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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

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

For the quarterly period ended June 30, 2014

OR

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 001-33147

 

Constellation Energy Partners LLC

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

 

 

Delaware

11-3742489

(State of

organization)

(I.R.S. Employer

Identification No.)

 

 

1801 Main Street, Suite 1300

Houston, Texas

77002

(Address of Principal Executive Offices)

(Zip Code)

Telephone Number: (832) 308-3700

 

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      No   

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 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      No   

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

Accelerated filer

 

 

 

 

Non-accelerated filer

  (Do not check if a smaller reporting company)

Smaller reporting company

 

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Units outstanding on August 11, 2014:  28,734,396 units.

 

 

 

 


 

 

 

TABLE OF CONTENTS

 

 

 

 

 

 

  Page  

PART I—Financial Information 

3

Item 1.

Financial Statements

3

 

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

3

 

Condensed Consolidated Balance Sheets

4

 

Condensed Consolidated Statements of Cash Flows

5

 

Condensed Consolidated Statements of Changes in Members’ Equity

6

 

Notes to Condensed Consolidated Financial Statements

7

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

24

 

Results of Operations

26

 

Liquidity and Capital Resources

30

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

33

Item 4.

Controls and Procedures

33

PART II—Other Information  

33

Item 1.

Legal Proceedings

33

Item1A.

Risk Factors

34

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

35

Item 3.

Defaults Upon Senior Securities

35

Item 4.

Mine Safety Disclosures

35

Item 5.

Other Information

35

Item 6.

Exhibits

36

Signatures  

38

 

 

2

 


 

 

PART I—FINANCIAL INFORMATION 

Item 1. Financial Statements

 

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(In thousands, except per unit data)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

Revenues

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

6,575 

 

$

10,025 

 

$

12,599 

 

$

11,417 

Oil and liquids sales

 

5,514 

 

 

5,363 

 

 

11,231 

 

 

9,071 

Total revenues (See Note 5)

 

12,089 

 

 

15,388 

 

 

23,830 

 

 

20,488 

Expenses:

 

 

 

 

 

 

 

 

 

 

 

Operating expenses: 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

5,182 

 

 

3,905 

 

 

10,302 

 

 

8,141 

Cost of sales

 

434 

 

 

379 

 

 

794 

 

 

799 

Production taxes

 

995 

 

 

622 

 

 

1,767 

 

 

1,109 

General and administrative

 

5,591 

 

 

3,737 

 

 

9,162 

 

 

8,141 

Gain on sale of assets

 

(16)

 

 

(17)

 

 

(23)

 

 

(23)

Depreciation, depletion and amortization

 

4,320 

 

 

4,767 

 

 

8,370 

 

 

9,565 

Asset impairments

 

45 

 

 

 -

 

 

194 

 

 

 -

Accretion expense

 

150 

 

 

123 

 

 

300 

 

 

246 

Total operating expenses 

 

16,701 

 

 

13,516 

 

 

30,866 

 

 

27,978 

Other expenses (income) 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

533 

 

 

864 

 

 

1,058 

 

 

2,216 

Other income

 

(134)

 

 

(104)

 

 

(144)

 

 

(172)

Total other expenses 

 

399 

 

 

760 

 

 

914 

 

 

2,044 

Total expenses 

 

17,100 

 

 

14,276 

 

 

31,780 

 

 

30,022 

Income (loss) from continuing operations 

 

(5,011)

 

 

1,112 

 

 

(7,950)

 

 

(9,534)

Loss from discontinued operations

 

 -

 

 

 -

 

 

 -

 

 

(2,686)

Net income (loss)

$

(5,011)

 

$

1,112 

 

$

(7,950)

 

$

(12,220)

Earnings (loss) per unit (See Note 2)

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) from continuing operations per unit

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

$

(0.21)

 

$

0.05 

 

$

(0.15)

 

$

(0.39)

Class B units - Basic and diluted

$

(0.17)

 

$

0.05 

 

$

(0.28)

 

$

(0.40)

Loss from discontinued operations per unit

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

$

 -

 

$

 -

 

$

 -

 

$

(0.11)

Class B units - Basic and diluted

$

 -

 

$

 -

 

$

 -

 

$

(0.11)

Net earnings (loss) per unit

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

$

(0.21)

 

$

0.05 

 

$

(0.15)

 

$

(0.50)

Class B units - Basic and diluted

$

(0.17)

 

$

0.05 

 

$

(0.28)

 

$

(0.51)

Weighted Average Units Outstanding

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic

 

484,505 

 

 

484,370 

 

 

1,046,638 

 

 

484,383 

Class B units -  Basic

 

28,305,380 

 

 

23,345,280 

 

 

28,259,994 

 

 

23,306,269 

Class A units - Diluted

 

484,505 

 

 

484,370 

 

 

1,046,638 

 

 

484,383 

Class B units -  Diluted

 

28,305,380 

 

 

23,720,732 

 

 

28,259,994 

 

 

23,306,269 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions declared and paid per unit

$

 -

 

$

 -

 

$

 -

 

$

 -

See accompanying notes to condensed consolidated financial statements.

 

 

3

 


 

 

 

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Condensed Consolidated Balance Sheets 

(In thousands, except unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30, 2014

 

December 31, 2013

 

(Unaudited)

 

 

 

ASSETS

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

$

4,437 

 

$

4,894 

Restricted cash (See Note 2)

 

1,748 

 

 

 -

Accounts receivable, net (See Note 2)

 

10,056 

 

 

6,678 

Prepaid expenses

 

1,275 

 

 

2,547 

Risk management assets (See Note 5)

 

4,041 

 

 

9,141 

Total current assets

 

21,557 

 

 

23,260 

Oil and natural gas properties (See Note 6)

 

 

 

 

 

Oil and natural gas properties, equipment and facilities

 

643,678 

 

 

639,156 

Material and supplies

 

1,057 

 

 

1,054 

Less accumulated depreciation, depletion, amortization, and impairments

 

(503,436)

 

 

(495,215)

Net oil and natural gas properties

 

141,299 

 

 

144,995 

Other assets

 

 

 

 

 

Debt issue costs (net of accumulated amortization of $9,012 and $9,003, respectively)

 

833 

 

 

824 

Risk management assets (See Note 5)

 

131 

 

 

1,461 

Restricted cash (See Note 2)

 

 -

 

 

1,748 

Other non-current assets

 

1,987 

 

 

2,245 

Total assets

$

165,807 

 

$

174,533 

LIABILITIES AND MEMBERS’ EQUITY

 

 

 

 

 

Liabilities

 

 

 

 

 

Current liabilities 

 

 

 

 

 

Accounts payable

$

627 

 

$

12 

Accrued liabilities

 

8,031 

 

 

12,763 

Royalty payable

 

1,338 

 

 

1,242 

Risk management liabilities (see Note 5)

 

2,641 

 

 

 -

Total current liabilities 

 

12,637 

 

 

14,017 

Other liabilities 

 

 

 

 

 

Asset retirement obligation

 

9,919 

 

 

9,513 

Risk management liabilities (see Note 5)

 

1,841 

 

 

 -

Other non-current liabilities

 

 -

 

 

1,398 

Debt (See Note 7)

 

51,950 

 

 

50,700 

Total other liabilities 

 

63,710 

 

 

61,611 

Total liabilities

 

76,347 

 

 

75,628 

Commitments and contingencies (See Note 9)

 

 

 

 

 

Members’ equity

 

 

 

 

 

Class A units, 484,505 and 1,615,017 units authorized, issued and outstanding, respectively

 

1,581 

 

 

2,591 

Class B units, 28,848,785 and 28,848,785 units authorized, respectively, and 28,833,202 and 28,462,185 issued and outstanding, respectively

 

87,879 

 

 

96,314 

Total members’ equity

 

89,460 

 

 

98,905 

Total liabilities and members’ equity

$

165,807 

 

$

174,533 

See accompanying notes to condensed consolidated financial statements.

 

 

4

 


 

 

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows 

(In thousands)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six months ended

 

June 30,

 

2014

 

2013

Cash flows from operating activities:

 

 

 

 

 

Net loss

$

(7,950)

 

$

(12,220)

Adjustments to reconcile net loss to cash provided by operating activities

 

 

 

 

 

Depreciation, depletion and amortization

 

8,370 

 

 

9,565 

Asset impairments (See Note 6)

 

194 

 

 

 -

Amortization of debt issuance costs

 

127 

 

 

1,178 

Accretion expense

 

300 

 

 

246 

Equity earnings in affiliate

 

(70)

 

 

(172)

Gain from disposition of property and equipment

 

(23)

 

 

(23)

Bad debt expense

 

112 

 

 

15 

Mark-to-market on derivatives:

 

 

 

 

 

    Total (gains) losses

 

8,805 

 

 

(776)

    Cash settlements

 

2,107 

 

 

4,066 

Unit-based compensation programs

 

1,130 

 

 

609 

Discontinued operations

 

 -

 

 

2,686 

Changes in Assets and Liabilities: 

 

 

 

 

 

(Increase) decrease in accounts receivable

 

(3,489)

 

 

1,160 

(Increase) decrease in prepaid expenses

 

1,272 

 

 

(77)

(Increase) decrease in other assets

 

 

 

(1,149)

Increase in accounts payable

 

615 

 

 

101 

Decrease in accrued liabilities

 

(4,174)

 

 

(1,391)

Increase (decrease) in royalty payable

 

96 

 

 

(45)

Increase (decrease) in other liabilities

 

(1,398)

 

 

1,139 

Net cash provided by continuing operations

 

6,026 

 

 

4,912 

Net cash provided by discontinued operations

 

 -

 

 

1,062 

Net cash provided by operating activities

 

6,026 

 

 

5,974 

Cash flows from investing activities:

 

 

 

 

 

Cash paid for acquisitions, net of cash acquired

 

(1,351)

 

 

(130)

Development of oil and natural gas properties

 

(3,819)

 

 

(6,319)

Proceeds from sale of assets

 

58 

 

 

58,987 

Distributions from equity affiliate

 

140 

 

 

95 

Net cash provided by (used in) continuing operations

 

(4,972)

 

 

52,633 

Net cash used in discontinued operations

 

 -

 

 

 -

Net cash provided by (used in) investing activities

 

(4,972)

 

 

52,633 

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuance of debt

 

5,750 

 

 

194 

Repayment of debt

 

(4,500)

 

 

(50,194)

Repurchase of Class A, Class C and Class D interests

 

(2,468)

 

 

 -

Units tendered by employees for tax withholdings

 

(157)

 

 

(185)

Debt issue costs

 

(136)

 

 

(840)

Net cash used in continuing operations

 

(1,511)

 

 

(51,025)

Net cash used in discontinued operations

 

 -

 

 

 -

Net cash used in financing activities

 

(1,511)

 

 

(51,025)

Net increase (decrease) in cash and cash equivalents

 

(457)

 

 

7,582 

Cash and cash equivalents, beginning of period

 

4,894 

 

 

1,959 

Cash and cash equivalents, end of period

$

4,437 

 

$

9,541 

Supplemental disclosures of cash flow information:

 

 

 

 

 

Change in accrued capital expenditures

$

(542)

 

$

(351)

Cash paid during the period for interest

$

(950)

 

$

(1,012)

See accompanying notes to condensed consolidated financial statements.

 

5

 


 

 

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Condensed Consolidated Statements of Changes in Members’ Equity 

(In thousands, except unit data)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

Total

 

Class A

 

Class B

 

Comprehensive

 

Members’

 

Units

 

Amount

 

Units

 

Amount

 

Income (Loss)

 

Equity

Balance, December 31, 2013

1,615,017 

 

$

2,591 

 

28,462,185 

 

$

96,314 

 

$

 -

 

$

98,905 

Distributions

 -

 

 

 -

 

 -

 

 

 -

 

 

 -

 

 

 -

Units tendered by employees for tax withholding

 -

 

 

 -

 

(62,683)

 

 

(157)

 

 

 -

 

 

(157)

Unit-based compensation programs

 -

 

 

 -

 

433,700 

 

 

1,130 

 

 

 -

 

 

1,130 

Cancellation of units (See Note 9)

(1,130,512)

 

 

(851)

 

 -

 

 

(1,617)

 

 

 -

 

 

(2,468)

Net loss

 -

 

 

(159)

 

 -

 

 

(7,791)

 

 

 -

 

 

(7,950)

Balance, June 30, 2014

484,505 

 

$

1,581 

 

28,833,202 

 

$

87,879 

 

$

 -

 

$

89,460 

See accompanying notes to condensed consolidated financial statements.

 

6

 


 

 

CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Constellation Energy Partners LLC (CEP, we, us, our or the Company) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the symbol “CEP”.  We are currently focused on the acquisition, development and production of oil and natural gas properties, as well as midstream assets.  Our proved reserves are located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas and in Texas and Louisiana.

Through subsidiaries, Sanchez Oil & Gas Corporation (SOG) and PostRock Energy Corporation (NASDAQ: PSTR) (PostRock) own a portion of our outstanding units.  As of June 30, 2014, Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned 484,505, or 100%, of our Class A units and 5,139,345, or 17.8%, of our Class B common units.  As of June 30, 2014, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 4,282,500, or 14.9%, of our Class B common units.

On June 26, 2014, we settled the lawsuit brought by Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon Corporation, against us in the Court of Chancery of the State of Delaware (the Exelon Litigation).  In conjunction with the settlement, we paid CEPH $1.65 million in exchange for all of the Class C management incentive interests and Class D interests held by CEPH, which were all of such interests issued by CEP.  Effective with the acquisition of these interests from CEPH, we cancelled the Class C management incentive interests and Class D interests.

On May 8, 2014, the Company and SP Holdings, LLC (the Manager), an affiliate of SOG, entered into a Shared Services Agreement (the Services Agreement) pursuant to which, as of July 1, 2014, the Manager provides services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services.

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of CEP and our wholly-owned subsidiaries.  All significant intercompany accounts and transactions have been eliminated in consolidation.  We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas.  Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (SEC).  Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP), have been condensed or omitted pursuant to those rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim consolidated financial statements have been included.  The results of operations for the interim periods are not necessarily indicative of the results for the entire year.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP.

These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2013, which was filed with the SEC on March 27, 2014.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes.  These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses.  The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of

7

 


 

 

commodity derivatives and fair values of assets and liabilities.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from the estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Reclassifications

Certain reclassifications have been made to the prior period to conform to the current period presentation.  These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.

Discontinued Operations

In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama.  The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the six months ended June 30, 2013.  Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations.  Information related to discontinued operations is included in Note 3. Acquisitions and Divestiture.

New Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.

In April 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  This guidance changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results.  This guidance is effective prospectively for fiscal years beginning after December 15, 2014.  The effects of this accounting standard on our financial position, results of operations and cash flows are not yet known.

         In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606).  This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services.  The new guidance is effective for fiscal years and interim periods beginning after December 15, 2016.  Early adoption is not permitted.  The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application.  We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2013.

Earnings per Unit

Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period.  To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any.  The remaining net income (loss) is allocated to each class with the Class A units receiving 2% and the Class B units receiving 98%.

As of June 30, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities.  These units will be considered in the diluted weighted average common units outstanding number in periods of net income.  In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.

The following table presents our calculation of basic and diluted units outstanding for the periods indicated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

8

 


 

 

 

 

2014

 

2013

 

2014

 

2013

Weighted average units outstanding during period:

 

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic

 

 

484,505 

 

 

484,370 

 

 

1,046,638 

 

 

484,383 

Class B units - Basic

 

 

28,305,380 

 

 

23,345,280 

 

 

28,259,994 

 

 

23,306,269 

 

 

 

28,789,885 

 

 

23,829,650 

 

 

29,306,632 

 

 

23,790,652 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average units outstanding during period:

 

 

 

 

 

 

 

 

 

 

 

 

Class A units - Diluted

 

 

484,505 

 

 

484,370 

 

 

1,046,638 

 

 

484,383 

Class B units - Diluted

 

 

28,305,380 

 

 

23,720,732 

 

 

28,259,994 

 

 

23,306,269 

 

 

 

28,789,885 

 

 

24,205,102 

 

 

29,306,632 

 

 

23,790,652 

 

At June 30, 2014, we had 503,556 Class B common units that were restricted unvested common units granted and outstanding.  These units were excluded from the diluted weighted average common unit outstanding number.

 

The following table presents our basic and diluted loss per unit for the three months ended June 30, 2014 (in thousands, except for per unit amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Class A Units

 

Class B Units

 

 

 

 

 

 

 

 

 

 

Loss from continuing operations

 

$

(5,011)

 

 

 

 

 

 

Distributions

 

 

 -

 

$

 -

 

$

 -

Assumed net loss to be allocated

 

$

(5,011)

 

$

(100)

 

$

(4,911)

 

 

 

 

 

 

 

 

 

 

Basic and diluted loss per unit

 

 

 

 

$

(0.21)

 

$

(0.17)

 

The following table presents our basic and diluted earnings per unit for the three months ended June 30, 2013 (in thousands, except for per unit amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Class A Units

 

Class B Units

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

1,112 

 

 

 

 

 

 

Distributions

 

 

 -

 

$

 -

 

$

 -

Assumed allocation of income from continuing operations

 

 

1,112 

 

 

22 

 

 

1,090 

Discontinued operations

 

 

 -

 

 

 -

 

 

 -

Assumed net income to be allocated

 

$

1,112 

 

$

22 

 

$

1,090 

 

 

 

 

 

 

 

 

 

 

Basic and diluted earnings from continuing operations per unit

 

 

 

 

$

0.05 

 

$

0.05 

Basic and diluted earnings from discontinued operations per unit

 

 

 

 

$

 -

 

$

 -

Basic and diluted earnings per unit

 

 

 

 

$

0.05 

 

$

0.05 

 

 

 

 

 

 

 

 

 

 

 

The following table presents our basic and diluted loss per unit for the six months ended June 30, 2014 (in thousands, except for per unit amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Class A Units

 

Class B Units

 

 

 

 

 

 

 

 

 

 

Loss from continuing operations

 

$

(7,950)

 

 

 

 

 

 

Distributions

 

 

 -

 

$

 -

 

$

 -

Assumed net loss to be allocated

 

$

(7,950)

 

$

(159)

 

$

(7,791)

 

 

 

 

 

 

 

 

 

 

Basic and diluted loss per unit

 

 

 

 

$

(0.15)

 

$

(0.28)

9

 


 

 

The following table presents our basic and diluted loss per unit for the six months ended June 30, 2013 (in thousands, except for per unit amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

Class A Units

 

Class B Units

 

 

 

 

 

 

 

 

 

 

Loss from continuing operations

 

$

(9,534)

 

 

 

 

 

 

Distributions

 

 

 -

 

$

 -

 

$

 -

Assumed allocation of loss from continuing operations

 

 

(9,534)

 

 

(191)

 

 

(9,343)

Discontinued operations

 

 

(2,686)

 

 

(54)

 

 

(2,632)

Assumed net loss to be allocated

 

$

(12,220)

 

$

(245)

 

$

(11,975)

 

 

 

 

 

 

 

 

 

 

Basic and diluted loss from continuing operations per unit

 

 

 

 

$

(0.39)

 

$

(0.40)

Basic and diluted loss from discontinued operations per unit

 

 

 

 

$

(0.11)

 

$

(0.11)

Basic and diluted loss per unit

 

 

 

 

$

(0.50)

 

$

(0.51)

Cash

All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable at June 30, 2014 and December 31, 2013.

Restricted  Cash

Restricted cash, at June 30, 2014 and December 31, 2013, of $1.7 million was being held in escrow.  Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved.  The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama.  These funds will remain in escrow for a period ending February 28, 2015, pending certain post-closing conditions.  The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at June 30, 2014, based on the conditions of the cash held in the account.

Accounts Receivable, Net

         Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments.  Oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted.  At June 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts receivable of $0.3 million and $0.1 million, respectively.

3. ACQUISITIONS AND DIVESTITURE

Sale of Robinson’s Bend Field Assets

On February 28, 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments that amounted to approximately $4.0 million.  We recorded a loss on the sale of approximately $3.1 million in the six months ended June 30, 2013.  The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt.  

The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the condensed consolidated statements of operations for the three and six months ended June 30, 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30, 2013

 

June 30, 2013

Revenues

$

 -

 

$

2,304 

Loss from discontinued operations

$

 -

 

$

(2,686)

See Note 2 for information regarding earnings per unit, including earnings per unit data relating to loss from discontinued operations.

The condensed consolidated statements of cash flows reflect discontinued operations for the six months ended June 30, 2013.

10

 


 

 

Acquisition of Oil, Natural Gas and Natural Gas Liquids Properties from SEP I

On August 9, 2013, we acquired oil, natural gas and NGLs assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million.  In conjunction with the acquisition, SEP I received $20.1 million in cash; 1,130,512 Class A units, which represented 70.0% of the total Class A units outstanding as of such date, and 4,724,407 Class B units, which represented 16.6% of the total Class B units outstanding as of such date.  The cash portion of the transaction was financed with cash on hand and a borrowing of $16.7 million under our reserve-based credit facility.

The acquired assets include 67 producing wells in Texas and Louisiana.  The primary factors considered by management in acquiring the SEP I properties include the belief that these wells provide an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus of increasing our oil-weighted assets.  The SEP I properties also provide us with access to exploitation and development potential.

The following table summarizes the estimated values of assets acquired and liabilities assumed effective August 1, 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

August 1, 2013

Oil and natural gas properties, equipment and facilities

 

$

31,497 

Asset retirement obligation

 

 

(1,088)

Net assets acquired

 

$

30,409 

We accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore we estimated the fair value of the assets acquired and the liabilities assumed as of the acquisition date.  The fair value measurements of assets acquired and liabilities assumed were based on inputs that were not observable in the market and therefore represent Level 3 inputs.  The fair value of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted cost of capital rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

11

 


 

 

Pro Forma Information

The following supplemental pro forma information presents consolidated results of operations as if the acquisition of the SEP I properties had occurred on January 1, 2013.  The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of operations of SEP I.  This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2013, nor is such information indicative of any expected future results of operations.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pro Forma

 

Pro Forma

 

Three Months Ended

 

Six Months Ended

(In thousands, except per unit data)

June 30, 2013

 

June 30, 2013

Revenue

$

19,668 

 

$

29,316 

Income (loss) from continuing operations

$

3,179 

 

$

(4,551)

Discontinued operations

$

 -

 

$

(2,686)

Net income (loss)

$

3,179 

 

$

(7,237)

Income (loss) from continuing operations per unit

 

 

 

Class A units - Basic and diluted

$

0.04 

 

$

(0.06)

Class B units - Basic and diluted

$

0.11 

 

$

(0.16)

Discontinued operations per unit

 

 

 

 

 

Class A units - Basic and diluted

$

 -

 

$

(0.03)

Class B units - Basic and diluted

$

 -

 

$

(0.09)

Net income (loss) per unit

 

 

 

 

 

Class A units - Basic and diluted

$

0.04 

 

$

(0.09)

Class B units - Basic and diluted

$

0.11 

 

$

(0.25)

Weighted average units outstanding

 

 

 

 

 

Class A units - Basic

 

1,614,882 

 

 

1,614,895 

Class B units - Basic

 

28,069,687 

 

 

28,030,676 

Class A units - Diluted

 

1,614,882 

 

 

1,614,895 

Class B units - Diluted

 

28,445,139 

 

 

28,030,676 

 

Acquisition of Oil and Natural Gas Properties

 

On April 9, 2014, we acquired a 20% working interest in nine producing wells and other assets for $1.4 million.  These assets are located in LaSalle Parish, Louisiana and are operated by SOG.  This purchase became effective May 1, 2014.  The impact of the acquisition of these properties was not material to our consolidated financial statements, so no pro forma information for this acquisition is provided.

 

4. FAIR VALUE MEASUREMENTS

 We measure certain financial assets and liabilities at fair value.  Fair value is defined as an “exit price” which represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date.  As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in valuing an asset or liability.  The accounting guidance also requires the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize the use of unobservable inputs.  As a basis for considering such assumptions and inputs, a fair value hierarchy has been established which identifies and prioritizes three levels of inputs to be used in measuring fair value.

The three levels of the fair value hierarchy are as follows:

Level 1 – Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 – Inputs other than the quoted prices in active markets that are observable either directly or indirectly, including: quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data.

Level 3 – Unobservable inputs that are supported by little or no market data and require the reporting entity to develop its own assumptions.

12

 


 

 

As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at June 30, 2014

 

Quoted Prices in

 

Significant Other

 

 

 

 

 

 

 

 

 

 

Active Markets for

 

Observable

 

Significant

 

 

 

 

 

 

 

Identical Assets

 

Inputs

 

Unobservable Inputs

 

Netting Cash and

 

Fair Value at

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Collateral

 

June 30, 2014

Risk Management Assets

$

 -

 

$

4,473 

 

$

 -

 

$

(301)

 

$

4,172 

Risk Management Liabilities

 

 -

 

 

(4,783)

 

 

 -

 

 

301 

 

 

(4,482)

Total Net Assets and Liabilities

$

 -

 

$

(310)

 

$

 -

 

$

 -

 

$

(310)

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at December 31, 2013

 

Quoted Prices in

 

Significant Other

 

 

 

 

 

 

 

 

 

 

Active Markets for

 

Observable

 

Significant

 

 

 

 

 

 

 

Identical Assets

 

Inputs

 

Unobservable Inputs

 

Netting Cash and

 

Fair Value at

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Collateral

 

December 31, 2013

Risk Management Assets

$

 -

 

$

11,577 

 

$

 -

 

$

(975)

 

$

10,602 

Risk Management Liabilities

 

 -

 

 

(975)

 

 

 -

 

 

975 

 

 

 -

Total Net Assets and Liabilities

$

 -

 

$

10,602 

 

$

 -

 

$

 -

 

$

10,602 

As of June 30, 2014, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.

Fair Value of Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports.  The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Reserve-Based Credit Facility – We believe that the carrying value of long-term debt for our reserve-based credit facility approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  Our reserve-based credit facility is discussed further in Note 7.

        Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs.  Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.  Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate.  We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

13

 


 

 

5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized.  These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty.  These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations.  It is never our intention to enter into derivative contracts for speculative trading purposes.

Under ASC Topic 815, Derivatives and Hedging, all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We will net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.

As of June 30, 2014, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

MTM Fixed Price Swaps—NYMEX (Henry Hub)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the quarter ended (in MMBtu)

 

March 31,

 

June 30,

 

September 30,

 

December 31,

 

Total

 

 

 

Average

 

 

 

Average

 

 

 

Average

 

 

 

Average

 

 

 

Average

 

Volume

 

Price