Attached files

file filename
EX-31.1 - EX-31.1 - Reef Oil & Gas Income & Development Fund III LPa13-19718_1ex31d1.htm
EX-31.2 - EX-31.2 - Reef Oil & Gas Income & Development Fund III LPa13-19718_1ex31d2.htm
EX-32.2 - EX-32.2 - Reef Oil & Gas Income & Development Fund III LPa13-19718_1ex32d2.htm
EX-32.1 - EX-32.1 - Reef Oil & Gas Income & Development Fund III LPa13-19718_1ex32d1.htm
EXCEL - IDEA: XBRL DOCUMENT - Reef Oil & Gas Income & Development Fund III LPFinancial_Report.xls

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 September 30, 2013

 

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
(Address of principal executive offices)

 

75080-3610
(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 November 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.

 

 

 



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

 

 

 

September 30,
2013

 

December 31,
2012

 

 

 

(unaudited)

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

565,215

 

$

495,244

 

Accounts receivable

 

 

1,986

 

Accounts receivable from affiliates

 

682,983

 

679,422

 

Deferred financing fees, net

 

10,056

 

12,299

 

Total current assets

 

1,258,254

 

1,188,951

 

 

 

 

 

 

 

Oil and gas properties, full cost method of accounting:

 

 

 

 

 

Proved properties, net of accumulated depletion of $63,534,903 and $62,728,480

 

13,600,433

 

14,023,909

 

Unproved properties

 

524,357

 

524,357

 

Net oil and gas properties

 

14,124,790

 

14,548,266

 

 

 

 

 

 

 

Deferred financing fees, net

 

6,697

 

 

 

 

 

 

 

 

Total assets

 

$

15,389,741

 

$

15,737,217

 

 

 

 

 

 

 

Liabilities and partnership equity

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

6,912

 

$

5,595

 

Current portion of long-term note payable

 

360,000

 

1,315,000

 

Total current liabilities

 

366,912

 

1,320,595

 

 

 

 

 

 

 

Long-term liabilities:

 

 

 

 

 

Note payable (Note 3)

 

590,000

 

 

Asset retirement obligation

 

2,437,672

 

2,366,899

 

Total long-term liabilities

 

3,027,672

 

2,366,899

 

 

 

 

 

 

 

Partnership equity

 

 

 

 

 

General partners

 

6,827,806

 

6,899,244

 

Limited partners

 

4,937,304

 

4,995,071

 

Managing general partner

 

230,047

 

155,408

 

Partnership equity

 

11,995,157

 

12,049,723

 

 

 

 

 

 

 

Total liabilities and partnership equity

 

$

15,389,741

 

$

15,737,217

 

 

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
September 30,

 

For the nine months ended
September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

 

Oil, gas and NGL sales

 

$

1,401,335

 

$

1,345,466

 

$

3,916,505

 

$

4,479,342

 

 

 

 

 

 

 

 

 

 

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

583,360

 

619,270

 

1,748,688

 

1,906,325

 

Production taxes

 

77,561

 

18,832

 

228,220

 

227,529

 

Depreciation, depletion and amortization

 

280,781

 

257,333

 

806,423

 

908,040

 

Accretion of asset retirement obligation

 

38,259

 

29,738

 

116,216

 

87,550

 

General and administrative

 

162,951

 

203,211

 

568,926

 

642,487

 

Total costs and expenses

 

1,142,912

 

1,128,384

 

3,468,473

 

3,771,931

 

 

 

 

 

 

 

 

 

 

 

Income from operations

 

258,423

 

217,082

 

448,032

 

707,411

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Miscellaneous income

 

14

 

 

457

 

69

 

Interest expense

 

(14,099

)

(19,656

)

(45,271

)

(62,102

)

Amortization of deferred financing fees

 

(2,809

)

(6,538

)

(12,389

)

(18,626

)

Total other income (expense)

 

(16,894

)

(26,194

)

(57,203

)

(80,659

)

 

 

 

 

 

 

 

 

 

 

Net income

 

$

241,529

 

$

190,888

 

$

390,829

 

$

626,752

 

 

 

 

 

 

 

 

 

 

 

Net income per general partner unit

 

$

210.45

 

$

162.34

 

$

300.89

 

$

525.91

 

Net income per limited partner unit

 

$

210.45

 

$

162.34

 

$

300.89

 

$

525.91

 

Net income per managing general partner unit

 

$

6,092.29

 

$

5,209.87

 

$

13,783.41

 

$

17,809.51

 

 

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 nine months ended
September 30,

 

 

 

2013

 

2012

 

 

 

 

 

 

 

Cash flows from operating activities

 

 

 

 

 

Net income

 

$

390,829

 

$

626,752

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Plugging and abandonment costs paid from ARO

 

(45,443

)

(27,362

)

Adjustments for non-cash transactions:

 

 

 

 

 

Depreciation, depletion and amortization

 

806,423

 

908,040

 

Accretion of asset retirement obligation

 

116,216

 

87,550

 

Amortization of deferred financing fees

 

12,389

 

18,626

 

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

1,986

 

 

Accounts receivable from affiliates

 

(3,561

)

(169,472

)

Accounts payable

 

1,317

 

8,531

 

Net cash provided by operating activities

 

1,280,156

 

1,452,665

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

Proceeds from sale of oil and gas properties

 

62,600

 

 

Property development

 

(445,547

)

(731,162

)

Net cash used in investing activities

 

(382,947

)

(731,162

)

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

Payment of note payable

 

(365,000

)

(270,000

)

Payment of debt issuance costs

 

(16,843

)

(812

)

Partner distributions

 

(445,395

)

(467,109

)

Net cash used in financing activities

 

(827,238

)

(737,921

)

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

69,971

 

(16,418

)

Cash and cash equivalents at beginning of period

 

495,244

 

513,410

 

Cash and cash equivalents at end of period

 

$

565,215

 

$

496,992

 

 

 

 

 

 

 

Supplemental cash flow disclosure:

 

 

 

 

 

 

 

 

 

 

 

Cash paid for interest

 

$

45,040

 

$

62,102

 

 

 

 

 

 

 

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

Property sales included in accounts receivable from affiliates

 

$

 

$

138,973

 

Additions to property and asset retirement obligation

 

$

 

$

6,559

 

 

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)

September 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 nine 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 nine month periods ended September 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 nine month periods ended September 30, 2013 and 2012, the Partnership recognized no property impairment expense of proved properties.

 

At September 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 nine month periods ended September 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 September 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.

 

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 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 nine month period ended September 30, 2013 and the year ended December 31, 2012.

 

 

 

Nine months ended
September 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

 

(45,443

)

(32,388

)

Accretion expense

 

116,216

 

119,588

 

Ending asset retirement obligation

 

$

2,437,672

 

$

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 September 30, 2013 and December 31, 2012 and is classified as Level 2 within the fair value hierarchy.

 

5



Table of Contents

 

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 September 30, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable.  The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.  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 September 30, 2013, the borrowing base, as well as the outstanding balance due under the Credit Agreement, was $950,000.  The borrowing base is currently being reduced by $30,000 per month.  The Partnership has recognized $360,000 of the outstanding note payable as a current liability as of September 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.

 

6



Table of Contents

 

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 September 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 nine month period ended September 30, 2013, RELP received $20,660 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 nine month periods ended September 30, 2013, Reef and its affiliates received total reimbursements for direct costs of $13,545 and $79,348, respectively, and other documented out-of-pocket expenses of $269 and $1,179, respectively. During the three and nine month periods ended September 30, 2012, Reef and its affiliates received total reimbursements for direct costs of $32,056 and $134,976, respectively, and other documented out-of-pocket expenses of $73 and $415, respectively.

 

RELP also receives an administrative fee to cover all general and administrative costs.  During the three and nine month periods ended September 30, 2013, RELP received administrative fees totaling $136,058 and $377,227, respectively. During the three and nine month periods ended September 30, 2012, RELP received administrative fees totaling $153,741 and $457,758, 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.

 

7



Table of Contents

 

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At September 30, 2013 and December 31, 2012, RELP owed the Partnership $682,983 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 December 31, 2012 related to the sale of certain leasehold interests.  Payment was received by the Partnership during September 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 nine month periods ended September 30, 2013 is detailed below:

 

For the three months ended September 30, 2013

 

Type of Unit

 

Number of
Units

 

Net income

 

Net income
per unit

 

Managing general partner

 

8.9697

 

$

54,646

 

$

6,092.29

 

General partner

 

490.9827

 

103,329

 

$

210.45

 

Limited partner

 

397.0172

 

83,554

 

$

210.45

 

Total

 

896.9696

 

$

241,529

 

 

 

 

For the nine months ended September 30, 2013

 

Type of Unit

 

Number of
Units

 

Net income

 

Net income
per unit

 

Managing general partner

 

8.9697

 

$

123,633

 

$

13,783.41

 

General partner

 

490.9827

 

147,735

 

$

300.89

 

Limited partner

 

397.0172

 

119,461

 

$

300.89

 

Total

 

896.9696

 

$

390,829

 

 

 

 

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;

 

8



Table of Contents

 

·                                     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



Table of Contents

 

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

 

 

 

Leasehold
Costs

 

Drilling and
Facilities Costs

 

Workovers

 

Total Costs

 

Purchase Existing Wells

 

$

35,474,208

 

 

 

35,474,208

 

 

 

 

 

 

 

 

 

 

 

New Wells

 

 

 

 

 

 

 

 

 

Producing Wells

 

34,125

 

29,921,963

 

 

29,956,088

 

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

 

$

35,508,333

 

36,866,980

 

7,076,418

 

79,451,731

 

 

The Partnership has expended approximately $57,322,450 (included in the expenditures shown in the table above) on the Slaughter Dean Project as of September 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 September 30, 2013, the Partnership had expended $79,451,731on 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 $891,342 at September 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.

 

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.

 

10



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 September 30,

 

For the nine months
ended September 30,

 

 

 

2013

 

2012

 

2013

 

2012

 

Sales volumes:

 

 

 

 

 

 

 

 

 

Oil (Barrels)

 

13,658

 

14,754

 

40,540

 

46,817

 

Natural gas (Mcf)

 

29,061

 

32,226

 

74,403

 

100,635

 

 

 

 

 

 

 

 

 

 

 

Average sales prices received:

 

 

 

 

 

 

 

 

 

Oil (Barrels)

 

$

95.02

 

$

85.82

 

$

89.43

 

$

88.15

 

Natural gas (Mcf)

 

$

3.56

 

$

2.46

 

$

3.91

 

$

3.50

 

 

The estimated net proved crude oil and natural gas reserves as of September 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 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)

 

September 30, 2013

 

736,400

 

958,530

 

September 30, 2012

 

804,530

 

981,070

 

 

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

 

The Partnership had net income of $241,529 for the three month period ended September 30, 2013, compared to net income of $190,888 for the three month period ended September 30, 2012. The primary causes of this change were increases in average sales prices and decreases in lease operating and general and administrative expenses, which were partially offset by increases in production taxes.

 

Partnership revenue increased between the comparative periods, totaling $1,401,335 for the three month period ended September 30, 2013 compared to $1,345,466 for the comparable three month period in 2012, due to increases in average sales prices.  Overall sales volumes decreased by 8.1% on an EBO basis as a result of natural declining oil and gas production from wells in which the Partnership owns an interest.   However, this decline in volumes was more than offset by the increase in the average price received for both oil and gas.  The average sales price received for crude oil increased by 10.7% to $95.02 for the three month period ended September 30, 2013 as compared to $85.82 for the three month period ended September 30, 2012, and the average sales price received for natural gas increased by 44.7% to $3.56 for the three month period ended September 30, 2013 as compared to $2.46 for the three month period ended September 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 decreased from $619,270 for the three month period ended September 30, 2012 to $583,360 for the three month period ended September 30, 2013, due primarily to lower workover expenses on the Slaughter Dean B Unit. Production tax expense totaled $77,561 for the three month period ended September 30, 2013 compared to $18,832 for the three month period ended September 30, 2012, due primarily to a refund of taxes received during the third quarter of 2012.  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 28.3% of total third quarter 2013 revenues. The tax rate reduction saved the Partnership approximately $9,000 during the third quarter of 2013.

 

11



Table of Contents

 

General and administrative costs incurred during the three month periods ended September 30, 2013 and 2012 decreased to $162,951 from $203,211. 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 $153,741 during the three month period ended September 30, 2012 to $136,058 during the three month period ended September 30, 2013. Decreased professional services fees related to processing SEC filings also contributed to the reduction in general and administrative costs.

 

Nine months ended September 30, 2013 compared to the nine months ended September 30, 2012

 

The Partnership had net income of $390,829 for the nine month period ended September 30, 2013, compared to net income of $626,752 for the nine month period ended September 30, 2012. The primary cause of this change was declines in sales volumes, which were partially offset by increases in average sales prices for crude oil and natural gas.

 

Partnership revenue decreased by 12.6% between comparative periods, totaling $3,916,505 for the nine month period ended September 30, 2013 compared to $4,479,342 for the comparable nine month period in 2012.  Sales volumes decreased by 16.7% on an EBO basis as a result of natural declining oil and gas production from wells in which the Partnership owns an interest.  The percentage decline in revenues was less than the percentage decline in volumes due to increases in average sales prices between the comparative periods. The average sales price for crude oil increased by 1.5%, to an average price of $89.43 per Bbl for the nine month period ended September 30, 2013, compared to an average price of $88.15 for the nine month period ended September 30, 2012.  The average sales price for natural gas increased by 11.7%, from an average price of $3.50 per Mcf during the nine month period ended September 30, 2012 to $3.91 during the nine month period ended September 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 $1,906,325 for the nine month period ended September 30, 2012 to $1,748,688 for the nine month period ended September 30, 2013, due primarily to lower workover expenses on the Slaughter Dean property, and lower overhead on the Azalea Acquired Properties. Production tax expense totaled $228,220 for the nine month period ended September 30, 2013 compared to $227,529 for the nine month period ended September 30, 2012. 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 30.4% of total revenues for the first nine months of 2013. The tax rate reduction saved the Partnership approximately $27,300 during the first nine months of 2013.

 

General and administrative costs incurred during the nine month periods ended September 30, 2013 and 2012 decreased to $568,926 from $642,487. 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 $457,758 during the nine month period ended September 30, 2012 to $377,277 during the nine month period ended September 30, 2013.

 

12



Table of Contents

 

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 September 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.

 

13



Table of Contents

 

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

 

14



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:   November 14, 2013

By:

/s/ Michael J. Mauceli

 

 

Michael J. Mauceli

 

 

Manager and Member

 

 

(Principal Executive Officer)

 

 

 

 

 

 

Dated:   November 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



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

 

16