional risks and uncertainties not currently known~~ to usprovide ~~or, as a result of developments occurring in~~ the ~~future,~~information ~~conditions~~required ~~that~~under ~~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~~Item.

Continued 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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exploration and development activities are capitalized. The net capitalized costs of proved oil and gas properties are subject to a quarterly “ceiling test” and are limited to the lower of the unamortized cost or the cost ceiling, 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. Net capitalized costs in excess of the ceiling limit are charged as impairment expense against current earnings. Under full cost accounting rules, the ceiling test must be performed at the end of each quarter. Without a substantial increase in crude oil and natural gas prices, a significant portion of the Partnership’s reserves 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 significant impact on revenues and operating cash flows. The combination of lower prices and property impairment could have a material adverse effect on the Partnership’s results of operations in the period incurred and would reduce Partnership equity.

During the fourth quarter of 2014, the Partnership recorded impairment charges totaling $1,841,274, primarily resulting from a reduction in the oil 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 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 $3.0 million 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 also result in additional impairment charges during the remaining three quarters of 2015.

As a result of the decline in prices received for our crude oil and natural gas sales, the results of our operations for 2014 may not be indicative of our future results of operations in 2015 and beyond, as realized prices for our production may remain low or continue to decline.

Continued low crude oil, natural gas and NGL 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.

The sales price at which the Partnership’s 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 engaged in commodity futures trading or hedging activities, and 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 production fail to cover the operating and administrative costs of the Partnership, the managing general partner may need to temporarily advance funds to the Partnership. In order to repay such advances, the Partnership may be required to sell properties during a period of lower prices, and may not obtain a maximum return to investors upon such property sales.

Crude 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.

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.

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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 82.8% of the Partnership’s estimated proved reserves at December 31, 2014 were crude oil reserves, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.

The Partnership, while not prohibited from engaging in commodity trading or hedging activities in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at December 31, 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 flow available for capital expenditures, operating expenses, and distribution to partners, and results of operations.

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

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.

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

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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.

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.

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.

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, 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

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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.

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 distributions.

In connection with the Lett acquisition in June 2010, the Partnership borrowed $5,000,000 under a Credit Agreement with Texas Capital Bank, N.A. (“TCB”). The Partnership made its final payment under this Credit Agreement in December 2014 and terminated the Credit Agreement on December 31, 2014.

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 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 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.

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 Properties and the Thums Long Beach Unit are held in the name of the Partnership. Under the purchase agreement with RCWI, L.P. (“RCWI”), an affiliate of the Partnership, relating to the Azalea 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

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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

Property Acquisition, Development Activities, and Divestiture of Certain Properties

Slaughter Dean 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~~were located in the Slaughter Field in Cochran County, Texas. Reef implemented a waterflood development plan on a portion of the Dean “B” Unit (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. While the waterflood development activity temporarily reduced the rate of decline in oil production, the desired increase in oil production rates did not materialize.

The ~~drilling~~Partnership ofsold ~~new~~all ~~water~~of ~~injection wells and~~ the ~~conversion~~properties ofacquired ain ~~number~~the ofSlaughter ~~old~~Dean ~~already-producing~~acquisition ~~oil~~during ~~wells~~the tosecond ~~water~~quarter ~~injection~~of ~~wells~~2015. ~~was~~The ~~intended~~Slaughter toDean ~~increase~~acquisition ~~the~~properties ~~productivity~~were ofoperated ~~the~~by ~~project~~RELP ason abehalf ~~whole. The gradual filling~~ of the ~~productive~~Partnership, ~~formation via this enhancement of waterflooding was designed to loosen~~ and ~~force~~were ~~out additional oil, thereby increasing~~ the ~~ultimate~~only ~~recovery~~RELP ofoperated ~~crude~~properties ~~oil~~owned inby the ~~Dean “B” Unit~~Partnership.

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) subsequent to 2010, but no further developmental activities have been 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.

Azalea Acquisition

~~During~~In January 2010, the Partnership acquired from RCWI, L.P. (“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 properties (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.8

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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 was an interest in the Thums Long Beach Unit (“Thums Unit”), which is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. Thums Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell.

During the fourth quarter of 2015, the Partnership sold its working interest in the Thums Unit that it had acquired in the Azalea Properties acquisition, and during the third and fourth quarters made eight additional sales of various wells from the Azalea acquisition properties.

Lett Acquisition

~~During~~In June 2010, the Partnership acquired from RCWI, at cost, certain working interests (the “Lett Properties”) acquired by RCWI from Lett Oil & Gas, L.P. The Lett Properties consisted of additional working interests in the Thums ~~Long Beach~~ Unit. The acquired working interests are all minority non-operated interests. The Thums ~~Long Beach~~ Unit is operated by a third party not affiliated with the Partnership or Reef.

~~Sale~~During the fourth quarter of ~~Certain~~2015, the Partnership sold its working interest in the Thums Unit that it had acquired in the Lett Properties acquisition.

~~The~~Properties ~~Partnership~~Owned ~~sold~~at 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 offerDecember 31, 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 these 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 loan principal under its Credit Agreement with TCB during November 2013. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to this transaction.2015

~~During~~The ~~the~~sales ~~second~~during ~~quarter~~2015 of ~~2014,~~ the ~~Partnership~~Slaughter ~~sold~~Dean ~~its~~acquisition ~~interest~~properties, the working interests in ~~several~~the ~~oil~~Thums ~~and~~Unit ~~gas~~that ~~wells~~were acquired asin aconnection ~~part~~with of the Azalea ~~acquisition~~Acquisition ~~for~~and ~~approximately~~Lett ~~$135~~Acquisition,~~000.~~ ~~The~~and ~~estimated~~other ~~discounted~~properties ~~future~~acquired ~~cash flows included~~ in the ~~Partnership’s~~Azalea ~~2013~~Acquisition ~~reserve~~represented ~~report for these wells was less than $45,000~~87.3% ~~The operator~~ of the ~~properties notified the~~ Partnership’s ofoil ~~their~~reserves ~~intent~~and ~~to form a waterflood unit to be implemented in three phases~~25.1% ~~The cost~~ of the ~~initial~~Partnership’s ~~phase,~~natural ~~net~~gas toreserves ~~the~~based ~~working~~upon ~~interest~~reserve ~~owned~~quantities bystated ~~the~~in ~~Partnership, was approximately $351,500, and would have required~~ the Partnership’s ~~to pay these capital costs~~December 31, ~~plus~~2014 ~~costs~~reserve ~~associated~~report. At ~~with Phases 2 and 3~~December 31, ~~from~~2015 ~~current~~the ~~cash~~Partnership ~~flows~~owns ~~instead~~working ofinterests ~~distributing~~in ~~those~~more ~~cash~~than ~~flows~~600 towells ~~investors.~~acquired ~~The~~in ~~Partnership utilized~~ the ~~sales~~Azalea ~~proceeds~~Acquisition, aslocated ~~well~~in asTexas, ~~current~~New ~~operating~~Mexico, ~~cash~~Louisiana, ~~flow~~Oklahoma, toNorth ~~make~~Dakota, aMississippi, ~~$150~~Alabama,~~000~~ ~~prepayment~~Kansas, ~~of loan principal under its Credit Agreement with TCB during June 2014. In accordance with the full cost method of accounting~~Montana, ~~the~~Colorado ~~Partnership~~and ~~did not record any gain or loss related to this transaction~~Arkansas.

~~The~~Property 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.Sales

The Partnership sold the Slaughter Dean acquisition properties during the second quarter of 2015 to Red Sea 2012, Inc. for a purchase price of $700,000, less fees paid of $5,765, subject to certain revenue and cost adjustments retroactive to the effective sale date of December 1, 2014. In accordance with the full cost methodology, the Partnership recorded a gain on sale totaling $1,673,100 related to this sale. During the fourth quarter of 2015, the Partnership wrote off the account receivable totaling $181,610 it had recorded related to the certain revenue and cost adjustments retroactive to the effective date of sale of December 1, 2014 as a bad debt expense, as RELP has been unsuccessful in recovering these funds from the purchaser.

During the second quarter of 2015, the Partnership sold its working interest in a well drilled upon acreage acquired as a part of the Azalea acquisition for a purchase price of $84,332. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss associated with this sale.

During the fourth quarter of 2015, the Partnership and Reef Oil & Gas Income and Development Fund II, L.P., an affiliate of the Partnership, sold their interest in the Thums Unit to the operator, California Resources Long Beach Inc. for a purchase price totaling $1,000,000. Sales proceeds allocated to the interest owned by the Partnership were $940,371. In accordance with the full cost methodology, the Partnership recorded a loss on sale totaling $2,405,410 related to this sale.

During the third and fourth quarters of 2015, the Partnership consummated eight property sales involving properties acquired as a part of its Azalea acquisition in 2010. Collectively, the Partnership received sales proceeds totaling

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$47,483 for these eight property sales. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss associated with these eight sales transactions.

During the second quarter of 2014, the Partnership sold its interest in several oil and gas wells acquired as a part of the Azalea acquisition for approximately $135,000. The estimated discounted future cash flows included in the Partnership’s 2013 reserve report for these wells was less than $45,000. The operator of the properties notified the Partnership of their intent to form a waterflood unit to be implemented in three phases. The cost of the initial phase, net to the working interest owned by the Partnership, was approximately $351,500, and would have required the Partnership to pay these capital costs, plus costs associated with Phases 2 and 3, from current cash flows instead of distributing those cash flows to investors. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to this transaction.

The Partnership does not expect to purchase interests in any additional properties, nor does it expect to participate in the drilling of any new wells, should proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition be received.

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 senior reservoir engineer for RELP as of December 31, 2015, and by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014 and 2013. All of the Partnership’s reserves are located in the United States.

The estimated net proved crude oil and natural gas reserves at December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013 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)
	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
Net proved reserves as of December 31, 2015	50,012	365,260

The standardized measure of discounted future net cash flows as of December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013 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, 2013	$	13,982,370
Standardized measure of discounted future net cash flows as of December 31, 2014	$	11,116,900
Standardized measure of discounted future net cash flows as of December 31, 2015	$	760,460

During the years ended December 31, 2015, 2014, and 2013, the Partnership recognized property impairment costs of proved properties totaling $5,432,366, $1,841,274, and $0, respectively.

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, and adjustments to various Azalea Properties totaled approximately 96,000 Mcf. During 2015, the oil and gas reserves sold by the Partnership, as

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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

measured by the proved reserves shown in the 2014 reserve report, totaled 459,910 Bbl and 164,990 Mcf. The additional reductions in reserve volumes are primarily attributable to lower commodity prices during 2015.

During the year ended December 31, 2014 the Partnership recorded property impairment costs of proved properties totaling $1,841,274. During the years ended December 31, 2013, and 2012, the Partnership recorded no property impairment costs of proved properties.

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.

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

The Partnership used ~~an independent petroleum engineering firm, Forrest A~~Mr. Jerald ~~Garb & Associates~~Sluder, ~~Inc.,~~RELP’s ~~(“FGA”)~~Senior ofReservoir ~~Dallas,~~Engineer ~~Texas,~~ to prepare its December 31, ~~2014,~~2015 ~~2013, and 2012~~ estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2014, 2013 and 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.

The Partnership used an independent petroleum engineering firm, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2014 and 2013 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2014 and 2013. 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.

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~~engineer. 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~~were prepared by Jerald Sluder, RELP’s Senior Reservoir Engineer, and by FGA. Our technical staff and members of our accounting department ~~meet~~met regularly with Mr. Sluder and 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, iswas 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-one 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.

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Title to Properties

Title to the Partnership’s interest in the leases for ~~the Slaughter Dean Properties, the Thums Long Beach Unit, and~~ certain Azalea Properties is held in the name of the Partnership. Under the purchase agreement with RCWI 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.

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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

Units and Holders

As of ~~December 31~~March 30, ~~2014~~2016, the Partnership had one managing general partner, ~~816~~818 non-Reef general partners, and ~~666~~671 non-Reef limited partners. Reef holds a total of 89.~~9697~~2197 general partner units and 01.~~6000~~0500 limited partner units, and the non-Reef partners hold 490.~~9827~~2327 general partner units and ~~396~~395.~~4172~~4672 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.

Investor 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~~initially 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~~As such, effective October 1, 2013, Reef ~~also~~received ~~receives 0~~11.06% and investor partners received 88.94% of ~~the~~total cash distributions. ~~paid~~During to2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from investor partners. As such, ~~Reef~~effective ~~currently~~September 1, 2015 Reef receives 11.0613% and investor partners receive 88.9487% of total cash distributions. Total cash distributions paid during ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013 were $~~170~~17,~~871~~654, $~~682~~170,~~835~~871, and $~~655~~682,~~321~~835, 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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ITEM 6. SELECTED FINANCIAL DATA

The ~~following~~Partnership ~~table~~is ~~sets~~a ~~forth~~“smaller ~~selected~~reporting ~~financial~~company” ~~and~~as ~~operating~~defined ~~data.~~by ~~The~~Rule 12b-2 ~~selected~~of ~~financial~~the ~~data~~Exchange ~~presented~~Act, ~~below~~and ~~has~~as ~~been~~such, ~~derived~~is ~~from~~not ~~the~~required ~~audited~~to ~~financial~~provide ~~statements~~the ofinformation ~~the~~required ~~Partnership~~under this Item.

	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

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

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

~~For a discussion of risk factors that could impact the Partnership’s financial results, please see Item 1A of this Annual Report.~~12

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Going Concern

Management is currently pursuing the sale of all Partnership assets with the intent to wind up and terminate the Partnership during 2016. As a result, the Partnership is not expected to continue as a going concern. The financial statements included with this Annual Report do not include any adjustments that might result from the outcome of this uncertainty.

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 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.

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 oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful, exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 thousand cubic feet (“Mcf”) of natural gas to 1 barrel (“Bbl”) of crude oil. 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. During 2015, the Partnership recorded gain or loss in connection with two of its property sales. During the second quarter of 2015, the Partnership recognized a gain of $1,673,100 in connection with the sale of the Slaughter Dean acquisition properties in Cochran County, Texas. During the fourth quarter of 2015, the Partnership recognized a loss of $2,405,410 in connection with the sale of its interest in the Thums Unit located in the Wilmington Field underneath the Long Beach Harbor in southern California.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the 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 ~~year~~years ended December 31, 2015, 2014, and 2013, the Partnership recognized ~~$1,841,274~~property of impairment ~~expense~~costs of proved properties. ~~During~~totaling ~~the years ended December 31~~$5,432,366, ~~2013~~$1,841,274, and ~~2012~~$0, ~~the Partnership recognized no property impairment expense of proved properties~~respectively.

Unproved property consists of undrilled infill and offset acreage acquired in connection with the ~~purchase of the~~ Azalea ~~Properties~~acquisition in 2010. Investments in unproved property are not subject to depletion until they are either impaired or developed. Unproved property is assessed for impairment quarterly as of the balance sheet date. In determining whether an unproved property is impaired, the Partnership considers numerous factors including, but 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, geological and geophysical evaluation and current market conditions. To the extent that the assessment indicates a property is impaired, the impairment amount is re-classed from unproved property to the proved property full cost pool and subjected to depletion and the quarterly full cost ceiling test. After considering the holding period of the Azalea unproved properties as well 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 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 and 2012, the Partnership recognized no impairment of unproved property.

~~Estimates of Proved Oil and Gas Reserves~~13

The estimate of the Partnership’s proved reserves at December 31, 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.

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~~knowledge~~unproved ofproperty ~~these~~is ~~variables~~impaired, ~~evolves.~~the ~~Therefore,~~Partnership ~~these~~considers ~~estimates~~numerous ~~are~~factors ~~inherently~~including, ~~imprecise~~but not limited to, ~~and~~the ~~are~~following ~~subject~~items: intent to ~~considerable~~drill; ~~upward~~remaining orprimary ~~downward~~lease ~~adjustments.~~term; ~~Actual~~drilling ~~production~~results and activity in the immediate area of the property; the holding period of the property, ~~revenues~~geological and ~~expenditures~~geophysical ~~with~~evaluation ~~respect~~and tocurrent ~~reserves~~market ~~will~~conditions. ~~likely~~To ~~vary~~the ~~from~~extent ~~estimates~~that the assessment indicates a property is impaired, the impairment amount is re-classed from unproved property to the proved property full cost pool and ~~such~~subjected ~~variances~~to ~~could~~depletion beand ~~material~~the quarterly full cost ceiling test. After Inconsidering ~~addition,~~the ~~reserve~~holding ~~estimates~~period ~~for~~of the Azalea acquisition unproved properties ~~which~~as ~~have~~well ~~not~~as ~~yet~~current ~~been~~market ~~drilled~~conditions at December 31, or2014, ~~properties~~the ~~with~~Partnership aimpaired ~~limited~~all ~~production~~of ~~history~~its ~~may~~remaining beunproved ~~less~~property ~~reliable~~totaling ~~than~~$361,865 ~~estimates~~during ~~for~~the ~~properties~~fourth ~~with~~quarter ~~longer~~of ~~production~~2014. ~~histories~~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 year ended December 31, 2013, the Partnership recognized no impairment of unproved property.

Estimates of Proved Oil and Gas Reserves

The estimates of the Partnership’s proved reserves at December 31, 2015, 2014, and 2013 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-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 the senior reservoir engineer for RELP at December 31, 2015, and by FGA, an independent petroleum engineering firm, at December 31, 2014 and 2013.

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.

The following table summarizes the Partnership’s asset retirement obligation for the ~~periods~~years ended December 31, ~~2014~~2015 and ~~2013~~2014.

	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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	2015			2014
Beginning asset retirement obligation	$	2,528,422		$	2,463,175
Additions related to new properties	—			2,014
Retirement related to sale and disposition of proved properties	(1,988,403		)	(4,692		)
Retirement related to property abandonment and restoration	(4,170		)	(95,565		)
Accretion expense	56,096			163,490
Ending asset retirement obligation	$	591,945		$	2,528,422

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~~its purchasers each month. Any significant over or under balanced gas positions are disclosed in the financial statements. As of December 31, ~~2014~~2015, ~~2013~~2014 and ~~2012~~2013, the Partnership had no material gas imbalance positions.

Recent Accounting Developments — Revenue Recognition

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~~2017. 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.

Outlook

The oil and gas industry began experiencing decreases in and sustained depression of commodity prices during the third quarter of 2014, and these decreases continued throughout 2015 and into the first quarter of 2016. The severely depressed commodity prices are believed to be driven by a global supply/demand imbalance for crude oil and an oversupply of natural gas in the United States. Commodity prices are the most significant factor impacting the revenues, profitability, operating cash flows, and working capital of the Partnership. Reef is unable to predict what changes may occur in commodity prices, when such changes may occur, and for what period of time such changes may be effective. Reef believes that both crude oil and natural gas prices will remain volatile for the foreseeable future.

The depressed level of commodity prices over the past five quarters has had a significant adverse effect upon the financial position, cash flows, and results of operations of the Partnership. The profitability of properties owned by the Partnership has deteriorated, and the Partnership has recorded significant proved property impairment expense totaling $1,841,274 during the fourth quarter of 2014 and $5,432,366 during 2015 as oil and gas reserves have been rendered uneconomic to produce in the current pricing environment.

During the first half of 2015, the Partnership’s Slaughter Dean acquisition properties operated at a deficit prior to being sold, and during the third quarter oil and gas revenues from the Partnership’s remaining oil and gas properties, while exceeding direct lease operating costs and production taxes, were unable to cover direct lease operating costs, production taxes, and general and administrative costs.

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As a result of this continued depressed commodity price environment, Reef made a decision in October 2015 to begin marketing the remaining oil and gas properties owned by the Partnership, with a goal to complete the divestiture of all properties, wind up and terminate the Partnership during 2016.

Overview

Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership formed in 2007. The primary stated objectives of the Partnership ~~are~~were to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties, subject to certain market conditions, no earlier than 2010, but expected 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 the three groups of properties purchased by the Partnership (see ITEM 2 — Properties), the Partnership ~~plans~~has toproduced ~~produce~~ existing proved reserves and ~~develop~~worked ~~any~~to develop proved undeveloped reserves, but ~~will~~has not ~~engage~~engaged in exploratory drilling for unproved reserves, ~~should~~on leasehold acreage purchased by the Partnership be deemed to contain unproved drilling locations. Drilling locations with unproved reserves, if any, have been farmed out or sold to third parties or other partnerships formed by Reef. Prior to the fourth quarter of 2015, the Partnership evaluated, 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 agreed to participate or declined to participate in such additional drilling based upon its evaluations of such proposals. When the Partnership decided to participate in such developmental drilling, funds to drill were taken from current net cash flows that otherwise would have been available for distributions to investors.

20In October 2015, Reef made a decision to market the remaining assets of the Partnership as a result of continuing depressed commodity prices. The Partnership does not expect to purchase interests in any additional properties, nor does it expect to participate in the drilling of any new wells, should proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition be received.

The Partnership expended all of the capital it raised on the Slaughter Dean, Azalea, and Lett acquisitions described in Item 2 — Properties, and upon developmental drilling opportunities on infill and offset acreage acquired in connection with the Azalea acquisition. Upon exhausting the capital raised by the Partnership, additional development drilling opportunities were funded using current net cash flows that otherwise would have been available for distribution to investors.

During 2015, the Partnership sold its interest in approximately 87.3% of its total oil reserves and 25.1% of its total gas reserves, as measured by the December 31, 2014 reserve report. The Thums Unit and the Slaughter Dean acquisition properties represented 65.2% and 21.7% of total December 31, 2014 oil reserves, respectively, and 2.3% and 12.6% of total December 31, 2014 gas reserves, respectively. As a result of these sales, Partnership oil and gas production subsequent to December 31, 2015 is expected to significantly decline.

The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. While oil and gas sales revenues began declining during the third quarter of 2014, the full impact of the decline in prices was not felt until the last quarter of 2014 and beyond. The significant declines in prices for oil and gas have had a material effect on the Partnership’s financial condition, results of operations, cash flows, and quantities of reserves that are economically recoverable. The decline in commodity prices led to a decrease in proved reserves considered to be economically recoverable, resulting in impairment expense of proved properties totaling $1,841,274 during the fourth quarter of 2014 and $5,432,366 during 2015. The Partnership expects to recognize additional impairment of proved properties during the first quarter of 2016, since the quarterly reserves are calculated using the preceding 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices held constant and discounted at 10%, and it is expected that this average will decline from the average used to prepare the December 31, 2015 reserve estimates. 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.

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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, ~~2014~~2015, the Partnership had expended $5781,~~318~~369,~~891~~543 on ~~acquisition~~property ~~and development of the Slaughter Dean Properties, $16,532,120 on the~~ acquisition and development ~~of the Azalea Properties, and $7,201,297 on the acquisition and development of the Lett Properties~~costs. Expenditures in excess of available capital ~~have~~were ~~been~~ financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

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Credit Agreement

On June 30, 2010, the Partnership and 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 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 5%, payable monthly. The obligations 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

As of December 31, ~~2014~~2015, the Partnership had expended $81,~~052~~369,~~308~~543 on property acquisition and development costs. OfExpenditures ~~this~~in ~~amount,~~excess ~~$57,318,891~~of ~~has~~available ~~been~~capital ~~expended~~were onfinanced ~~the~~through ~~Slaughter~~debt ~~Dean~~or ~~Properties,~~property ~~$16~~sales,~~532,120~~ ~~has~~or have been ~~expended~~recovered onfrom ~~the~~cash ~~Azalea~~flows ~~Properties,~~by ~~and~~reducing ~~$7,201,297~~Partnership ~~has been expended on the Lett Properties~~distributions. Expenditures in excess of available Partnership capital, which totaled $76,242,425, have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.

AtThe ~~December~~Partnership had working capital of $1,640,865 at December 31, ~~2010~~2015, ~~the~~primarily ~~Partnership~~as ~~fully~~a ~~impaired~~result ~~its~~of ~~unproved~~property ~~properties~~sales ~~associated~~made ~~with~~during ~~the~~2015. ~~Slaughter~~The ~~Dean~~Partnership ~~waterflood~~distributed ~~project~~approximately ~~totaling~~ $53500,~~166~~000 of property sales proceeds to investors during January 2016,~~873.~~ ~~This~~but ~~amount~~has ~~was~~maintained ~~re-classed~~the ~~from~~remaining ~~unproved~~working ~~property~~capital to ~~the~~cover ~~proved~~any ~~property~~deficits ~~full~~prior ~~cost~~to ~~pool,~~its ~~where~~divestiture itof ~~was~~all ~~subject~~remaining properties during 2016. Subsequent to ~~depletion~~expending the initial available Partnership capital contributions on property acquisitions and development, the ~~full~~Partnership ~~cost~~working ~~ceiling~~capital ~~test~~consists ~~for~~primarily ~~the~~of ~~year~~cash ~~ended~~flows ~~December~~from 31productive properties, ~~2010~~which have been utilized to pay cash distributions to investors. Sources Asof afuture ~~result~~funding consist of ~~the~~cash ~~ceiling~~on ~~test~~hand, ~~calculation~~cash flow from operations, if any, and cash received from the sale of the Partnership’s ~~recorded~~remaining ~~impairment~~properties. The ~~expense~~Partnership ~~totaling~~has entered into three separate sales transactions subsequent to December 31, 2015 which have generated approximately $57100,~~944,024~~000 in ~~2010,~~sales ~~primarily~~proceeds ~~resulting~~to ~~from~~the ~~this~~Partnership. ~~transfer~~The ofPartnership ~~the~~may ~~Slaughter~~not ~~Dean~~be ~~waterflood~~able ~~project~~to ~~costs~~sell ~~into~~properties at the ~~proved~~values ~~property~~desired ~~full~~in ~~cost~~order ~~pool~~to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.

Unproved property on the Partnership 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. Subsequent to 2010, 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, the Partnership has transferred amounts from unproved property to proved property as wells have been drilled by the various 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, 2014.17

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The table below summarizes Partnership activity related to unproved properties during the year ended December 31, 2014:

	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	$	—		$	—

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

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

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.

Results of Operations

Year Ended December 31, 2015 compared to Year Ended December 31, 2014

The Partnership had a net loss of $7,296,413 for the year ended December 31, 2015, compared to a net loss of $2,493,870 for the year ended December 31, 2014. The increased loss is primarily the result of an increase in impairment of proved properties during the year ended December 31, 2015 as a result of continuing decreases in commodity prices. In addition, the Partnership incurred a net loss of $732,310 from property sales and saw its net revenues less lease operating expenses decrease from $1,625,594 in 2014 to $254,897 in 2015.

During the year ended December 31, 2015, the Partnership recognized impairment expense of $5,432,366. The impairment was the result of falling commodity prices throughout 2015, which decreased estimated future cash flows from Partnership properties and rendered some properties uneconomic to produce. During 2014, the Partnership recognized impairment expense of $1,841,274, all of which was incurred in the fourth quarter.

Partnership revenues totaled $4,234,581 and lease operating expenses totaled $2,608,987 for the year ended December 31, 2014, for a margin of $1,625,594. During the year ended 2015, Partnership revenues totaled $1,557,050 and lease operating expenses totaled $1,302,153, for a margin of $254,897. The 63.2% decrease in oil and gas revenues during 2015 was primarily attributable to the decrease in oil and gas sales prices during 2015. The average sales price for crude oil decreased by 45.1%, to an average price of $43.83 per Bbl for the year ended December 31, 2015 compared to an average price of $81.01 for the year ended December 31, 2014. Oil sales volumes also decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014 by 15,518 Bbl, or approximately 32.6%. Oil sales volumes from the Partnership’s Slaughter Dean acquisition properties, which were sold during the second quarter of 2015, accounted for 12,430 Bbl of the 15,518 Bbl drop in sales volumes.

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 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.

Lease operating expenses decreased from $2,608,987 for the year ended December 31, 2014 to $1,302,153 for the year ended December 31, 2015, a decrease of $1,306,834, or 50.1%. Lease operating expenses from the Partnership’s Slaughter Dean acquisition properties, which were sold during the second quarter of 2015, declined from $1,628,357 during 2014 to $455,869 during the first six months of 2015, a decrease of $1,172,488, or 89.7% of the total decrease in lease operating expenses. The Slaughter Dean acquisition properties incurred high workover expenditures of $390,078 in 2014. During the first six months of 2015, the Partnership deferred workover costs by shutting in wells with mechanical failures, thus delaying workover costs. Lease operating expenses on the Thums Unit also decreased from $471,329 in 2014 to $390,591 in 2015. During the first six months of 2014 the Partnership experienced higher lease operating costs on the Thums Unit in connection with certain projects being performed by the lease operator.

General and administrative costs during the year ended December 31, 2015 decreased to $506,622 as compared to $635,685 incurred during the year ended December 31, 2014. 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 $431,793 during the year ended December 31, 2014 to $279,085 during the year ended December 31, 2015. This decrease was primarily incurred during the second half of 2015, as the sale of the Slaughter Dean acquisition properties reduced this Partnership’s activity levels compared to the activity levels of other Reef partnerships.

The Partnership incurred a loss on sale of oil and gas properties totaling $732,310 during 2015, compared to $0 during 2014. Under the full cost method of accounting, no gain or loss on disposition of oil and gas properties is recorded unless such disposition significantly alters the relationship between capitalized costs and proved reserves.

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Because of the significant reduction in commodity prices during 2015, the property write-offs related to the Partnership’s two major sales were considered to materially affect this relationship, and as such, the partnership recorded gain/loss. During 2014 no gain/loss was required to be recorded in connection with the Partnership’s sale of properties.

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.

23Lease 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 acquisition properties. Total workover costs included in lease operating expenses, most of which are incurred on the Partnership’s Slaughter Dean acquisition 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.

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~~its~~fees, ~~production~~audit ~~from~~fees, ~~successful~~engineering ~~oil~~fees for reserve reports and ~~gas~~other ~~wells~~analysis, onand afees ~~month-to-month~~for ~~basis~~preparation atof ~~current~~SEC ~~spot~~filings ~~market~~and ~~prices~~XBRL services. ~~Accordingly~~During 2013, the Partnership isincurred atone ~~risk~~time ~~for~~fees ~~the~~associated ~~volatility~~with inXBRL ~~commodity~~services ~~prices~~to ~~inherent~~set inup the ~~oil~~initial ~~and~~detailed ~~gas~~XBRL ~~industry,~~tagging of its financial statements and ~~the~~footnotes. ~~level~~These ofdecreases ~~commodity~~were ~~prices~~offset ~~has~~by a ~~significant~~slight ~~impact~~increase onin ~~the~~geology ~~Partnership’s~~and ~~results~~geophysical ofcharges ~~operations.~~incurred ~~Prices~~related ~~for~~to ~~crude~~resolving ~~oil~~ownership ~~have~~issues ~~continued~~and tovarious ~~decline~~other ~~throughout~~issues ~~the~~related ~~first~~to ~~quarter~~the ofindividual ~~2015~~properties.

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 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 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.

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 Properties, and lower overhead on the Azalea Properties. Overall, workover expenses declined from $338,114 incurred during

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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.

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, ~~2014~~2015, ~~2013~~2014 and ~~2012~~2013, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.

Contractual Obligations Table

	Payment due by period
Contractual obligations	Total	Less than 1 Year	1-3 Years	3-5 years	More than 5 Years
Consulting agreement *	—	—	—	—	—

* 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 ~~Properties~~acquisition 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~~acquisition properties. During the years ended December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013, William R. Dixon received $194,~~379~~216, $1719,~~147~~379, and $2317,~~819~~147, respectively, related to this overriding royalty interest. AtThe ~~December 31,~~Partnership ~~2014,~~sold its interest in the ~~estimated~~Slaughter ~~net~~Dean ~~proved~~acquisition ~~reserves~~properties ofduring the ~~Slaughter~~second ~~Dean~~quarter ~~Properties~~of 2015, asand ~~determined~~the byliability ~~the~~for ~~independent~~payment ~~engineering~~of ~~firm~~this ~~used~~overriding byroyalty interest was transferred to the ~~Partnership’s,~~purchaser ~~had~~of athe ~~remaining~~Slaughter ~~economic~~Dean ~~life~~acquisition properties upon consummation of 27the ~~years~~sale.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

~~Interest~~The ~~Rate~~Partnership ~~Risk~~is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.

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. During 2014, the Partnership completed repayment of all of its outstanding debt under its Credit Agreement with TCB, and terminated the Credit

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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

The Partnership’s oil and gas sales revenues, 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 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. 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, 2014, a 10% change in the price received for crude oil would have had an approximate $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 $38,000 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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financial and accounting officer of the Partnership’s managing general partner, Reef Oil & Gas Partners, L.P., evaluated the effectiveness of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report. Based on that evaluation, the principal executive officer and principal financial and accounting officer of our managing general partner have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial and accounting officer of our managing general partner, as appropriate to allow timely decisions regarding financial disclosure.

Management Report on Internal Control Over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (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, ~~2014~~2015.

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, ~~2014~~2015 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. (referred to herein as Reef). Reef Exploration, L.P. (referred to herein as RELP), an affiliate of Reef, 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.

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

The Manager, officers and key personnel of the managing general partner (Reef) and RELP, 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	58	Manager of Reef Oil & Gas Partners GP, LLC; Chief Executive Officer of RELP
Daniel C. Sibley	63	Chief Financial Officer and General Counsel of RELP
David M. Tierney	62	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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employed by several exploration and development firms in planning exploration and marketing feasibility of privately sponsored drilling programs.

Name	Age	Positions and Offices Held
Michael J. Mauceli	59	Manager of Reef Oil & Gas Partners GP, LLC; Chief Executive Officer of RELP
Daniel C. Sibley	64	Chief Financial Officer and General Counsel 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 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
Affiliates		and 2013, the Partnership paid administrative fees totaling $431,793 and $489,183, respectively.
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 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 and its Affiliates	Monthly administrative fee	For the years ended December 31, 2015 and 2014, the Partnership paid administrative fees totaling $279,085 and $431,793, 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 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 served as operator of the Slaughter Dean acquisition properties, such drilling compensation was payable to RELP based on the level of developmental operations conducted by 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, 2015 and 2014, the Partnership paid drilling compensation fees totaling $13,564 and $21,201, respectively.
Managing General Partner and its Affiliates	~~Payment~~Direct ~~for equipment, supplies, marketing, and other services~~costs	~~Competitive~~Reimbursement ~~prices~~at cost. For the years ended December 31, ~~2014~~2015 and ~~2013~~2014, the Partnership paid nodirect ~~payments~~costs ~~for~~totaling ~~equipment~~$85,594 ~~supplies, marketing~~ and ~~other~~$97,934, ~~services~~respectively.

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Recipient	Form of Compensation	Amount
Managing General Partner and its Affiliates	~~Acquisition~~Payment for equipment, supplies, marketing, and ~~Development~~other ~~Costs~~services	~~Reimbursement~~Competitive ~~at cost~~prices. For the years ended December 31, ~~2014~~2015 and ~~2013~~2014, the Partnership ~~did~~paid ~~not~~no ~~reimburse~~payments ~~the~~for ~~Managing~~equipment, ~~General~~supplies, ~~Partner~~marketing and ~~its~~other ~~affiliates for any acquisition and development costs~~services.
Managing General Partner and its Affiliates	Acquisition and Development Costs	Reimbursement at cost. For the years ended December 31, 2015 and 2014, the Partnership did not reimburse the Managing General Partner 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 Partnership units to brokers for their own accounts, who were permitted to buy Partnership units at a price net of the commission that they would normally earn on sales of 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. 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, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. ~~Thus~~As such, effective October 1, 2013, Reef ~~also~~received ~~receives 0~~11.06% and investor partners received 88.94% of ~~the~~total cash distributions. ~~paid~~During to2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from the Partnership’s investor partners. As such, ~~Reef~~effective ~~currently~~September 1, 2015, Reef receives 11.0613% and investor partners receive 88.9487% of total cash distributions. During the years ended December 31, ~~2014~~2015, ~~2013~~2014 and ~~2012~~2013, Reef received $181,~~796~~965, $7518,~~112~~899, and $7275,~~085~~254, respectively, in cash distributions related to its ~~11%~~Partnership interest~~, and received $103 and $142 during the years ended December 31, 2014 and 2013 related to its 0~~.~~06% limited partner interest.~~

~~In addition, when~~ RELP, ~~serves~~is asentitled ~~operator~~to ofreceive ~~a Partnership well, then RELP, receives~~ drilling compensation in an amount equal to 15% of the total well costs paid ~~from~~by the ~~funds~~Partnership offor ~~the~~wells ~~Partnership~~operated by RELP. RELP ~~currently~~served ~~serves~~ as the operator of the Slaughter Dean ~~Properties.~~acquisition Asproperties auntil ~~result,~~their ~~such~~sale ~~drilling~~during ~~compensation~~the ~~payable~~second toquarter of 2015. RELP ~~may~~also ~~amount~~is toalso ~~approximately~~entitled 9%to ofreceive ~~total~~drilling ~~partnership~~compensation ~~subscriptions,~~in ~~depending~~an onamount ~~the~~equal ~~level~~to 5% of ~~developmental~~the ~~operations~~total ~~conducted~~well costs paid by ~~RELP~~the Partnership for non-operated wells. Total well costs include all drilling and equipment costs, including intangible ~~well~~development 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, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013, RELP received $2113,~~201~~564, $2521,~~602~~201, and $3925,~~856~~602, 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~~2015, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $9682,~~804~~922 and $12,~~130~~672, respectively. During the year ended December 31, ~~2013~~2014, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $~~102~~96,~~762~~804 and $1,~~551~~130, respectively. During the year ended December 31, ~~2012~~2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $~~171~~102,~~800~~762 and $1,~~302~~551, respectively.

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RELP 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, 2015, 2014, and 2013, the administrative overhead charged by RELP to the Partnership totaled $~~431~~279,~~793~~085, $~~489~~431,~~183~~793, and $~~567~~489,~~424~~183, respectively. 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.

RELP processes joint interest billings and revenues on behalf of the Partnership. At December 31, ~~2014~~2015 and ~~2013~~2014, RELP owed the Partnership $~~183~~135,~~078~~851 and $~~509~~183,~~271~~078, 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, ~~2014~~2015 concerning the managing general partner and 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. As of December 31, 2015 there were a total of 896.9696 Partnership units outstanding, including 499.9524 units of general partner interest outstanding and 397.0172 units of limited partner interest outstanding.

Title of Interest	Person or Group	Number of Units Beneficially Owned	Percent of Total Partnership Units Outstanding		Percentage of Total Partnership Interests Beneficially Owned
General Partner	Reef Oil & Gas Partners, L.P. (1)	89.~~969696~~2197	1.00028	%	1.00025	%
Limited Partner	Reef Oil & Gas Partners, L.P. (1)	01.~~600000~~0500	0.~~067~~117	%	0.06104	%
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~~As ~~October~~of December 131, ~~2013~~2015, Reef has also purchased 01.6005 units of limited partner interest from aninvestor partners, representing 0.117% of outstanding investor partner units, and 0.25 units of general partner interest, representing 0.~~067~~028% of outstanding investor partner units. Michael J. Mauceli has control of Reef’s 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.

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

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

31ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

~~Table~~In each of ~~Contents~~the last two fiscal years, the Partnership incurred professional audit and tax fees from its principal accountant BDO USA, LLP, as disclosed in the table below:

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

	2015		2014
Audit Fees	$	76,547	$	70,803
Audit Related Fees	—		—
Tax Fees	—		—
All Other Fees	—		—

InAs ~~each~~indicated ofin ~~the~~Item ~~last~~10 ~~two fiscal years~~above, the Partnership ~~incurred~~does ~~professional~~not have any directors or an audit ~~and~~committee. ~~tax~~As ~~fees~~such, ~~from~~no ~~its~~pre-approval ~~principal~~policies ~~accountant~~or ~~BDO~~procedures ~~USA,~~for ~~LLP,~~engagement asof ~~disclosed~~principal inaccountants ~~the~~have ~~table~~been ~~below:~~established.

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

PART IV

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

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	1. Financial Statements

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


	2. Financial Statement Schedules	None

	3. Exhibits

A list of the exhibits filed or furnished with this Annual Report (or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Exhibit Index in this Annual Report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the exhibits are filed herewith.

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SIGNATURES

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

Date: March 31, 2015
Date: March 30, 2016
	REEF OIL & GAS INCOME
	AND DEVELOPMENT FUND III, L.P.
	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner
	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner
	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)

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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, ~~this~~the ~~report~~registrant has ~~been~~duly ~~signed~~caused ~~below~~this byreport ~~the~~to ~~following~~be ~~persons~~signed on its behalf ofby the ~~registrant~~undersigned, ~~and~~thereunto induly ~~the capacities and on the dates indicated~~authorized.

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	Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners,	March 30, 2016
/s/ Michael J. Mauceli		March 31, 2015
Michael J. Mauceli	L.P., the Managing General Partner of the Partnership (Principal Executive Officer)
Michael J. Mauceli
/s/ Daniel C. Sibley	Chief Financial Officer and General Counsel of	March 30, 2016
/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	Reef Exploration, L.P. (Principal Financial and Accounting Officer)
Daniel C. Sibley

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EXHIBIT INDEX

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

Exhibit
Number		Description

3.1		Certificate of Formation of Reef Oil & Gas Income and Development Fund III, L.P. dated November 27, 2007(incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

4.1		Second Amendment and Restated Agreement of Limited Partnership of Reef Oil & Gas Income and Development Fund III, L.P., dated June 4, 2008 (incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.1		Operating Agreement dated January 7, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.2		Operating Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 10.2 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.3		Purchase and Sale Agreement dated January 7, 2008 by and among Sierra-Dean Production Company L.P., Reef Oil & Gas Income and Development Fund III, L.P., Reef Exploration L.P. and SPI Operations LLC, as amended on January 8, 2008 (incorporated by reference to Exhibit 10.3 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.4		Assignment, dated May 1, 2008, by and between Davric Corporation and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.4 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.5		Crude Oil Contract, dated March 13, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc., as amended by Amendment No. 1, dated June 24, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc. (incorporated by reference to Exhibit 10.5 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.6		Consulting Agreement, dated September 1, 2006, by between Reef Exploration, L.P. and William R. Dixon (incorporated by reference to Exhibit 10.6 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.7		Casinghead Gas Sales Contract, dated January 1, 1978, by and between Amoco Production Company and Amoco Production Company (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).

10.8		Purchase and Sale Agreement, dated January 19, 2010, by and between Azalea Properties Ltd. And RCWI, LP. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).

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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

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

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

10.22		Purchase and Sale Agreement dated May 27, 2015, by and between Reef Oil & Gas Income and Development Fund III, L.P. and Red Sea 2012, Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K, dated June 3, 2015).

10.23		Offer to Purchase Oil, Gas and Mineral Interest Wilmington Oil Field, Long Beach Unit, dated December 2, 2015 and Acceptance of Offer to Purchase, signed December 16, 2015, by and between Reef Oil & Gas Income and Development Fund II, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and California Resources Long Beach Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K, dated December 22, 2015).

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.INS	*	XBRL Instance Document
101.SCH	*	XBRL Taxonomy Extension Schema Document.
101.SCH	*	XBRL Taxonomy Extension Schema Document
101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.CAL	*	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	*	XBRL Taxonomy Extension Labels Linkbase Document.
101.LAB	*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document.
101.PRE	*	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	*	XBRL Taxonomy Extension Definitions Linkbase Document.
101.DEF	*	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith

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

Financial Statements

Years Ended December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013

Contents

Report of Independent Registered Public Accounting Firm	F-1

Audited Financial Statements

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

Table of Contents

Report of Independent Registered Public Accounting Firm

The Partners

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

Richardson, TX

We have audited the accompanying balance sheets of Reef Oil & Gas Income and Development Fund III, L.P. (“the Partnership”) as of December 31, ~~2014~~2015 and ~~2013~~2014 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, ~~2014~~2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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.

InThe ~~our~~accompanying ~~opinion,~~financial statements have been prepared assuming that the ~~financial~~Partnership ~~statements~~will ~~referred~~continue toas ~~above~~a ~~present~~going ~~fairly,~~concern. As discussed in ~~all~~Note ~~material~~1 ~~respects,~~to the financial ~~position~~statements, ofthe ~~Reef~~Partnership, ~~Oil &~~when ~~Gas~~formed, ~~Income~~was ~~and~~projected ~~Development~~to ~~Fund~~have ~~III,~~a ~~L.P.~~limited atlife through December 31 2016, ~~2014~~unless ~~and~~terminated ~~2013,~~sooner. ~~and~~Management is currently pursuing the ~~results~~sale of ~~its~~all ~~operations~~Partnership ~~and~~assets ~~its~~with ~~cash~~the ~~flows~~intent ~~for~~to ~~each~~wind ofup and terminate the ~~three~~Partnership ~~years~~during 2016, as specified in the ~~period~~Partnership’s ~~ended~~governing ~~December 31,~~documents ~~2014,~~at inits ~~conformity~~inception. In accordance with generally accepted accounting principles ~~generally~~for ~~accepted~~a inlimited life entity, the ~~United~~Partnership ~~States~~has not applied the liquidation basis of ~~America~~accounting to these financial statements.

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, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/S/ BDO USA, LLP

Dallas, Texas

March 3130, ~~2015~~2016

F-1

Table of Contents

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

Balance Sheets

December 31,	~~2014~~2015		~~2013~~2014
Assets
Current assets:
Cash and cash equivalents	$	~~368~~1,~~620~~515,010	$	~~651~~368,~~936~~620
Accounts receivable from affiliates	~~183~~135,~~078~~851		~~509~~183,~~271~~078
Deferred financing fees, net	—		10,056
Total current assets	1,650,861		551,698
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
Proved properties, net of accumulated depletion of $14,737,574 and $66,651,471	760,460		11,116,897
Unproved properties, excluded from amortization	—		389,672
Net oil and gas properties	760,460		11,116,897
Net oil and gas properties	11,116,897		13,774,303
Total assets	$	2,411,321	$	11,668,595
Deferred financing fees, net	—		4,184
Total assets	$	11,668,595	$	14,949,750
Liabilities and partnership equity
Current liabilities:
Accounts payable	$	109,~~479~~996	$	810,~~387~~479
Accrued liabilities	~~6,247~~—		—6,247
Current portion of long term note payable	—		360,000
Total current liabilities	9,996		16,726
Total current liabilities	16,726		368,387
Long term liabilities
Note payable	—		330,000
Asset retirement obligation	591,945		2,528,422
Asset retirement obligation	2,528,422		2,463,175
Total long term liabilities	591,945		2,528,422
Total long term liabilities	2,528,422		2,793,175
Commitments and contingencies (Note 6)
Partnership equity
General partners	51,~~230~~302,~~521~~555		65,~~709~~230,~~582~~521
Limited partners	3468,~~645,712~~462		43,~~841~~645,~~706~~712
Managing general partner	~~247~~38,~~214~~363		~~236~~247,~~900~~214
Total partnership equity	91,~~123~~809,~~447~~380		119,~~788~~123,~~188~~447
Total liabilities and partnership equity	$	112,~~668~~411,~~595~~321	$	1411,~~949~~668,~~750~~595

See accompanying notes to financial statements.

F-2

Table of Contents

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

Statements of Operations

	For the Years Ended December 31,
	2014			2013			2012
	2015			2014			2013
Oil, gas and NGL sales	$	41,~~234~~557,~~581~~050		$	54,~~112~~234,~~482~~581		$	5,~~830~~112,~~997~~482
Costs and expenses:
Lease operating expenses	21,~~608~~302,~~987~~153			2,~~327~~608,~~209~~987			2,~~506~~327,~~677~~209
Production taxes	~~252~~118,~~144~~071			~~298~~252,~~815~~144			~~314~~298,~~377~~815
Depreciation, depletion and amortization	1524,~~194,107~~630			1,~~102~~194,~~611~~107			1,~~222~~102,~~493~~611
Accretion of asset retirement obligation	~~163~~56,~~490~~096			~~155~~163,~~345~~490			~~119~~155,~~588~~345
Property impairment	15,~~841~~432,~~274~~366			—1,841,274			—
General and administrative	635,685			736,429			776,523
Loss on sale of oil & gas properties	732,310			—			—
Total costs and expenses	6,695,687			4,620,409			4,939,658
General and administrative	506,622			635,685			736,429
Income (loss) from operations	(2,461,106		)	492,073			891,339
Bad debt expense	181,610			—			—
Total costs and expenses	8,853,858			6,695,687			4,620,409
Income (loss) from operations	(7,296,808		)	(2,461,106		)	492,073
Other income (expense)
Miscellaneous income	~~746~~395			~~463~~746			69463
Interest expense	~~(17,954~~—		)	(5617,~~334~~954		)	(8056,~~632~~334		)
Amortization of deferred financing fees	~~(15,556~~—		)	(1415,~~902~~556		)	(2414,~~776~~902		)
Total other income (expense)	~~(32,764~~395		)	(7032,~~773~~764		)	(~~105~~70,~~339~~773		)
Net income (loss)	$	(27,~~493~~296,~~870~~413	)	$	~~421~~(2,~~300~~493,870	)	$	~~786~~421,~~000~~300
Net income (loss) per general partner unit	$	(27,~~841.31~~985	)	$	~~298.08~~(2,841	)	$	~~650.10~~298
Net income (loss) per limited partner unit	$	(27,~~841.31~~985	)	$	~~298.08~~(2,841	)	$	~~650.10~~298
Net income per managing partner unit	$	3,256.80		$	17,459.23		$	23,268.23
Net income (loss) per managing partner unit	$	(22,103	)	$	3,257		$	17,459

See accompanying notes to financial statements.

F-3

Table of Contents

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

Statements of Partnership Equity

	General Partners					Limited Partners				Managing General Partner				Total
	Units		Amount			Units	Amount			Units	Amount			Units	Amount
Balance at December 31, 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
Balance at December 31, 2014	490.9827		$	5,230,521		397.0172	$	3,645,712		8.9697	$	247,214		896.9696	$	9,123,447
Purchase (sale) of units	(0.25	)	—			—	—			0.25	—			—	—
Partner distributions			(8,683		)	—	(7,025		)		(1,946		)	—	(17,654		)
Net loss	—		(3,919,283		)	—	(3,170,225		)	—	(206,905		)	—	(7,296,413		)
Balance at December 31, 2015	490.7327		$	1,302,555		397.0172	$	468,462		9.2197	$	38,363		896.9696	$	1,809,380
Distribution amount per partnership unit			$	17.69			$	17.69			$	211.07

See accompanying notes to financial statements

F-4

Table of Contents

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

Statements of Cash ~~Flows~~Flow

	For the Years Ended December 31,
	2014			2013			2012
	2015			2014			2013
Cash flows from operating activities
Net income (loss)	$	(27,~~493~~296,~~870~~413	)	$	~~421~~(2,~~300~~493,870	)	$	~~786~~421,~~000~~300
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: Plugging and abandonment costs paid from ARO	(4,170		)	(53,894		)	(55,893		)
Adjustments for non-cash transactions:
Depletion, depreciation and amortization	1524,~~194,107~~630			1,~~102~~194,~~611~~107			1,~~222~~102,~~493~~611
Accretion of asset retirement obligation	~~163~~56,~~490~~096			~~155~~163,~~345~~490			~~119~~155,~~588~~345
Amortization of deferred financing fees	~~15,556~~—			1415,~~902~~556			2414,~~776~~902
Plugging and abandonment costs paid from ARO	(53,894		)	(55,893		)	(30,835		)
Loss on sale of oil and gas properties	732,310			—			—
Property impairment	15,~~841~~432,~~274~~366			—1,841,274			—
Bad debt expense	181,610			—			—
Changes in operating assets and liabilities
Accounts receivable	—			~~1,986~~—			~~(186~~1,986		)
Accounts receivable from affiliates	~~326~~47,~~193~~227			~~170~~326,~~151~~193			~~(35~~170,~~301~~151		)
Accounts payable	65—			~~2,792~~65			12,~~998~~792
Accrued liabilities	(6,247		)	—6,247			—
Net cash provided by operating activities	999,168			1,813,194			2,088,533
Net cash provided by (used in) operating activities	(332,591		)	999,168			1,813,194
Cash flows from investing activities:
Proceeds from sale of oil & gas properties	~~134~~1,~~839~~814,352			~~253~~134,~~760~~839			93253,~~451~~760
Property development	(~~557~~317,~~163~~234		)	(~~585~~557,~~584~~163		)	(1585,~~094,017~~584		)
Net cash used in investing activities	(422,324		)	(331,824		)	(1,000,566		)
Net cash provided by (used in) investing activities	1,497,118			(422,324		)	(331,824		)
Cash flows from financing activities:
Payment of note payable	~~(690,000~~—		)	(~~625~~690,000		)	(~~450~~625,000		)
Payment of debt issuance costs	~~(1,316~~—		)	(161,~~843~~316		)	(~~812~~16,843		)
Distributions to partners	(~~168~~18,~~844~~137		)	(~~682~~168,~~835~~844		)	(~~655~~682,~~321~~835		)
Net cash used in financing activities	(~~860~~18,~~160~~137		)	(1860,~~324,678~~160		)	(1,~~106~~324,~~133~~678		)
Net increase (decrease) in cash and cash equivalents	~~(283~~1,~~316~~146,390		)	~~156~~(283,~~692~~316		)	~~(18~~156,~~166~~692		)
Cash and cash equivalents, beginning of year	~~651~~368,~~936~~620			~~495~~651,~~244~~936			~~513~~495,~~410~~244
Cash and cash equivalents, end of year	$	~~368~~1,~~620~~515,010		$	~~651~~368,~~936~~620		$	~~495~~651,~~244~~936
Supplemental cash flow disclosure
Cash paid for interest expense on note payable	$	~~17,954~~—		$	5617,~~103~~954		$	8056,~~592~~103
Supplemental disclosure of non-cash investing transactions
Asset retirement obligation reduction resulting from sale and disposition of proved properties	$	(41,~~692~~988,403	)	$	(54,~~859~~692	)	$	(15,~~605~~859	)
Property sales included in accounts receivable from affiliates	$	—		$	—		$	45,522
Property sale account receivable charged to bad debt expense	$	181,610		$	—		$	—
Additions to property and asset retirement obligation	$	~~2,014~~—		$	2,~~683~~014		$	~~446~~2,~~189~~683
Asset retirement obligation in excess of liability	$	~~(41,671~~—	)	$	—(41,671	)	$	—
Supplemental disclosure of non-cash financing transactions
Partner distributions included in accounts payable	$	~~2,027~~483		$	—2,027		$	—

See accompanying notes to financial statements.

F-5

Table of Contents

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

Notes to Financial Statements

1. Organization and Basis of Presentation

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

Reef, as managing general partner, received a 10% general partner interest in the Partnership as compensation for forming the Partnership. This 10% 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 purchase price paid by Reef for the units it purchased was net of the 15% management fee paid by investors. The units purchased by investor partners represented an 89% interest in the Partnership.

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

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 ~~previously~~initially 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~~As such, effective October 1, 2013 Reef ~~also~~received ~~receives 0~~11.06% and investor partners received 88.94% of ~~the~~total cash distributions. ~~paid~~During to2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from investor partners. As such, effective ~~October~~ September 1, ~~2013~~2015 Reef receives 11.0613% and investor partners receive 88.9487% of total cash distributions.

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.

2.Going ~~Summary of Significant Accounting Policies~~Concern

~~Use~~The ofaccompanying ~~Estimates~~financial statements have been prepared assuming that the Partnership will continue as a going concern.

~~The~~During ~~preparation~~2015, ofthe ~~financial~~Partnership ~~statements~~sold inits ~~conformity~~interest ~~with accounting principles generally accepted~~ in the ~~United~~Slaughter ~~States~~Dean ofacquisition ~~America~~properties, ~~requires~~which ~~management~~were tooperating ~~make~~at ~~estimates~~a ~~and~~deficit ~~judgments~~as ~~that~~a ~~affect~~result ~~the reported amounts~~ of ~~assets~~the ~~and~~decline ~~liabilities~~in ~~and~~commodity ~~disclosure~~prices ofthat ~~contingent~~began ~~assets~~during ~~and liabilities at~~ the ~~date~~third ofquarter ~~the financial statements and the reported amounts~~ of ~~revenues~~2014. ~~and~~As ~~expenses~~Reef ~~during~~is ~~the~~unable ~~reporting~~to ~~period.~~project ~~The~~when ~~Partnership~~or ~~bases~~if ~~its~~commodity ~~estimates~~prices onwill ~~historical~~recover, ~~experience~~in ~~and~~October 2015 ~~various~~Reef ~~other~~made ~~assumptions~~a ~~that~~decision ~~are believed~~ to bebegin ~~reasonable~~marketing ~~under~~ the ~~circumstances.~~remainder ~~Actual~~of ~~results~~the ~~could~~Partnership’s ~~differ~~oil ~~from these estimates~~ and ~~assumptions~~gas ~~under different conditions~~properties. ~~The~~Several ~~more~~property ~~significant~~sales ~~areas~~were ~~requiring~~consummated during the ~~use~~fourth quarter of ~~management’s~~2015, ~~estimates~~ and ~~judgments~~Reef ~~relate~~is tocurrently pursuing the ~~estimation~~divestiture of ~~proved~~all ~~crude~~of the Partnership’s oil and ~~natural~~ gas ~~reserves,~~properties with the ~~use~~intent ofto ~~these~~wind ~~crude~~up ~~oil~~ and ~~natural~~terminate ~~gas~~the ~~reserves~~Partnership induring ~~calculating~~2016. ~~depletion~~Therefore, ~~depreciation,~~the ~~and~~Partnership ~~amortization,~~is ~~the~~not ~~use~~expected ofto ~~the~~continue ~~estimates~~as ofa ~~future~~going ~~net~~concern. ~~revenues~~The infinancial ~~computing~~statements ~~ceiling~~do ~~test~~not ~~limitations,~~include ~~and~~any ~~estimates~~adjustments ofthat ~~future~~might ~~abandonment~~result ~~obligations~~from ~~used~~the inoutcome ~~recording~~of ~~asset~~this ~~retirement obligations~~uncertainty.

Cash and Cash Equivalents

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Notes to Financial Statements (continued)

~~investments invested with a major national bank, which at times may exceed federally insured limits~~2. ~~The~~Summary ~~Partnership has not experienced any losses in such accounts, and does not expect any loss from this exposure. The carrying value~~ of ~~the~~Significant ~~Partnership’s~~Accounting ~~cash equivalents approximates fair value.~~Policies

Use of Estimates

Cash and Cash Equivalents

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

Risks and Uncertainties

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

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

Oil and Gas Properties

The Partnership follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful, as well as unsuccessful, exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 thousand cubic feet (“Mcf”) of natural gas to 1 barrel (“Bbl”) of crude oil. 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. During 2015, the Partnership recorded gain or loss in connection with two of its property sales. During the second quarter of 2015, the Partnership recognized a gain of $1,673,100 in connection with the sale of the Slaughter Dean acquisition properties in Cochran County, Texas (the “Slaughter Dean Properties”). During the fourth quarter of 2015, the Partnership recognized a loss of $2,405,410 in connection with the sale of its interest in the Thums Long Beach Unit (“Thums Unit”) located in the Wilmington Field underneath the Long Beach Harbor in southern California.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the 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 year ended December 31, 2014, the Partnership recognized $1,841,274 of impairment expense of proved properties. During the years ended December 31, 2013, and 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 in 2010. Investments in unproved property are not subject to depletion until they are either impaired or developed. Unproved property is assessed for impairment quarterly as of the balance sheet date. In determining whether an unproved property is impaired, the Partnership considers numerous factors including, but 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, geological and geophysical evaluation and current market conditions. To the extent that the assessment indicates a property is impaired, the impairment amount is re-classed from unproved property to the proved property full cost pool and subjected to depletion and the quarterly full cost ceiling test. After considering the holding period of the Azalea unproved properties as well 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 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 and 2012, the Partnership recognized no property impairment of unproved property.

Estimates of Proved Oil and Gas Reserves

The 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-weighted arithmetic average of the first-day-of-the-month

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Notes to Financial Statements (continued)

~~commodity~~price ~~prices~~for ~~over~~crude ~~the~~oil ~~preceding~~and ~~12-month~~natural ~~period~~gas held constant and ~~year~~discounted ~~end~~at ~~costs.~~10%, ~~Future~~plus ~~prices~~the ~~and~~lower ~~costs~~of ~~may~~cost beor ~~materially~~estimated ~~higher~~fair orvalue ~~lower~~of ~~than~~unproved ~~these~~properties, ~~prices~~if ~~and~~any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which ~~would~~the ~~impact~~capitalized costs exceed the ~~estimate~~ceiling, and is shown as a reduction of ~~reserves~~oil and ~~future~~gas ~~cash~~properties ~~flows.~~and ~~The~~as property impairment expense on the Partnership’s ~~proved~~statements ~~reserve~~of ~~information~~operations. ~~included~~During inthe ~~this~~years ~~report~~ended ~~was~~December 31, ~~based~~2015, ~~upon~~2014, ~~evaluations~~and ~~prepared~~2013, bythe ~~independent~~Partnership ~~petroleum~~recognized ~~engineers~~property impairment costs of proved properties totaling $5,432,366, $1,841,274, and $0, respectively.

Estimates of Proved Oil and Gas Reserves

The estimates of the Partnership’s proved reserves at December 31, 2015, 2014, and 2013 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-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 the senior reservoir engineer for Reef Exploration, L.P. (“RELP”), an affiliate of the Partnership and Reef, at December 31, 2015, and by an independent petroleum engineering firm at December 31, 2014 and 2013.

Restoration, Removal, and Environmental Liabilities

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

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

The Partnership has recognized an estimated liability for future 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 following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2014 and 2013.

	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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Notes to Financial Statements (continued)

The following table summarizes the Partnership’s asset retirement obligation for the years ended December 31, 2015 and 2014.

	2015			2014
Asset retirement obligation as of January 1	$	2,528,422		$	2,463,175
Additions related to new properties	—			2,014
Retirement related to sale and disposition of proved properties	(1,988,403		)	(4,692		)
Retirement related to property abandonment and restoration	(4,170		)	(95,565		)
Accretion expense	56,096			163,490
Asset retirement obligation as of December 31	$	591,945		$	2,528,422

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 its purchasers each month. The Partnership had no material gas imbalances at December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013.

Income Taxes

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

As of December 31, ~~2014~~2015, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $1916.67 million, primarily due to the difference between property impairment costs deducted for financial reporting purposes and intangible drilling costs deducted for income tax purposes.

Accounting for Uncertainty in Income Taxes

Accounting Standards Codification (“ASC”) section 740 provides guidance on accounting for uncertainty in income taxes. ASC 740 is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.

Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.

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

Based on the Partnership’s assessment, there are no material uncertain tax positions as of December 31, ~~2014~~2015 and ~~2013~~2014. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable from affiliates, accounts payable and accrued liabilities approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at December 31, 2013, 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 Income

Comprehensive income is defined as a change in equity of a business enterprise 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 period presented. Therefore, net income as presented in the

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

Notes to Financial Statements (continued)

~~statements~~The estimated fair value of ~~operations~~cash ~~equals~~and ~~comprehensive~~cash ~~income~~equivalents, accounts receivable from affiliates, accounts payable and accrued liabilities approximates their carrying value due to their short-term nature.

Recent Accounting Developments — Revenue Recognition

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

3. Long-Term Debt

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 a 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 5%, payable monthly. The obligations 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 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.

4. Transactions with Affiliates

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 ~~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~~cash ~~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~~net ~~ended December 31, 2014, 2013 and 2012, Reef received $18,796, $75,112, and $72,085, respectively, in~~ cash ~~distributions~~flow 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.from

Reef Exploration, L.P. (“RELP”), an affiliate of 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

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

Notes to Financial Statements (continued)

~~Partnership~~crude ~~for~~oil ~~non-operated~~and ~~wells.~~natural ~~Total~~gas ~~well~~sales ~~costs~~revenues, ~~include~~less ~~all~~operating, ~~drilling~~general and ~~equipment costs~~administrative, ~~including~~and ~~intangible~~other ~~development~~ costs~~, surface~~ ~~facilities,~~were ~~and~~distributed ~~costs~~11% ~~of pipelines necessary~~ to ~~connect~~Reef ~~the~~and ~~well~~89% to ~~the~~investor ~~nearest~~partners. ~~delivery~~Effective ~~point. In~~October 1, ~~addition~~2013, ~~total~~Reef ~~well~~purchased ~~costs~~0.60 ~~also~~units ~~include~~of ~~the~~limited ~~costs~~partner ofinterest ~~all~~from ~~developmental~~one ~~activities~~of onthe aPartnership’s ~~well,~~investor ~~such~~partners. asAs ~~reworking~~such, ~~working~~effective ~~over~~October 1, ~~deepening,~~2013 ~~sidetracking,~~Reef ~~fracturing~~received a11.06% ~~producing~~and ~~well,~~investor ~~installing~~partners ~~pipeline~~received ~~for~~88.94% aof ~~well~~total orcash ~~any~~distributions. ~~other~~During ~~activity~~2015, ~~incident~~Reef topurchased ~~the~~0.45 ~~operations~~units of alimited ~~well,~~partner ~~excluding~~interest ~~ordinary~~and ~~well operating costs after completion~~0. ~~Total~~25 ~~well~~units ~~costs~~of dogeneral ~~not~~partner ~~include~~interest ~~costs~~from ~~relating~~investor ~~to lease acquisitions~~partners. ~~During~~ ~~the~~As ~~years~~such, ~~ended~~effective ~~December~~September 311, ~~2014,~~2015 ~~2013~~Reef ~~and~~receives ~~2012,~~11.13% ~~RELP received $21,201, $25,602,~~ and ~~$39,856,~~investor ~~respectively,~~partners inreceive ~~drilling compensation~~88.87% ~~Drilling~~of ~~compensation~~total ~~payments~~cash ~~are included in oil and gas properties in the financial statements~~distributions.

~~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~~years ended December 31, ~~2014~~2015, ~~Reef~~2014 and ~~its~~2013, ~~affiliates~~Reef received ~~total~~$1,965, ~~reimbursements~~$18,899, ~~for~~and ~~direct~~$75,254, ~~costs~~respectively, ~~and~~in ~~other~~cash ~~documented~~distributions ~~out-of-pocket~~related ~~expenses~~to ofits ~~$96,804~~Partnership ~~and~~interest. ~~$1,130,~~From ~~respectively.~~funds ~~During~~generated ~~the~~by ~~year~~its ~~ended~~carried ~~December 31,~~interest ~~2013~~and management fee, Reef ~~and~~pays ~~its~~to ~~affiliates~~specific ~~received~~FINRA-licensed ~~total~~broker-dealers ~~reimbursements~~on ~~for~~a ~~direct~~quarterly ~~costs~~basis ~~and~~a ~~other~~fee ~~documented~~in ~~out-of-pocket~~an ~~expenses~~amount ofequal ~~$102,762~~to ~~and~~the ~~$1,551,~~maximum ~~respectively.~~of ~~During~~ the ~~year~~economic ~~ended~~equivalent ~~December 31,~~of ~~2012,~~a ~~Reef~~3% ~~and~~carried ~~its~~interest ~~affiliates~~in ~~received~~the ~~total~~Partnership ~~reimbursements~~as additional compensation for ~~direct~~the ~~costs~~sale ~~and~~of ~~other~~units. ~~documented~~This ~~out-of-pocket~~fee ~~expenses~~is ofrecorded ~~$171,800~~as ~~and~~a ~~$1,302,~~commission ~~respectively~~expense by Reef.

RELP ~~allocates~~is ~~its~~entitled ~~general~~to ~~and~~receive ~~administrative~~drilling ~~expenses~~compensation asin ~~overhead~~an amount equal to ~~all~~15% of the ~~partnerships~~total towell ~~which~~costs itpaid ~~provides~~by ~~services,~~the ~~and~~Partnership ~~this~~for ~~allocation~~wells isoperated aby ~~significant~~RELP. RELP ~~portion~~served as the operator of the Partnership’s ~~general~~Slaughter ~~and~~Dean ~~administrative~~acquisition ~~expenses.~~properties ~~The~~until ~~allocation~~their sale during the second quarter of 2015. RELP’s ~~overhead~~is also entitled to ~~the~~receive ~~partnerships~~drilling compensation in an amount equal to ~~which~~5% itof ~~provides~~the ~~services~~total iswell ~~based~~costs ~~upon~~paid ~~several~~by ~~factors~~the Partnership for non-operated wells. Total well costs include all drilling and equipment costs, including ~~the~~intangible ~~level~~development costs, tangible costs of drilling ~~activity,~~and ~~revenues~~completing the well, costs of storage and ~~capital~~other surface facilities, and ~~operating~~the ~~expenditures~~costs of ~~each~~gathering ~~partnership~~pipelines ~~compared~~necessary to connect the ~~total~~well ~~levels~~to ofthe ~~all~~nearest ~~partnerships. During~~appropriate ~~the~~sales ~~years~~point ~~ended~~or ~~December 31,~~delivery ~~2014,~~point. In ~~2013~~addition, ~~and~~total ~~2012,~~well ~~the~~costs ~~administrative~~also ~~overhead~~include ~~charged~~the bycosts ~~RELP~~of toall ~~the~~developmental ~~Partnership~~activities ~~totaled~~on ~~$431~~a well,~~793,~~ ~~$489~~such as reworking,~~183,~~ ~~and~~working ~~$567~~over,~~424~~ deepening, ~~respectively.~~sidetracking, ~~The~~fracturing ~~administrative~~a ~~overhead~~producing ~~charged~~well, byinstalling ~~RELP~~pipeline isfor ~~included~~a inwell ~~general~~or ~~and~~any ~~administrative~~other ~~expense~~activity inincident to the ~~accompanying~~operations ~~statements~~ of ~~operations.~~a ~~RELP’s~~well, ~~general~~excluding ~~and~~ordinary ~~administrative~~well operating costs ~~include~~after ~~all~~completion. Total ~~customary~~well ~~and~~costs ~~routine~~do ~~expenses,~~not ~~accounting,~~include ~~office~~costs ~~rent,~~relating ~~telephone,~~to ~~secretarial,~~lease ~~salaries~~acquisitions ~~and~~for ~~other~~purposes ~~incidental~~of ~~expenses~~calculating ~~incurred~~drilling bycompensation. During ~~RELP~~the oryears ~~its~~ended ~~affiliates~~December 31, ~~that~~2015, ~~are~~2014 ~~necessary~~and to2013, ~~the~~RELP ~~conduct~~received of$13,564, ~~the~~$21,201, ~~Partnership’s~~and ~~business~~$25,602, ~~whether~~respectively, ~~generated~~in bydrilling ~~RELP,~~compensation. ~~its~~Drilling ~~affiliates~~compensation orpayments byare ~~third~~included ~~parties,~~in ~~but~~oil ~~excluding~~and ~~direct~~gas ~~costs~~properties ~~and~~in ~~operating~~the ~~costs~~financial statements.

~~RELP~~Additionally, ~~processes~~Reef ~~joint~~and ~~interest~~its ~~billings~~affiliates are reimbursed for direct costs and ~~revenues~~all documented out-of-pocket expenses incurred on behalf of the Partnership. AtDuring the year ended December 31, ~~2014~~2015, Reef and ~~2013,~~its ~~RELP~~affiliates ~~owed~~received ~~the~~total ~~Partnership~~reimbursements for direct costs and other documented out-of-pocket expenses of $~~183~~82,~~078~~922 and $~~509~~2,~~271~~672, respectively. During the year ended December 31, ~~for~~2014, ~~net~~Reef ~~revenues~~and ~~processed~~its inaffiliates ~~excess~~received oftotal ~~net~~reimbursements ~~joint~~for ~~interest~~direct costs and ~~technical~~other ~~and~~documented ~~administrative~~out-of-pocket ~~service~~expenses ~~charges~~of $96,804 and $1,130, respectively. ~~The~~ ~~cash~~During ~~associated~~the ~~with~~year ~~net~~ended ~~revenues~~December 31, ~~processed~~2013, byReef ~~RELP~~and isits ~~normally~~affiliates received bytotal ~~RELP~~reimbursements ~~from~~for ~~oil~~direct costs and ~~gas~~other ~~purchasers~~documented 30out-60of-pocket ~~days~~expenses ~~after~~of ~~the~~$102,762 ~~end~~and of$1,551, ~~the month~~respectively.

InRELP ~~September 2012,~~allocates ~~the~~its ~~Partnership~~general ~~sold~~and ~~leasehold~~administrative ~~interests~~expenses ~~related~~as overhead to aall ~~non-operated~~of ~~three~~the ~~well~~partnerships ~~drilling~~to ~~program~~which init ~~the~~provides ~~Covington~~services, ~~Prospect~~and inthis ~~Ward~~allocation ~~County,~~is ~~Texas~~a tosignificant ~~Reef~~portion ~~2012-A~~of ~~Private~~the ~~Drilling~~Partnership’s ~~Fund,~~general Land administrative expenses.~~P.,~~ aThe ~~Reef~~allocation ~~affiliate~~of ~~(“Reef~~RELP’s ~~2012-A”). The~~overhead ~~estimated~~to ~~drilling~~the ~~cost~~partnerships ofto ~~the~~which ~~three~~it ~~proposed~~provides ~~wells~~services tois ~~the~~based ~~Partnership~~upon ~~was~~several infactors, ~~excess~~including the level of ~~$450~~drilling activity,~~000~~ revenues, and ~~the~~capital ~~Partnership~~and ~~would~~operating ~~have~~expenditures ~~needed~~of each partnership compared to ~~retain~~the ~~cash~~total ~~flow~~levels ~~from~~of ~~producing~~all ~~properties~~partnerships. During ~~and~~the ~~forego~~years ~~distributions~~ended toDecember 31, ~~partners~~2015, ~~for~~2014, ~~several~~and ~~months~~2013, inthe ~~order~~administrative overhead charged by RELP to ~~fund~~the ~~this~~Partnership ~~drilling~~totaled ~~project~~$279,085, $431,793, and $489,183, respectively. The ~~leasehold~~administrative ~~acreage~~overhead ~~sold~~charged ~~also~~by RELP is included ~~one~~in ~~productive~~general ~~working~~and ~~interest~~administrative ~~well~~expense ~~and~~in ~~twelve~~the ~~productive~~accompanying ~~royalty~~statements ~~interest~~of ~~wells~~operations. ~~The~~RELP’s ~~sales~~general ~~price~~and ~~was~~administrative ~~$201~~costs include all customary and routine expenses,~~573~~ accounting, ofoffice ~~which~~rent, ~~$93~~telephone,~~451~~ ~~was~~secretarial, ~~received~~salaries inand ~~2012~~other ~~and~~incidental ~~the~~expenses ~~remainder~~incurred ~~during~~by ~~2013.~~RELP Inor ~~accordance~~its ~~with~~affiliates ~~the~~that ~~full~~are ~~cost~~necessary ~~method~~to ofthe ~~accounting,~~conduct of the Partnership’s ~~did~~business, ~~not~~whether ~~record~~generated ~~any~~by ~~gain~~RELP, orits ~~loss~~affiliates ~~related~~or toby ~~this~~third ~~transaction~~parties, asbut itexcluding ~~did~~direct ~~not~~costs ~~significantly~~and ~~affect~~operating ~~the unit-of-production amortization rate~~costs.

5RELP processes joint interest billings and revenues on behalf of the Partnership. ~~Major~~At ~~Customers~~December 31, 2015 and 2014, RELP owed the Partnership $135,851 and $183,078, 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. At September 30, 2015, RELP also owed the Partnership $181,610 associated with the sale of the Partnership’s Slaughter Dean Properties. The amount represented post-closing purchase price adjustments due from the purchaser of the Slaughter Dean Properties. RELP has been unsuccessful in collecting this balance due, and as of December 31, 2015 this amount was re-classified as a bad debt expense on the books of the Partnership.

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, 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.

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Notes to Financial Statements (continued)

5. 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, 2015, one marketer and one operator accounted for 44.3% and 18.2% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2014, the same marketer and 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, the same marketer and operator accounted for 38.0% and 32.8% 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.

6. Commitments and Contingencies

The Partnership is not currently involved in any legal proceedings.

The Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN Associates whereby the Partnership agreed to assign a one percent (1%) overriding royalty interest, proportionately reduced to the Partnership’s working interest, to William R. Dixon in exchange for Dixon’s agreement to “review and evaluate exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnership’s working interest in the Slaughter Dean Properties. During the years ended December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013, William R. Dixon received $194,~~379~~216, $1719,~~147~~379, and $2317,~~819~~147, respectively, related to this overriding royalty interest. AtThe ~~December 31,~~Partnership ~~2014,~~sold ~~the~~its ~~estimated~~interest ~~net~~in ~~proved reserves of~~ the Slaughter Dean Properties, asduring ~~determined~~the bysecond quarter of 2015, and the ~~independent~~liability ~~engineering~~for ~~firm~~payment ~~used~~of bythis ~~the~~overriding ~~Partnership,~~royalty ~~had~~interest awas ~~remaining~~transferred ~~economic~~to ~~life~~the purchaser of 27the ~~years~~Slaughter Dean Properties.

7. Partnership Equity

Information regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the years ended December 31, ~~2014~~2015, ~~2013~~2014 and ~~2012~~2013 is detailed below:

For the year ended December 31, 2015

Type of Unit	Number of Units	Net (loss)			Net income (loss) per unit
Managing general partner	9.2197	$	(206,905	)	$	(22,103	)
General partner	490.7327	(3,919,283		)	$	(7,985	)
Limited partner	397.0172	(3,170,225		)	$	(7,985	)
Total	896.9696	$	(7,296,413	)

For the year ended December 31, 2014

Type of Unit	Number of Units	Net income (loss)			Net income ~~(loss)~~ per unit
Managing general partner	8.9697	$	29,212		$	3,~~256.80~~257
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	)

For the year ended December 31, 2013

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

For the year ended December 31, 2012

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

8. Subsequent Event

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.

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Notes to Financial Statements (continued)

For the year ended December 31, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	156,604	$	17,459
General partner	490.9827	146,353		$	298
Limited partner	397.0172	118,343		$	298
Total	896.9696	$	421,300

8. Subsequent Event

During the first quarter of 2016, two investor partners owning 0.50 units of general partner interest and 0.50 units of limited partner interest have abandoned their interests in the Partnership. As such, the Partnership has reduced the total number of general partner and limited partner units outstanding effective January 1, 2016 to reflect these abandonments.

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

Capitalized Costs

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

	December 31, 2014			December 31, 2013			December 31, 2012
	December 31, 2015			December 31, 2014
Oil and natural gas properties:
Unproved properties	$	—		$	~~389,672~~—		$	~~524,357~~
Proved properties	7515,~~650~~079,~~205~~599			75,~~083~~650,~~374~~205			~~74,628,075~~
Capitalized asset retirement cost	2418,~~118,163~~435			2,~~126~~118,~~682~~163			~~2,124,314~~
	77,768,368			77,599,728			77,276,746
	15,498,034			77,768,368
Less:
Accumulated depreciation, depletion and amortization	(61,~~197~~331,~~743~~652		)	(56,~~212~~197,~~971~~743		)	~~(4,116,026~~		)
Property impairment	(6013,~~453~~405,~~728~~922		)	(5860,~~612~~453,~~454~~728		)	~~(58,612,454~~		)
	(66,651,471		)	(63,825,425		)	(62,728,480		)
	(14,737,574		)	(66,651,471		)
Total	$	11760,~~116,897~~460		$	1311,~~774~~116,~~303~~897		$	~~14,548,266~~

Costs Incurred

The following table sets forth the costs incurred in oil and gas exploration and development activities during the years ended December 31, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013.

	2014		2013		2012
	2015		2014		2013
Oil and natural gas properties:
Exploration	$	—	$	—	$	—
Development	~~559~~317,~~177~~234		~~588~~559,~~267~~177		1588,~~540,206~~267
Total	$	~~559~~317,~~177~~234	$	~~588~~559,~~267~~177	$	1588,~~540,206~~267

Results of Operations

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

	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

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

Notes to Financial Statements (continued)

Results of Operations

The following table sets forth the results of operations from oil and gas producing activities for the years ended December 31, 2015, 2014 and 2013

	2015			2014			2013

Oil and gas producing activities:
Oil sales	$	1,404,084		$	3,852,681		$	4,746,601
Natural gas sales	152,966			381,900			365,881
Production expenses	(1,420,224		)	(2,861,131		)	(2,626,024		)
Accretion of asset retirement obligation	(56,096		)	(163,490		)	(155,345		)
Depreciation, depletion and amortization	(524,630		)	(1,194,107		)	(1,102,611		)
Property impairment	(5,432,366		)	(1,841,274		)	—
Results of operations from oil and gas producing activities	$	(5,876,266	)	$	(1,825,421	)	$	1,228,502

Depletion rate per BOE	$	12.08		$	18.98		$	16.16

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

Crude Oil and Natural Gas Reserves

Net Proved Reserve Summary

The reserve information presented below is based upon estimates of net proved oil and gas reserves that were prepared by Jerald Sluder, the Senior Reservoir Engineer for RELP, as of December 31, 2015, and by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014, ~~2013~~ and ~~2012~~2013. 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 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, 2015 and 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.

The 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.

	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

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Notes to Financial Statements (continued)

The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013.

	Oil (BBL) (1)		Gas (mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
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

Reserves sold	(417,582	)	(131,452	)	(439,491	)
Revisions of previous estimates	(27,049	)	(92,595	)	(42,481	)
Production	(32,037	)	(68,343	)	(43,427	)
Reserves at December 31, 2015	50,012		365,260		110,889

(1) Oil includes both oil and natural gas liquids

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

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, ~~2014~~2015, ~~2013~~2014, and ~~2012~~2013, calculations were made using average prices of $9350.6319, $9693.9063, and $9496.6890 per barrel of crude oil, respectively, and $42.2263, $34.6722, and $23.7667 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, 2014, 2013 and 2012 were as 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

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:

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

Notes to Financial Statements (continued)

	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

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, 2015, 2014 and 2013 were as follows:

	December 31, 2015			December 31, 2014			December 31, 2013
Future cash inflows	$	3,156,030		$	50,801,390		$	58,719,780
Future production costs	(1,873,760		)	(22,574,330		)	(23,427,730		)
Future development costs	—			—			(23,970		)
Future net cash flows	1,282,270			28,227,060			35,268,080
Effect of discounting net cash flows at 10%	(521,810		)	(17,110,163		)	(21,285,710
Discounted future net cash flows	$	760,460		$	11,116,897		$	13,982,370

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, 2015			December 31, 2014			December 31, 2013
Standardized measure at beginning of period	$	11,116,897		$	13,982,370		$	16,721,530
New Discoveries, net of future production and development cost	—			97,740			139,290
Net change in sales price, net of production costs	(9,014,606		)	(1,797,237		)	1,603,865
Revisions of quantity estimates	(1,117,671		)	92,511			(3,155,972		)
Changes in production timing rates	2,575,805			(1,404,294		)	(665,373		)
Accretion of discount	1,111,690			1,398,237			1,672,153
Sales net of production costs	(80,730		)	(1,209,960		)	(2,331,113		)
Sales of minerals in place	(3,830,925		)	(42,470		)	(2,010		)
Net decrease	(10,356,437		)	(2,865,473		)	(2,739,160		)
Standardized measure at end of year	$	760,460		$	11,116,897		$	13,982,370

F-16

Filing Compare · Reef Oil & Gas Income & Development Fund III LP