10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended June 30, 2013

or

oTRANSITION 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)	(Zip code)

(972)-437-6792

(Registrant’s telephone number, including area code)

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 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

As of August 14, 2013, the registrant had 490.9827 units of general partner interest outstanding, 8.9697 units of general partner interest held by the managing general partner, and 397.0172 units of limited partner interest outstanding.

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

Form 10-Q Index

PART I — FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)
	Condensed Balance Sheets
	Condensed Statements of Operations
	Condensed Statements of Cash Flows
	Notes to Condensed Financial Statements
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk
ITEM 4.	Controls and Procedures
PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings
ITEM 1A.	Risk Factors
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds
ITEM 3.	Default Upon Senior Securities
ITEM 4.	Mine Safety Disclosures
ITEM 5.	Other Information
ITEM 6.	Exhibits
Signatures

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

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

Condensed Balance Sheets

	June 30,2013		December 31,2012
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	477,723	$	495,244
Accounts receivable	—		1,986
Accounts receivable from affiliates	695,526		679,422
Deferred financing fees, net	8,280		12,299
Total current assets	1,181,529		1,188,951
Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $63,254,122 and $62,728,480	13,816,798		14,023,909
Unproved properties	524,357		524,357
Net oil and gas properties	14,341,155		14,548,266
Deferred financing fees, net	7,589		—
Total assets	$	15,530,273	$	15,737,217
Liabilities and partnership equity
Current liabilities:
Accounts payable	$	6,430	$	5,595
Current portion of long-term note payable	360,000		1,315,000
Total current liabilities	366,430		1,320,595
Long-term liabilities:
Note payable (Note 3)	775,000		—
Asset retirement obligation	2,401,433		2,366,899
Total long-term liabilities	3,176,433		2,366,899
Partnership equity
General partners	6,839,518		6,899,244
Limited partners	4,946,775		4,995,071
Managing general partner	201,117		155,408
Partnership equity	11,987,410		12,049,723
Total liabilities and partnership equity	$	15,530,273	$	15,737,217

See accompanying notes to condensed financial statements (unaudited).

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

Condensed Statements of Operations

(Unaudited)

	For the three months ended June 30,						For the six months ended June 30,
	2013			2012			2013			2012
Oil, gas and NGL sales	$	1,342,186		$	1,488,651		$	2,515,170		$	3,133,876
Costs and expenses:
Lease operating expenses	604,372			616,352			1,165,328			1,287,055
Production taxes	84,438			106,208			150,659			208,697
Depreciation, depletion and amortization	287,030			308,137			525,642			650,707
Accretion of asset retirement obligation	39,250			29,207			77,957			57,812
General and administrative	205,600			221,048			405,975			439,276
Total costs and expenses	1,220,690			1,280,952			2,325,561			2,643,547
Income from operations	121,496			207,699			189,609			490,329
Other income (expense):
Miscellaneous income	—			—			443			69
Interest expense	(15,195		)	(20,795		)	(31,172		)	(42,446		)
Amortization of deferred financing fees	(3,430		)	(6,044		)	(9,580		)	(12,088		)
Total other income (expense)	(18,625		)	(26,839		)	(40,309		)	(54,465		)
Net income	$	102,871		$	180,860		$	149,300		$	435,864
Net income per general partner unit	$	70.78		$	146.57		$	90.44		$	363.57
Net income per limited partner unit	$	70.78		$	146.57		$	90.44		$	363.57
Net income per managing general partner unit	$	4,461.58		$	5,653.25		$	7,691.12		$	12,599.64

See accompanying notes to condensed financial statements (unaudited).

2

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

Condensed Statements of Cash Flows

(Unaudited)

	For the six months ended June 30,
	2013			2012
Cash flows from operating activities
Net income	$	149,300		$	435,864
Adjustments to reconcile net income to net cash provided by operating activities:
Plugging and abandonment costs paid from ARO	(43,423		)	—
Adjustments for non-cash transactions:
Depreciation, depletion and amortization	525,642			650,707
Accretion of asset retirement obligation	77,957			57,812
Amortization of deferred financing fees	9,580			12,088
Changes in operating assets and liabilities:
Accounts receivable	1,986			—
Accounts receivable from affiliates	(16,104		)	(115,477		)
Accounts payable	835			746
Net cash provided by operating activities	705,773			1,041,740
Cash flows from investing activities
Property development	(318,531		)	(600,606		)
Net cash used in investing activities	(318,531		)	(600,606		)
Cash flows from financing activities
Payment of note payable	(180,000		)	(180,000		)
Payment of debt issuance costs	(13,150		)	—
Partner distributions	(211,613		)	(300,354		)
Net cash used in financing activities	(404,763		)	(480,354		)
Net decrease in cash and cash equivalents	(17,521		)	(39,220		)
Cash and cash equivalents at beginning of period	495,244			513,410
Cash and cash equivalents at end of period	$	477,723		$	474,190
Supplemental cash flow disclosure:
Cash paid for interest	$	30,941		$	42,447
Supplemental disclosure of non-cash investing transactions:
Additions to property and asset retirement obligation	$	—		$	6,559

See accompanying notes to condensed financial statements (unaudited).

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

Notes to Condensed Financial Statements (unaudited)

June 30, 2013

1. Organization and Basis of Presentation

The condensed financial statements of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first six months of 2013. Therefore, please read these unaudited condensed financial statements and notes to unaudited condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”). The results of operations for the three and six month periods ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

2. Summary of 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, as determined by independent petroleum engineers.  Proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the  sum of the estimated future net revenues from proved reserves using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. 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. The Partnership does not recognize gain or loss upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no property impairment expense of proved properties.

At June 30, 2013 and December 31, 2012, unproved properties consist of non-operated, undrilled infill and offset drilling locations associated with certain working interests acquired from Azalea Properties Ltd. on January 19, 2010 by RCWI L.P., an affiliate of Reef, and assigned to the Partnership (the “Azalea Acquired Properties”). Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this assessment is included in the full cost pool in the current period, as appropriate. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no impairment of unproved properties.

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Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at June 30, 2013 and December 31, 2012 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 current 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.

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

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 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 six month period ended June 30, 2013 and the year ended December 31, 2012.

	Six months ended June 30, 2013			Year ended December 31, 2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	—			7,579
Additions related to existing properties	—			438,610
Retirement related to property sales	—			(1,605		)
Retirement related to property abandonment and restoration	(43,423		)	(32,388		)
Accretion expense	77,957			119,588
Ending asset retirement obligation	$	2,401,433		$	2,366,899

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at June 30, 2013 and December 31, 2012 and is classified as Level 2 within the fair value hierarchy.

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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 consolidated statements of operations equals comprehensive income.

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 the acquisition of certain oil and gas properties (“Lett Acquired Properties”) purchased from Lett Oil & Gas, L.P. (“Lett”) by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in Note 2 of the Annual Report.  The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly.  At June 30, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement are set to expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.  The Partnership borrowed $5,000,000 from TCB under the Credit Agreement which was paid directly to Lett to satisfy the closing obligations of RCWI under the purchase agreement for the Lett Acquired Properties.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.

Under the terms of the Credit Agreement, on June 30, 2010 the Partnership paid TCB certain facility fees and engineering fees.  The Partnership is further obligated to pay additional facility fees upon each determination of an increase in the borrowing base, and additional engineering fees if TCB’s internal engineers perform the engineering review of the collateral, or the actual fees and expenses of any third-party engineers retained by TCB to prepare an engineering report, payable at the time of a redetermination of the borrowing base.

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

On April 30, 2013, the Partnership entered into the Third Amendment to the Credit Agreement (“Third Amendment”), with TCB.  The Third Amendment extended the final maturity date of the Credit Agreement and the obligations thereunder from June 30, 2013 to June 30, 2015.  During May 2013, the Partnership paid TCB fees of $13,150 in connection with the Third Amendment.  These fees have been capitalized as other assets on the accompanying balance sheet and will be amortized over the remaining term of the Credit Agreement.  At June 30, 2013, the borrowing base, as well as the outstanding balance under the Credit Agreement, was $1,135,000.  The borrowing base is currently being reduced by $30,000 per month, and as such, the Partnership has recognized $360,000 of the outstanding note payable as a current liability as of June 30, 2013 on the accompanying balance sheet.

6

The Credit Agreement contains various covenants, including among others:

·restrictions on liens;

·restrictions on incurring other indebtedness without the lenders’ consent;

·restrictions on distributions and other restricted payments;

·maintenance of a current ratio as of the end of each fiscal quarter commencing September 30, 2010 of not less than 1.0 to 1.0, as adjusted; and

·maintenance of an interest coverage ratio of cash flow to fixed charges as of the end of each fiscal quarter commencing September 30, 2010, to be at least 3.0 to 1.0.

All outstanding amounts owed under the Credit Agreement become due and payable upon the occurrence of certain usual and customary events of default, including among others:

·failure to make payments under the Credit Agreement;

·non-performance of covenants and obligations continuing beyond any applicable grace period; and

·the occurrence of a “Change in Control” (as defined in the Credit Agreement).

At June 30, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into an account with the lender.  A waiver of this requirement through December 31, 2013 has been obtained.

4. Transactions with Affiliates

The Partnership has no employees. Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. RELP currently serves as the operator of the Slaughter Field in Cochran County, Texas (the “Slaughter Dean Project”) and receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership.  RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells included in the Azalea Acquired Properties and the Lett Acquired Properties. All of the wells included in these two purchases are non-operated. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point.  In addition, total well costs include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion.  Total well costs do not include costs relating to lease acquisitions.  During the six month period ended June 30, 2013, RELP received $14,934 in drilling compensation. During the year ended December 31, 2012, RELP received $39,856 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 three and six month periods ended June 30, 2013, Reef and its affiliates received total reimbursements for direct costs of $30,161 and $65,803, respectively, and other documented out-of-pocket expenses of $627 and $910, respectively. During the three and six month periods ended June 30, 2012, Reef and its affiliates received total reimbursements for direct costs of $41,208 and $102,920, respectively, and other documented out-of-pocket expenses of $203 and $342, respectively.

7

RELP also receives an administrative fee to cover all general and administrative costs.  During the three and six month periods ended June 30, 2013, RELP received administrative fees totaling $117,260 and $241,169, respectively. During the three and six month periods ended June 30, 2012, RELP received administrative fees totaling $147,495 and $304,017, respectively. Administrative fees are included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At June 30, 2013 and December 31, 2012, RELP owed the Partnership $650,004 and $633,900, respectively, for net revenues processed in excess of joint interest, drilling compensation, and technical and administrative services 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 to which the revenues pertain. The Partnership settles its balances with Reef and RELP on at least a quarterly basis.  The Partnership also recorded $45,522 as accounts receivable from a Reef affiliate as of June 30, 2013 and December 31, 2012, related to the sale of certain leasehold interests.  The final amount could be less than or more than the current estimate, and is expected to be settled during the third quarter of 2013.

5. Commitments and Contingencies

None.

6.  Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three and six month periods ended June 30, 2013 is detailed below:

For the three months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	40,019	$	4,461.58
General partner	490.9827	34,752		$	70.78
Limited partner	397.0172	28,100		$	70.78
Total	896.9696	$	102,871

For the six months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	68,987	$	7,691.12
General partner	490.9827	44,406		$	90.44
Limited partner	397.0172	35,907		$	90.44
Total	896.9696	$	149,300

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following is a discussion of the Partnership’s financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our audited financial statements and the related notes thereto, included in the Annual Report.

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

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

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

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

·any statements of other than historical fact.

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

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

Overview

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

On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but will not engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations.  Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef.

The Partnership owns interests in over 1,500 wells located in twelve states, including the Slaughter Dean Project. The management of the operations and other business of the Partnership is the responsibility of Reef.  RELP, an affiliate of Reef, serves as the operator of the Slaughter Dean Project. This relationship with the Partnership is governed by two operating agreements.  One operating agreement (the “Sierra-Dean Operating Agreement” is between the Partnership, RELP and Sierra Dean.  The other operating agreement is between the Partnership, RELP, and Davric (the “Davric Operating Agreement”).  All other properties are operated by third party operators not affiliated with Reef or any of Reef’s affiliates.

9

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of June 30, 2013.

	Leasehold Costs		Drilling and Facilities Costs		Workovers		Total Costs
Purchase Existing Wells	$	35,475,652	$	—	$	—	$	35,475,652
New Wells
Producing Wells	33,923		29,793,705		—		29,827,628
Waterflood Injector Wells	—		5,149,620		—		5,149,620
Facilities	—		1,795,397		—		1,795,397
Existing Wells	—		—		7,076,418		7,076,418
Total	$	35,509,575	$	36,738,722	$	7,076,418	$	79,324,715

The Partnership has expended approximately $57,317,107 (included in the expenditures shown in the table above) on the Slaughter Dean Project as of June 30, 2013.  At December 31, 2010, the Partnership fully impaired its unproved properties associated with the Slaughter Dean Project by recognizing approximately $53,166,873 of property impairment expense.  The Partnership continues to monitor the implementation of waterflood operations and daily production of total fluids (oil and water), which are less than the total water injected each day, to determine the cause of the underperformance of the waterflood operations.  The Partnership may gather additional data in order to determine whether alternate configurations of water injection wells may be more effective in producing a better waterflood response in the future, though such alternative configurations may be cost prohibitive to the Partnership to implement.  The Partnership currently plans to continue waterflood operations as currently configured.

Liquidity and Capital Resources

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 general partner units and 397.0172 limited partner units for $88,648,094, net of adjustments for sales to brokers for their own accounts, who were permitted to buy units at a price net of the commission that they would normally earn on sales of units. Reef contributed $762,425 for the purchase of 8.9697 general partner units at a price of $85,000 per unit, which is net of all offering costs. Organization and offering costs totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of June 30, 2013, the Partnership had expended $79,324,715 on property acquisition and development costs, prior to sales of the Partnership’s interests or portions of its interests in certain properties during 2011 and 2012. Expenditures in excess of available capital have been financed through debt or recovered from cash flows by reducing Partnership distributions.

The Partnership had working capital of $815,099 at June 30, 2013. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the Partnership working capital consists primarily of cash flows from productive properties 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.

10

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the unaudited condensed financial statements and the related notes to the unaudited condensed financial statements included in this Quarterly Report.

The following table provides information about sales volumes and crude oil and natural gas prices for the periods indicated. Equivalent barrels of oil (“EBO”) are computed by converting 6 Mcf of natural gas to 1 barrel of crude oil.

	For the three months ended June 30,				For the six months ended June 30,
	2013		2012		2013		2012
Sales volumes:
Oil (Barrels)	14,026		16,175		26,883		32,063
Natural gas (Mcf)	28,645		23,923		45,343		68,409
Average sales prices received:
Oil (Barrels)	$	87.51	$	84.77	$	86.59	$	89.23
Natural gas (Mcf)	$	4.01	$	4.91	$	4.13	$	3.99

The estimated net proved crude oil and natural gas reserves as of June 30, 2013 and 2012 are summarized below. The quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

Net proved reserves	Oil (Bbl)	Gas (Mcf)
June 30, 2013	743,670	967,770
June 30, 2012	665,180	968,340

Three months ended June 30, 2013 compared to the three months ended June 30, 2012

The Partnership had net income of $102,871 for the three month period ended June 30, 2013, compared to net income of $180,860 for the three month period ended June 30, 2012. The primary causes of this change were declines in oil sales volumes and in average natural gas sales prices, which were partially offset by increases in average oil sales prices and in natural gas sales volumes.

Partnership revenue decreased between the comparative periods, totaling $1,342,186 for the three month period ended June 30, 2013 compared to $1,488,651 for the comparable three month period in 2012.  Overall sales volumes decreased by 6.8% on an EBO basis as a result of natural declining oil production from wells in which the Partnership owns an interest.  Oil sales volumes declined primarily in the Azalea Acquired Properties and a portion of the Slaughter Dean Project, the Slaughter Dean B Unit.  Although average prices received for crude oil increased by 3.23% to an average price of $87.51 for the three month period ended June 30, 2013 as compared to the three month period ended June 30, 2012, the average sales price for natural gas decreased by 18.3% to $4.01 for the comparable periods. During the three month period ended June 30, 2013, gas volumes comprised only approximately 25.4% of the Partnership’s total sales volumes on an EBO basis. The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes.  The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

11

Lease operating expenses decreased from $616,352 for the three month period ended June 30, 2012 to $604,372 for the three month period ended June 30, 2013, due primarily to lower workover expenses and lower overhead expenses on the Azalea Acquired Properties. Production tax expense totaled $84,438 for the three month period ended June 30, 2013 compared to $106,208 for the three month period ended June 30, 2012, due in part to declining sales volumes and also to a reduction in the severance tax rate on the Slaughter Dean B Unit. During the third quarter of 2012, RELP received a production tax refund from the State of Texas of approximately $54,000 related to the waterflood enhancement project performed in the Slaughter Dean 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 were refunded. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 31.5% of total second quarter 2013 revenues. The tax rate reduction saved the Partnership approximately $9,900 during the second quarter of 2013.

General and administrative costs incurred during the three month periods ended June 30, 2013 and 2012 decreased to $205,600 from $221,048. 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 $147,495 during the three month period ended June 30, 2012 to $117,260 during the three month period ended June 30, 2013. This decrease was partially offset by increased professional services fees related to processing SEC filings.

Six months ended June 30, 2013 compared to the six months ended June 30, 2012

The Partnership had net income of $149,300 for the six month period ended June 30, 2013, compared to net income of $435,864 for the six month period ended June 30, 2012. The primary cause of this change was declines in sales volumes and in average oil sales prices.

Partnership revenue decreased between the comparative periods, totaling $2,515,170 for the six month period ended June 30, 2013 compared to $3,133,876 for the comparable six month period in 2012.  Overall sales volumes decreased by 20.8% on an EBO basis as a result of natural declining production from wells in which the Partnership owns an interest.  In addition, average prices received for crude oil were less during the six month period ended June 30, 2013 as compared to the six month period ended June 30, 2012. The average sales price for crude oil dropped by 3.0%, to an average price of $86.59  per Bbl for the six month period ended June 30, 2013, compared to an average price of $89.23 for the six month period ended June 30, 2012.  The average sales price for natural gas increased by 3.5%, from an average price of $3.99 per Mcf during the six month period ended June 30, 2012 to $4.13 during the six month period ended June 30, 2013.  The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes.  The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

Lease operating expenses decreased from $1,287,055 for the six month period ended June 30, 2012 to $1,165,328 for the six month period ended June 30, 2013, due primarily to lower property taxes on various properties, lower workover expenses, utilities, and contract labor expenses on the Slaughter Dean property, and lower overhead on the Azalea Acquired Properties. Production tax expense totaled $150,659 for the six month period ended June 30, 2013 compared to $208,697 for the six month period ended June 30, 2012, due in part to declining sales volumes and also to a reduction in the severance tax rate on the Slaughter Dean B Unit. During the third quarter of 2012, RELP received a production tax refund from the State of Texas of approximately $54,000 related to the waterflood enhancement project performed in the Slaughter Dean 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 were refunded. Going forward, the overall average production tax rate paid by the Partnership will decline as a result of this rate reduction. Oil sales from the Slaughter Dean B Unit accounted for 31.6% of total revenues for the first six months of 2013. The tax rate reduction saved the Partnership approximately $18,400 during the first six months of 2013.

12

General and administrative costs incurred during the six month periods ended June 30, 2013 and 2012 decreased to $405,975 from $439,276. 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 $304,017 during the six month period ended June 30, 2012 to $241,169 during the six month period ended June 30, 2013. This decrease was partially offset by increased professional services fees related to processing SEC filings.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership is a “smaller reporting company” as defined by Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as such, is not required to provide the information required under this Item.

Item 4. 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 report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Quarterly Report. Based on that evaluation, the principal executive officer and principal financial officer 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 SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding financial disclosure.

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

None.

Item 1A.  Risk Factors

There were no material changes in the Risk Factors applicable to the Partnership as set forth in the Annual Report.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.  Default Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

13

Item 6.  Exhibits

Exhibits
10.1	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 lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 15, 2013).
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1	Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**
32.2	Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*Filed herewith

**Furnished herewith

14

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	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
Dated: August 14, 2013		By:	/s/ Michael J. Mauceli
			Michael J. Mauceli
			Manager and Member
			(Principal Executive Officer)
Dated: August 14, 2013		By:	/s/ Daniel C. Sibley
			Daniel C. Sibley
			Chief Financial Officer and General Counsel of
			Reef Exploration, L.P.
			(Principal Financial and Accounting Officer)

15

EXHIBIT INDEX

Exhibits
10.1	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 lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on May 15, 2013).
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1	Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**
32.2	Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.**
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*Filed herewith

**Furnished herewith

16

EX-31.1

Exhibit 31.1

Certification of Principal Executive Officer

Pursuant to 15 U.S.C. Section 7241, as Adopted

Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002

I, Michael J. Mauceli, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, of Reef Oil & Gas Income and Development Fund III, L.P. (the “Registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5.The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date:  August 14, 2013

/s/ Michael J. Mauceli

Michael J. Mauceli

Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the Partnership

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

Certification of Principal Financial Officer

Pursuant to U.S.C. Section 7241, as Adopted

Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002

I, Daniel C. Sibley, certify that:

1)I have reviewed this Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2013, of Reef Oil & Gas Income and Development Fund III, L.P. (the “Registrant”);

2)Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3)Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4)The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5)The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date:   August 14, 2013	/s/ Daniel C. Sibley
	Daniel C. Sibley
	Chief Financial Officer and General Counsel of
	Reef Exploration, L.P.
	(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

Certification of Principal Executive Officer

 Pursuant to 18 U.S.C. § 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Mauceli, principal executive officer of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 14, 2013

/s/ Michael J. Mauceli

Michael J. Mauceli

Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the Partnership

(Principal Executive Officer)

This certification accompanies the Report pursuant to § 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Partnership for purposes of § 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of Principal Financial Officer

Pursuant to 18 U.S.C. § 1350,

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2013  as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Daniel C. Sibley, principal financial officer of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date:August 14, 2013	/s/ Daniel C. Sibley
	Daniel C. Sibley
	Chief Financial Officer and General Counsel of
	Reef Exploration, L.P.
	(Principal Financial and Accounting Officer)

This certification accompanies the Report pursuant to § 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Partnership for purposes of § 18 of the Securities Exchange Act of 1934, as amended.

A signed original of this written statement has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Transactions with Affiliates (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Item	Jun. 30, 2012	Dec. 31, 2012
Transactions with Affiliates
Number of employees	0		0
Due from affiliates	$ 695,526		$ 695,526		$ 679,422
RELP
Transactions with Affiliates
Drilling compensation reimbursed as a percentage of total well costs paid			15.00%
Drilling compensation reimbursed as a percentage of total well costs paid for non-operated wells			5.00%
Number of purchases of properties with non-operated wells			2
Drilling compensation paid			14,934		39,856
Administrative fee paid to cover general and administrative costs	117,260	147,495	241,169	304,017
Due from affiliates	650,004		650,004		633,900
RELP | Minimum
Transactions with Affiliates
Period for receipt of cash from oil and gas purchasers, associated with the net revenues processed by affiliate			30 days
RELP | Maximum
Transactions with Affiliates
Period for receipt of cash from oil and gas purchasers, associated with the net revenues processed by affiliate			60 days
Reef and its affiliates
Transactions with Affiliates
Total reimbursements for direct costs	30,161	41,208	65,803	102,920
Other documented out-of-pocket expenses reimbursed	627	203	910	342
Reef 2012-A Private Drilling Fund, L.P
Transactions with Affiliates
Due from affiliates	$ 45,522		$ 45,522		$ 45,522

XML

Condensed Statements of Operations (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statements of Operations
Oil, gas and NGL sales	$ 1,342,186	$ 1,488,651	$ 2,515,170	$ 3,133,876
Costs and expenses:
Lease operating expenses	604,372	616,352	1,165,328	1,287,055
Production taxes	84,438	106,208	150,659	208,697
Depreciation, depletion and amortization	287,030	308,137	525,642	650,707
Accretion of asset retirement obligation	39,250	29,207	77,957	57,812
General and administrative	205,600	221,048	405,975	439,276
Total costs and expenses	1,220,690	1,280,952	2,325,561	2,643,547
Income from operations	121,496	207,699	189,609	490,329
Other income (expense):
Miscellaneous income			443	69
Interest expense	(15,195)	(20,795)	(31,172)	(42,446)
Amortization of deferred financing fees	(3,430)	(6,044)	(9,580)	(12,088)
Total other income (expense)	(18,625)	(26,839)	(40,309)	(54,465)
Net income	$ 102,871	$ 180,860	$ 149,300	$ 435,864
Net income per general partner unit (in dollars per unit)	$ 70.78	$ 146.57	$ 90.44	$ 363.57
Net income per limited partner unit (in dollars per unit)	$ 70.78	$ 146.57	$ 90.44	$ 363.57
Net income per managing general partner unit (in dollars per unit)	$ 4,461.58	$ 5,653.25	$ 7,691.12	$ 12,599.64

XML

Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies

Commitments and Contingencies

5. Commitments and Contingencies

None.

XML

Partnership Equity (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Number of Units
Managing general partner	8.9697		8.9697
General partner	490.9827		490.9827
Limited partner	397.0172		397.0172
Total	896.9696		896.9696
Net income
Managing general partner	$ 40,019		$ 68,987
General partner	34,752		44,406
Limited partner	28,100		35,907
Net income	$ 102,871	$ 180,860	$ 149,300	$ 435,864
Net income per unit
Managing general partner (in dollars per unit)	$ 4,461.58	$ 5,653.25	$ 7,691.12	$ 12,599.64
General partner (in dollars per unit)	$ 70.78	$ 146.57	$ 90.44	$ 363.57
Limited partner (in dollars per unit)	$ 70.78	$ 146.57	$ 90.44	$ 363.57

XML

Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2013

Organization and Basis of Presentation

Organization and Basis of Presentation

1. Organization and Basis of Presentation

The condensed financial statements of Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first six months of 2013. Therefore, please read these unaudited condensed financial statements and notes to unaudited condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (the “Annual Report”). The results of operations for the three and six month periods ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.

XML

Long-Term Debt

6 Months Ended

Jun. 30, 2013

Long-Term Debt

Long-Term Debt

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 the acquisition of certain oil and gas properties (“Lett Acquired Properties”) purchased from Lett Oil & Gas, L.P. (“Lett”) by RCWI and assigned to the Partnership under the Assignment, Conveyance and Bill of Sale described in Note 2 of the Annual Report.  The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly.  At June 30, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement are set to expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.  The Partnership borrowed $5,000,000 from TCB under the Credit Agreement which was paid directly to Lett to satisfy the closing obligations of RCWI under the purchase agreement for the Lett Acquired Properties.  The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.

Under the terms of the Credit Agreement, on June 30, 2010 the Partnership paid TCB certain facility fees and engineering fees.  The Partnership is further obligated to pay additional facility fees upon each determination of an increase in the borrowing base, and additional engineering fees if TCB’s internal engineers perform the engineering review of the collateral, or the actual fees and expenses of any third-party engineers retained by TCB to prepare an engineering report, payable at the time of a redetermination of the borrowing base.

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

On April 30, 2013, the Partnership entered into the Third Amendment to the Credit Agreement (“Third Amendment”), with TCB.  The Third Amendment extended the final maturity date of the Credit Agreement and the obligations thereunder from June 30, 2013 to June 30, 2015.  During May 2013, the Partnership paid TCB fees of $13,150 in connection with the Third Amendment.  These fees have been capitalized as other assets on the accompanying balance sheet and will be amortized over the remaining term of the Credit Agreement.  At June 30, 2013, the borrowing base, as well as the outstanding balance under the Credit Agreement, was $1,135,000.  The borrowing base is currently being reduced by $30,000 per month, and as such, the Partnership has recognized $360,000 of the outstanding note payable as a current liability as of June 30, 2013 on the accompanying balance sheet.

The Credit Agreement contains various covenants, including among others:

· restrictions on liens;

· restrictions on incurring other indebtedness without the lenders’ consent;

· restrictions on distributions and other restricted payments;

· maintenance of a current ratio as of the end of each fiscal quarter commencing September 30, 2010 of not less than 1.0 to 1.0, as adjusted; and

· maintenance of an interest coverage ratio of cash flow to fixed charges as of the end of each fiscal quarter commencing September 30, 2010, to be at least 3.0 to 1.0.

All outstanding amounts owed under the Credit Agreement become due and payable upon the occurrence of certain usual and customary events of default, including among others:

· failure to make payments under the Credit Agreement;

· non-performance of covenants and obligations continuing beyond any applicable grace period; and

· the occurrence of a “Change in Control” (as defined in the Credit Agreement).

At June 30, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into an account with the lender.  A waiver of this requirement through December 31, 2013 has been obtained.

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Partnership Equity

6 Months Ended

Jun. 30, 2013

Partnership Equity

Partnership Equity

6.  Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three and six month periods ended June 30, 2013 is detailed below:

For the three months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	40,019	$	4,461.58
General partner	490.9827	34,752		$	70.78
Limited partner	397.0172	28,100		$	70.78
Total	896.9696	$	102,871

For the six months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	68,987	$	7,691.12
General partner	490.9827	44,406		$	90.44
Limited partner	397.0172	35,907		$	90.44
Total	896.9696	$	149,300

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Transactions with Affiliates

6 Months Ended

Jun. 30, 2013

Transactions with Affiliates

Transactions with Affiliates

4. Transactions with Affiliates

The Partnership has no employees. Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. RELP currently serves as the operator of the Slaughter Field in Cochran County, Texas (the “Slaughter Dean Project”) and receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership.  RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells included in the Azalea Acquired Properties and the Lett Acquired Properties. All of the wells included in these two purchases are non-operated. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point.  In addition, total well costs include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion.  Total well costs do not include costs relating to lease acquisitions.  During the six month period ended June 30, 2013, RELP received $14,934 in drilling compensation. During the year ended December 31, 2012, RELP received $39,856 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 three and six month periods ended June 30, 2013, Reef and its affiliates received total reimbursements for direct costs of $30,161 and $65,803, respectively, and other documented out-of-pocket expenses of $627 and $910, respectively. During the three and six month periods ended June 30, 2012, Reef and its affiliates received total reimbursements for direct costs of $41,208 and $102,920, respectively, and other documented out-of-pocket expenses of $203 and $342, respectively.

RELP also receives an administrative fee to cover all general and administrative costs.  During the three and six month periods ended June 30, 2013, RELP received administrative fees totaling $117,260 and $241,169, respectively. During the three and six month periods ended June 30, 2012, RELP received administrative fees totaling $147,495 and $304,017, respectively. Administrative fees are included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At June 30, 2013 and December 31, 2012, RELP owed the Partnership $650,004 and $633,900, respectively, for net revenues processed in excess of joint interest, drilling compensation, and technical and administrative services 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 to which the revenues pertain. The Partnership settles its balances with Reef and RELP on at least a quarterly basis.  The Partnership also recorded $45,522 as accounts receivable from a Reef affiliate as of June 30, 2013 and December 31, 2012, related to the sale of certain leasehold interests.  The final amount could be less than or more than the current estimate, and is expected to be settled during the third quarter of 2013.

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Condensed Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Balance Sheets
Proved properties, accumulated depletion	$ 63,254,122	$ 62,728,480

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Partnership Equity (Tables)

6 Months Ended

Jun. 30, 2013

Partnership Equity

Schedule of number of units outstanding and the net income per type of Partnership unit

For the three months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	40,019	$	4,461.58
General partner	490.9827	34,752		$	70.78
Limited partner	397.0172	28,100		$	70.78
Total	896.9696	$	102,871

For the six months ended June 30, 2013

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner	8.9697	$	68,987	$	7,691.12
General partner	490.9827	44,406		$	90.44
Limited partner	397.0172	35,907		$	90.44
Total	896.9696	$	149,300

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Condensed Statements of Cash Flows (USD $)	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Cash flows from operating activities
Net income	$ 149,300	$ 435,864
Adjustments to reconcile net income to net cash provided by operating activities:
Plugging and abandonment costs paid from ARO	(43,423)
Adjustments for non-cash transactions:
Depreciation, depletion and amortization	525,642	650,707
Accretion of asset retirement obligation	77,957	57,812
Amortization of deferred financing fees	9,580	12,088
Changes in operating assets and liabilities:
Accounts receivable	1,986
Accounts receivable from affiliates	(16,104)	(115,477)
Accounts payable	835	746
Net cash provided by operating activities	705,773	1,041,740
Cash flows from investing activities
Property development	(318,531)	(600,606)
Net cash used in investing activities	(318,531)	(600,606)
Cash flows from financing activities
Payment of note payable	(180,000)	(180,000)
Payment of debt issuance costs	(13,150)
Partner distributions	(211,613)	(300,354)
Net cash used in financing activities	(404,763)	(480,354)
Net decrease in cash and cash equivalents	(17,521)	(39,220)
Cash and cash equivalents at beginning of period	495,244	513,410
Cash and cash equivalents at end of period	477,723	474,190
Supplemental cash flow disclosure:
Cash paid for interest	30,941	42,447
Supplemental disclosure of non-cash investing transactions:
Additions to property and asset retirement obligation		$ 6,559

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Condensed Balance Sheets (USD $)	Jun. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 477,723	$ 495,244
Accounts receivable		1,986
Accounts receivable from affiliates	695,526	679,422
Deferred financing fees, net	8,280	12,299
Total current assets	1,181,529	1,188,951
Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $63,254,122 and $62,728,480	13,816,798	14,023,909
Unproved properties	524,357	524,357
Net oil and gas properties	14,341,155	14,548,266
Deferred financing fees, net	7,589
Total assets	15,530,273	15,737,217
Current liabilities:
Accounts payable	6,430	5,595
Current portion of long-term note payable	360,000	1,315,000
Total current liabilities	366,430	1,320,595
Long-term liabilities:
Note payable (Note 3)	775,000
Asset retirement obligation	2,401,433	2,366,899
Total long-term liabilities	3,176,433	2,366,899
Partnership equity
General partners	6,839,518	6,899,244
Limited partners	4,946,775	4,995,071
Managing general partner	201,117	155,408
Partnership equity	11,987,410	12,049,723
Total liabilities and partnership equity	$ 15,530,273	$ 15,737,217

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Summary of Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2013

Summary of Accounting Policies

Summary of Partnership's asset retirement obligation

	Six months ended June 30, 2013			Year ended December 31, 2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	—			7,579
Additions related to existing properties	—			438,610
Retirement related to property sales	—			(1,605		)
Retirement related to property abandonment and restoration	(43,423		)	(32,388		)
Accretion expense	77,957			119,588
Ending asset retirement obligation	$	2,401,433		$	2,366,899

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Long-Term Debt (Details) (USD $)			1 Months Ended		6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	May 31, 2013 Revolving credit facility	Jun. 30, 2010 Revolving credit facility	Jun. 30, 2013 Revolving credit facility	Jun. 30, 2013 Revolving credit facility Minimum
Long-term debt
Variable rate basis					U.S. prime rate
Interest rate added to the base rate (as a percent)					0.50%
Minimum interest rate payable monthly (as a percent)					5.00%
Interest rate at end of period (as a percent)					5.00%
Amount borrowed under the facility				$ 5,000,000
Percentage of oil and gas properties pledged as collateral						90.00%
Discount rate for present value of net revenues from oil and gas reserves (as a percent)					9.00%
Facility fees and engineering fees			13,150
Current borrowing base					1,135,000
Outstanding Balance of Note payable					1,135,000
Reduction of borrowing base per month					30,000
Current portion of outstanding note payable	$ 360,000	$ 1,315,000			$ 360,000
Covenant, current ratio						1.0
Covenant, interest coverage ratio						3.0

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Summary of Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Summary of Accounting Policies

Oil and Gas Properties

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, as determined by independent petroleum engineers.  Proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the  sum of the estimated future net revenues from proved reserves using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. 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. The Partnership does not recognize gain or loss upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no property impairment expense of proved properties.

At June 30, 2013 and December 31, 2012, unproved properties consist of non-operated, undrilled infill and offset drilling locations associated with certain working interests acquired from Azalea Properties Ltd. on January 19, 2010 by RCWI L.P., an affiliate of Reef, and assigned to the Partnership (the “Azalea Acquired Properties”). Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this assessment is included in the full cost pool in the current period, as appropriate. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no impairment of unproved properties.

Estimates of Proved Oil and Gas Reserves

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at June 30, 2013 and December 31, 2012 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 current 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.

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

Restoration, Removal, and Environmental Liabilities

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 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 six month period ended June 30, 2013 and the year ended December 31, 2012.

	Six months ended June 30, 2013			Year ended December 31, 2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	—			7,579
Additions related to existing properties	—			438,610
Retirement related to property sales	—			(1,605		)
Retirement related to property abandonment and restoration	(43,423		)	(32,388		)
Accretion expense	77,957			119,588
Ending asset retirement obligation	$	2,401,433		$	2,366,899

Fair Value of Financial Instruments

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at June 30, 2013 and December 31, 2012 and is classified as Level 2 within the fair value hierarchy.

Comprehensive Income

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 consolidated statements of operations equals comprehensive income.

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Summary of Accounting Policies

6 Months Ended

Jun. 30, 2013

Summary of Accounting Policies

Summary of Accounting Policies

2. Summary of 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, as determined by independent petroleum engineers.  Proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the  sum of the estimated future net revenues from proved reserves using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. 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. The Partnership does not recognize gain or loss upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no property impairment expense of proved properties.

At June 30, 2013 and December 31, 2012, unproved properties consist of non-operated, undrilled infill and offset drilling locations associated with certain working interests acquired from Azalea Properties Ltd. on January 19, 2010 by RCWI L.P., an affiliate of Reef, and assigned to the Partnership (the “Azalea Acquired Properties”). Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this assessment is included in the full cost pool in the current period, as appropriate. During the three and six month periods ended June 30, 2013 and 2012, the Partnership recognized no impairment of unproved properties.

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at June 30, 2013 and December 31, 2012 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 current 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.

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

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 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 six month period ended June 30, 2013 and the year ended December 31, 2012.

	Six months ended June 30, 2013			Year ended December 31, 2012
Beginning asset retirement obligation	$	2,366,899		$	1,835,115
Additions related to new properties	—			7,579
Additions related to existing properties	—			438,610
Retirement related to property sales	—			(1,605		)
Retirement related to property abandonment and restoration	(43,423		)	(32,388		)
Accretion expense	77,957			119,588
Ending asset retirement obligation	$	2,401,433		$	2,366,899

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at June 30, 2013 and December 31, 2012 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 consolidated statements of operations equals comprehensive income.

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Summary of Accounting Policies (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Oil and Gas Properties
Rate at which proved natural gas reserves (Mcf) are converted to equivalent barrels of crude oil (Bbl)			6
Period of the un-weighted arithmetic average of the crude oil and natural gas prices, used in computing the present value of estimated future net revenues from proved reserves			12 months
Discount rate applied to estimated future net revenues from proved oil and gas reserves (as a percent)			10.00%
Property impairment expense of proved properties	$ 0	$ 0	$ 0	$ 0
Impairment of unproved properties recognized	0	0	0	0
Estimates of Proved Oil and Gas Reserves
Period of the un-weighted arithmetic average of the commodity prices to determine reserve estimates			12 months
Partnership's asset retirement obligation
Beginning asset retirement obligation			2,366,899	1,835,115	1,835,115
Additions related to properties				6,559
Accretion expense	39,250	29,207	77,957	57,812	119,588
Ending asset retirement obligation	2,401,433		2,401,433		2,366,899
Property Sales
Partnership's asset retirement obligation
Retirements					(1,605)
Property Abandonment and Restoration
Partnership's asset retirement obligation
Retirements			(43,423)		(32,388)
Slaughter Dean Field, seven wells for which plugging operations were begun.
Partnership's asset retirement obligation
Additions related to properties					438,610
New properties
Partnership's asset retirement obligation
Additions related to properties					$ 7,579

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Aug. 14, 2013 General Partners	Aug. 14, 2013 Managing General Partner	Aug. 14, 2013 Limited Partners
Entity Registrant Name	Reef Oil & Gas Income & Development Fund III LP
Entity Central Index Key	0001411643
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		490.9827	8.9697	397.0172
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2