Attached files

file filename
EXCEL - IDEA: XBRL DOCUMENT - Reef Oil & Gas Income & Development Fund III LPFinancial_Report.xls
EX-32.2 - EX-32.2 - Reef Oil & Gas Income & Development Fund III LPa12-13957_1ex32d2.htm
EX-31.1 - EX-31.1 - Reef Oil & Gas Income & Development Fund III LPa12-13957_1ex31d1.htm
EX-32.1 - EX-32.1 - Reef Oil & Gas Income & Development Fund III LPa12-13957_1ex32d1.htm
EX-31.2 - EX-31.2 - Reef Oil & Gas Income & Development Fund III LPa12-13957_1ex31d2.htm

Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-Q

 

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

 

For the Quarterly Period Ended June 30, 2012

 

or

 

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

 

For the Transition Period from                  to                

 

Commission File Number: 000-53795

 


 

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

(Exact name of registrant as specified in its charter)

 

Texas

(State or other jurisdiction of

incorporation or organization)

 

26-0805120

(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, 2012, 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.

 

 

 



Table of Contents

 

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

 

 

i



Table of Contents

 

PART I - FINANCIAL INFORMATION

 

Item 1. Financial Statements

 

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

Condensed Balance Sheets

 

 

 

June 30,
2012

 

December 31,
2011

 

 

 

(unaudited)

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

474,190

 

$

513,410

 

Accounts receivable

 

1,800

 

1,800

 

Accounts receivable from affiliates

 

714,076

 

598,599

 

Deferred financing fees, net

 

24,175

 

 

Total current assets

 

1,214,241

 

1,113,809

 

 

 

 

 

 

 

Oil and gas properties, full cost method of accounting:

 

 

 

 

 

Proved properties, net of accumulated depletion of $62,869,669 and $62,218,962

 

12,632,679

 

12,664,259

 

Unproved properties

 

1,696,463

 

1,708,425

 

Net oil and gas properties

 

14,329,142

 

14,372,684

 

 

 

 

 

 

 

Deferred financing fees, net

 

 

36,263

 

 

 

 

 

 

 

Total assets

 

$

15,543,383

 

$

15,522,756

 

 

 

 

 

 

 

Liabilities and partnership equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

4,343

 

$

3,597

 

Current portion of long-term note payable

 

1,585,000

 

360,000

 

Total current liabilities

 

1,589,343

 

363,597

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Note payable (Note 3)

 

 

1,405,000

 

Asset retirement obligation

 

1,899,486

 

1,835,115

 

Total long-term liabilities

 

1,899,486

 

3,240,115

 

 

 

 

 

 

 

Partnership equity

 

 

 

 

 

General partners

 

6,933,236

 

6,902,531

 

Limited partners

 

5,022,557

 

4,997,729

 

Managing general partner

 

98,761

 

18,784

 

Partnership equity

 

12,054,554

 

11,919,044

 

 

 

 

 

 

 

Total liabilities and partnership equity

 

$

15,543,383

 

$

15,522,756

 

 

See accompanying notes to condensed financial statements (unaudited).

 

1



Table of Contents

 

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,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Oil, gas and NGL sales

 

$

1,488,651

 

$

1,546,637

 

$

3,133,876

 

$

2,927,680

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

616,352

 

538,058

 

1,287,055

 

1,200,087

 

Production taxes

 

106,208

 

89,717

 

208,697

 

193,593

 

Depreciation, depletion and amortization

 

308,137

 

282,654

 

650,707

 

599,977

 

Accretion of asset retirement obligation

 

29,207

 

6,626

 

57,812

 

21,815

 

General and administrative

 

221,048

 

377,607

 

439,276

 

802,238

 

Total costs and expenses

 

1,280,952

 

1,294,662

 

2,643,547

 

2,817,710

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

207,699

 

251,975

 

490,329

 

109,970

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Miscellaneous income

 

 

30

 

69

 

45

 

Interest expense

 

(20,795

)

(53,518

)

(42,446

)

(112,687

)

Amortization of deferred financing fees

 

(6,044

)

(1,740

)

(12,088

)

(1,740

)

Total other income (expense)

 

(26,839

)

(55,228

)

(54,465

)

(114,382

)

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

180,860

 

$

196,747

 

$

435,864

 

$

(4,412

)

 

 

 

 

 

 

 

 

 

 

Net income (loss) per general partner unit

 

$

146.57

 

$

165.36

 

$

363.57

 

$

(60.75

)

Net income (loss) per limited partner unit

 

$

146.57

 

$

165.36

 

$

363.57

 

$

(60.75

)

Net income per managing general partner unit

 

$

5,653.25

 

$

5,564.02

 

$

12,599.64

 

$

5,522.86

 

 

See accompanying notes to condensed financial statements (unaudited).

 

2



Table of Contents

 

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

Condensed Statements of Cash Flows

(Unaudited)

 

 

 

For the six months ended
June 30,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income (loss)

 

$

435,864

 

$

(4,412

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Adjustments for non-cash transactions:

 

 

 

 

 

Depreciation, depletion and amortization

 

650,707

 

599,977

 

Accretion of asset retirement obligation

 

57,812

 

21,815

 

Amortization of deferred financing fees

 

12,088

 

1,740

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

 

144,340

 

Accounts receivable from affiliates

 

(115,477

)

(38,607

)

Accounts payable

 

746

 

2,852

 

Accounts payable to affiliates

 

 

18,830

 

Accrued liabilities

 

 

(9,819

)

Net cash provided by operating activities

 

1,041,740

 

736,716

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Proceeds from sale of oil and gas properties

 

 

3,059,455

 

Property development

 

(600,606

)

(597,503

)

Net cash provided by (used in) investing activities

 

(600,606

)

2,461,952

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Payment of note payable

 

(180,000

)

(2,805,000

)

Payment of deferred financing fees

 

 

(43,500

)

Partner distributions

 

(300,354

)

(597,848

)

Net cash used in financing activities

 

(480,354

)

(3,446,348

)

 

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(39,220

)

(247,680

)

Cash and cash equivalents at beginning of period

 

513,410

 

1,136,682

 

Cash and cash equivalents at end of period

 

$

474,190

 

$

889,002

 

 

 

 

 

 

 

Supplemental cash flow disclosure:

 

 

 

 

 

 

 

 

 

 

 

Cash paid for interest expense on note payable

 

$

42,447

 

$

112,687

 

 

 

 

 

 

 

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

 

 

 

 

 

 

Additions to property and asset retirement obligation

 

$

6,559

 

$

2,303

 

 

See accompanying notes to condensed financial statements (unaudited).

 

3



Table of Contents

 

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

Notes to Condensed Financial Statements (unaudited)

 

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 2012. 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, 2011 (the “Annual Report”). The results of operations for the three and six month periods ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.

 

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. No gain or loss is recognized upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and six month periods ended June 30, 2012 and 2011, the Partnership recognized no property impairment expense of proved properties.

 

At June 30, 2012 and December 31, 2011, 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”). Unproved properties are assessed for impairment at least annually as of the balance sheet date by considering drilling activity in the area of the unproved properties and other information.  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, 2012 and 2011, 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, 2012 and December 31, 2011 are prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and 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.

 

4



Table of Contents

 

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.  Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.

 

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

 

During the quarter ended September 30, 2011, the Partnership began plugging operations on seven wells located in the Slaughter Dean Field. Approximately $14,342 of plugging and abandonment costs were applied against the Partnership’s asset retirement obligation shown on the accompanying balance sheet, and the remaining amount of approximately $62,000 was recorded as current cost and is classified as lease operating expenses on the Partnership’s statement of operations. As a result of these plugging and abandonment operations, the Partnership revised its estimated liability during the quarter for the Slaughter Dean Field (approximately 145 wells) by increasing the basis of the Slaughter Dean wells by $860,878 and recording additional asset retirement obligation of this amount as a change in estimate.

 

The following table summarizes the Partnership’s asset retirement obligation for the six month period ended June 30, 2012 and the year ended December 31, 2011.

 

 

 

Six months ended
June 30, 2012

 

Year ended
December 31, 2011

 

Beginning asset retirement obligation

 

$

1,835,115

 

$

903,946

 

Additions related to new properties

 

6,559

 

13,008

 

Additions related to existing properties

 

 

860,878

 

Retirement related to property sales

 

 

(5,517

)

Retirement related to property abandonment and restoration

 

 

(15,230

)

Accretion expense

 

57,812

 

78,030

 

Ending asset retirement obligation

 

$

1,899,486

 

$

1,835,115

 

 

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

 

5



Table of Contents

 

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, 2012 and December 31, 2011 and is classified as Level 2 within the fair value hierarchy.

 

Reclassifications

 

Certain information provided for prior years has been reclassified to conform to the current year presentation adopted as of March 31, 2012.

 

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, 2012, the interest rate was 5.00%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2013, 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 a facility fee of $50,000 (one percent (1.00%) of the initial borrowing base) and is obligated to further pay, upon each determination of an increase in the borrowing base, a facility fee in the amount of one percent (1.00%) of the amount by which the borrowing base is increased over that in effect on the date of determination.  On June 30, 2010, the Partnership also paid TCB an engineering fee in the amount of $5,000, and is obligated to further pay additional engineering fees in the amount of $5,000 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 May 20, 2011, the Partnership entered into the First Amendment to Credit Agreement (“Amendment”) with TCB. Under the Amendment, the borrowing base was reduced to the Partnership’s outstanding balance of $4,100,000 effective May 20, 2011.  In addition, effective June 1, 2011, the borrowing base is reduced by $55,000 per month.  On May 24, 2011, the Partnership paid TCB fees of $43,500 in connection with the Amendment.  These fees have been capitalized as other non-current assets on the accompanying condensed balance sheet and will be amortized over the term of the credit agreement.

 

During July 2011, the Partnership and TCB executed the Second Amendment to Credit Agreement (“Second Amendment”), which is effective as of June 30, 2011. Under the Second Amendment, the borrowing base was reduced to $1,945,000 as of June 30, 2011 and the Partnership made a principal payment of $2,100,000 to reduce the loan balance to this amount.  In addition, effective August 1, 2011, the borrowing base is reduced by $30,000 per month.  During July 2011, the Partnership paid TCB fees of $6,316 in connection with the Second Amendment.  These fees have been capitalized as other non-current assets on the accompanying balance sheet and will be amortized over the term of the credit agreement.  At June 30, 2012, the borrowing base and outstanding balance due TCB was equal to $1,585,000.  The Partnership has recognized the entire $1,585,000 as a current liability as of June

 

6



Table of Contents

 

30, 2012 due to the June 30, 2013 expiration of the Credit Agreement.  There is no additional availability under the borrowing base as of June 30, 2012.

 

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, 2012, 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, 2012 has been obtained.

 

4. Transactions with Affiliates

 

Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, 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 also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion.  Total well costs do not include costs relating to lease acquisitions.  During the six month period ended June 30, 2012, RELP received $28,035 in drilling compensation. During the year ended December 31, 2011, RELP received $54,005 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, 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. During the three and six month periods ended June 30, 2011, Reef and its affiliates received total reimbursements for direct costs of $90,489 and $202,078, respectively, and other documented out-of-pocket expenses of $414 and $729, respectively.

 

Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12 th of 1% of all capital raised payable monthly, totaling $74,740 per month.  During the first

 

7



Table of Contents

 

quarter of 2012, Reef reduced the amount of the monthly administrative fee from the calculated amount above to the amount calculated through the standard RELP overhead allocation.  The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the three and six month periods ended June 30, 2012, RELP received administrative fees totaling $147,495 and $304,017, respectively. During the three and six month periods ended June 30, 2011, RELP received administrative fees totaling $224,220 and $448,440, 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, 2012 and December 31, 2011, RELP owed the Partnership $714,076 and $598,599, 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.

 

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

 

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, 2012 is detailed below:

 

For the three months ended June 30, 2012

 

Type of Unit

 

Number of
Units

 

Net income

 

Net income
per unit

 

Managing general partner

 

8.9697

 

$

50,708

 

$

5,653.25

 

General partner

 

490.9827

 

71,962

 

$

146.57

 

Limited partner

 

397.0172

 

58,190

 

$

146.57

 

Total

 

896.9696

 

$

180,860

 

 

 

 

For the six months ended June 30, 2012

 

Type of Unit

 

Number of
Units

 

Net income

 

Net income
per unit

 

Managing general partner

 

8.9697

 

$

113,015

 

$

12,599.64

 

General partner

 

490.9827

 

178,506

 

$

363.57

 

Limited partner

 

397.0172

 

144,343

 

$

363.57

 

Total

 

896.9696

 

$

435,864

 

 

 

 

8



Table of Contents

 

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.

 

The Partnership utilized its capital to acquire oil and gas properties in three separate purchase transactions, and for a major waterflood development program. In January 2008, the Partnership purchased an initial 41% working interest in over 100 wells located in the Slaughter Dean Field in Cochran County, Texas, approximately 50 miles southwest of Lubbock, Texas. Under the terms of the acquisition agreement, as described in the Partnership’s Annual Report, each month thereafter additional working interests are purchased based on the amount the Partnership spends developing the field through January 2013. In a separate transaction in May 2008, the Partnership purchased an additional 11% working interest in the Slaughter Dean Field.

 

9



Table of Contents

 

During 2010, the Partnership acquired from RCWI, L.P. (“RCWI”), an affiliate of Reef, 61% of the working interests acquired by RCWI in certain oil and gas properties from Azalea Properties Ltd (“Azalea Acquired Properties”). RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea Acquired Properties cover more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and include undrilled infill and offset locations.  The Partnership acquired minority working interests in each of these properties, which are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef.

 

In addition, during 2010 the Partnership acquired from RCWI all of the working interests acquired by RCWI in the Lett Acquired Properties.  The Lett Acquired Properties are located in the Thums Long Beach Unit and include approximately 870 producing wells and 485 injection wells.  The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California.  The acquired working interests are all minority non-operated working interests. The Thums Long Beach Unit is operated by a third party operator not affiliated with the Partnership or Reef.

 

On all properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but does not expect to engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations.  Drilling locations for unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef. During 2010 the Partnership, in two separate transactions, sold its interests in certain of the Azalea Acquired Properties to Reef 2010 Drilling Fund L.P., an affiliate, due to the planned drilling of exploratory wells. The Partnership sales included interests in fourteen existing productive wells, as well as the undeveloped acreage upon which the exploratory wells were to be drilled. The Partnership received a total of $992,755 in connection with these sales. The Partnership recorded no gain or loss associated with these transactions.

 

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

 

The table below summarizes Partnership expenditures for property purchases, development, and waterflood enhancement by type and classification of well as of June 30, 2012.

 

 

 

Leasehold
Costs

 

Drilling and
Facilities Costs

 

Workovers

 

Total Costs

 

Purchase Existing Wells

 

$

32,378,704

 

$

 

$

 

$

32,378,704

 

 

 

 

 

 

 

 

 

 

 

New Wells

 

 

 

 

 

 

 

 

 

Producing Wells

 

33,823

 

29,078,781

 

 

29,112,604

 

Waterflood Injector Wells

 

 

5,149,620

 

 

5,149,620

 

Facilities

 

 

1,795,397

 

 

1,795,397

 

 

 

 

 

 

 

 

 

 

 

Existing Wells

 

 

 

7,076,447

 

7,076,447

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

32,412,527

 

$

36,023,798

 

$

7,076,447

 

$

75,512,772

 

 

The Partnership has expended approximately $57,269,734 (included in the expenditures shown in the table above) on the Slaughter Dean Project as of June 30, 2012.  During the period from 2008 through 2010, the Partnership implemented a waterflood enhancement project on a portion of the Slaughter Dean Field. Well spacing was reduced from 40 to 20 acres per well.  The Partnership drilled 30 new producing wells and 5 new water injection wells, and

 

10



Table of Contents

 

performed workover operations on several old producing wells. In addition, 22 existing wells were converted to water injection wells and a new water injection pump was installed in order to increase the amount of water being injected back into the producing formation. Although the Slaughter Dean Field experienced periodic small increases in production during 2010, the waterflood enhancement project has not led to increased crude oil production as planned. Based upon observed results during 2010, the Partnership concluded during the fourth quarter of 2010 that although significant crude oil reserves may remain in the reservoir, the project work was deemed unlikely to be effective in materially increasing the recovery of those reserves. Therefore, 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.

 

Critical Accounting Policies

 

There have been no changes from the Critical Accounting Policies described in the Annual Report.

 

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, 2012, the Partnership had expended $78,512,772 on property acquisition and development costs, prior to the Partnership’s sale of a portion of its interests in the Thums Long Beach Unit during 2011. Expenditures in excess of available capital have been financed through debt or recovered from cash flows by reducing Partnership distributions.

 

The Partnership had negative working capital of $375,102 at June 30, 2012, primarily as a result of the reclassification of the Partnership’s note payable balance as a current liability as of June 30, 2012 due to the expiration of the Partnership’s credit agreement on June 30, 2013. The Partnership is currently evaluating its options to meet its obligations under its credit agreement, including  the sale of producing properties or an extension of its credit agreement.

 

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.

 

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.

 

11



Table of Contents

 

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,

 

 

 

2012

 

2011

 

2012

 

2011

 

Sales volumes:

 

 

 

 

 

 

 

 

 

Oil (Barrels)

 

16,175

 

16,836

 

32,063

 

32,380

 

Natural gas (Mcf)

 

23,923

 

36,648

 

68,409

 

77,717

 

 

 

 

 

 

 

 

 

 

 

Average sales prices received:

 

 

 

 

 

 

 

 

 

Oil (Barrels)

 

$

84.77

 

$

82.84

 

$

89.23

 

$

78.32

 

Natural gas (Mcf)

 

$

4.91

 

$

4.15

 

$

3.99

 

$

5.04

 

 

The estimated net proved crude oil and natural gas reserves as of June 30, 2012 and 2011 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, 2012

 

665,180

 

968,340

 

June 30, 2011

 

749,366

 

1,179,527

 

 

Three months ended June 30, 2012 compared to the three months ended June 30, 2011

 

The Partnership had net income of $180,860 for the three month period ended June 30, 2012, compared to net income of $196,747 for the three month period ended June 30, 2011. The primary causes of this change were decreased sales volumes and revenues, as well as increases in various operating expenses.

 

Partnership revenues totaled $1,488,651 for the three month period ended June 30, 2012 compared to $1,546,637 for the comparable period in 2011.  The decrease in sales revenues between the periods ended June 30, 2012 and 2011 was caused primarily by the decrease in sales volumes.  Overall, oil and gas sales volumes decreased during the three month period ended June 30, 2012 compared to the three month period ended June 30, 2011 by approximately 3.9% and 34.7%, respectively, due primarily to decreased production from new and existing wells on the Azalea Acquired Properties.  The sales price for crude oil rose by 2.3%, to an average price of $84.77  per Bbl for the three month period ended June 30, 2012, compared to an average price of $82.84 for the three month period ended June 30, 2011.  The sales price for natural gas rose by 18.3% from an average price of $4.15 per Mcf during the three month period ended June 30, 2011 to $4.91 during the three month period ended June 30, 2012.  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 increased from $538,058 for the three month period ended June 30, 2011 to $616,352 for the three month period ended June 30, 2012.  Operating expenses increased on the Azalea Acquired Properties during the comparative periods, as did repairs and maintenance and overhead costs on the Slaughter Dean Field.  These increases were partially offset by decreased ad valorem taxes on all properties and lower labor and utilities charges related to the Lett Acquired Properties during the comparative periods.

 

12



Table of Contents

 

Depreciation, depletion and amortization increased from $282,654 for the three month period ended June 30, 2011 to $308,137 for the three month period ended June 30, 2012. Although decreasing production rates led to a lower depletion rate, the Partnership’s depletable property basis increased over the comparable periods.

 

General and administrative costs incurred during the three month periods ended June 30, 2012 and 2011 decreased from $377,607 in 2011 to $221,048 in 2012. This decline is due to decreased salaries and wages for field personnel in the Slaughter Dean Field, decreased professional fees related to SEC filings and reserve reports, and decreased administrative fees charged by RELP.  During the three month period ended June 30, 2011, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th of 1% of all capital raised payable monthly, which totaled $74,740 per month.  During the three month period ended June 30, 2012, Reef  reduced the amount of the monthly administrative fee from the calculated amount above to the amount calculated through the standard RELP overhead allocation.  The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the three month periods ended June 30, 2012 and 2011, RELP received $147,495 and $224,220 of administrative fees from the Partnership, respectively.

 

Total other income and expense for the three month periods ended June 30, 2012 and 2011 decreased from expense of $55,228 in 2011 to expense of $26,839 in 2012.  Interest expense decreased during the comparable periods due to the Partnership’s payment of principal on its note payable.

 

Six months ended June 30, 2012 compared to the six months ended June 30, 2011

 

The Partnership had net income of $435,864 for the six month period ended June 30, 2012, compared to a net loss of $4,412 for the six month period ended June 30, 2011. The primary causes of this change were increased sales revenues, as well as reductions in general and administrative costs.

 

Partnership revenues totaled $3,133,876 for the six month period ended June 30, 2012 compared to $2,927,680 for the comparable period in 2011, due primarily to increased oil sales prices.  Overall, oil and gas sales volumes decreased during the six month period ended June 30, 2012 compared to the six month period ended June 30, 2011 by approximately 1.0% and 12.0%, respectively, due primarily to decreased production from new and existing wells on the Azalea Acquired Properties, as well as the Lett Acquired Properties.  However, the sales price for crude oil rose by 13.9%, to an average price of $89.23  per Bbl for the six month period ended June 30, 2012, compared to an average price of $78.32 for the six month period ended June 30, 2011.  While the sales price for natural gas declined by 20.8% from an average price of $5.04 per Mcf during the six month period ended June 30, 2011 to $3.99 during the six month period ended June 30, 2012, gas only represented approximately  8.7% of total sales revenues of the Partnership for the period ended June 30, 2012, compared to 13.4% of total sales revenues for the period ended June 30, 2011.  The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes.  The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.

 

Lease operating expenses increased from $1,200,087 for the six month period ended June 30, 2011 to $1,287,055 for the six month period ended June 30, 2012.  Operating expenses increased on the Lett Acquired Properties during the comparative periods, as did repairs and maintenance expenses and overhead costs on the Slaughter Dean Field.  These increases were partially offset by decreased overhead charges related to the Azalea Acquired Properties during the comparative periods.

 

Depreciation, depletion and amortization increased from $599,977 for the six month period ended June 30, 2011 to $650,707 for the six month period ended June 30, 2012. Although decreasing production rates led to a lower depletion rate, the Partnership’s depletable property basis increased over the comparable periods.

 

General and administrative costs incurred during the six month periods ended June 30, 2012 and 2011 decreased from $802,238 in 2011 to $439,276 in 2012. This decline is due to decreased salaries and wages for field personnel

 

13



Table of Contents

 

in the Slaughter Dean Field, decreased professional fees related to SEC filings and reserve reports, decreased direct costs, and decreased administrative fees charged by RELP.  Salaries and wages of administrative Slaughter Dean Field personnel declined by approximately $73,000 for the six month period ended June 30, 2012, due to a permanent reduction in personnel. In addition, direct general and administrative costs charged to the Partnership declined by approximately $132,500 for the first six months of 2012. During the six month period ended June 30, 2011, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th of 1% of all capital raised payable monthly, which totaled $74,740 per month.  During the six month period ended June 30, 2012, Reef reduced the amount of the monthly administrative fee from the calculated amount above to the amount calculated through the standard RELP overhead allocation.  The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the six month periods ended June 30, 2012 and 2011, RELP received $304,017 and $448,440 of administrative fees from the Partnership, respectively.

 

Total other income and expense for the six month periods ended June 30, 2012 and 2011 decreased from expense of $114,382 in 2011 to expense of $54,465 in 2012.  Interest expense decreased during the comparable periods due to the Partnership’s payment of principal on its note payable.

 

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, 2012 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.

 

14



Table of Contents

 

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.

 

Item 6.  Exhibits

 

Exhibits

 

 

 

 

 

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

 

15



Table of Contents

 

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, 2012

By:

/s/ Michael J. Mauceli

 

 

 

Michael J. Mauceli

 

 

 

Manager and Member

 

 

 

(Principal Executive Officer)

 

 

 

 

 

 

 

 

Dated:

August 14, 2012

By:

/s/ Daniel C. Sibley

 

 

 

Daniel C. Sibley

 

 

 

Chief Financial Officer and General Counsel of

 

 

 

Reef Exploration, L.P.

 

 

 

(Principal Financial and Accounting Officer)

 



Table of Contents

 

EXHIBIT INDEX

 

Exhibits

 

 

 

 

 

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