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EX-31.1 - EX-31.1 - Alta Mesa Holdings, LPc403-20140630ex311c27201.htm
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EX-31.2 - EX-31.2 - Alta Mesa Holdings, LPc403-20140630ex3129a2b08.htm
EX-32.1 - EX-32.1 - Alta Mesa Holdings, LPc403-20140630ex3219d72f4.htm

] 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 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: 333-173751

 

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

 

 

 

 

Texas

20-3565150

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

 

 

15021 Katy Freeway, Suite 400,

Houston, Texas

77094

(Address of principal executive offices)

(Zip Code)

Registrant’s telephone number, including area code: 281-530-0991

 

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   

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant 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 would have been required to file such reports) as if it were subject to such filing requirements.)

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      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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

 

 

 

 

 

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   

 

 

 

1

 


 

 

Table of Contents 

 

 

 

 

 

Page Number

PART I — FINANCIAL INFORMATION

 

Item 1. Financial Statements 

Consolidated Balance Sheets as of June 30, 2014 (unaudited) and December 31, 2013 

Consolidated Statements of Operations  (unaudited) for the Three and Six Months Ended June 30, 2014 and 2013 

Consolidated Statements of Cash  Flows (unaudited) for the Six Months Ended June 30, 2014 and 2013 

Notes to Consolidated Financial Statements (unaudited) 

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

19 

Item 3. Quantitative and Qualitative Disclosures about Market Risk 

30 

Item 4. Controls and Procedures 

30 

PART II — OTHER INFORMATION

 

Item 1. Legal Proceedings 

30 

Item 1A. Risk Factors 

30 

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

30 

Item 3. Defaults Upon Senior Securities 

30 

Item 4. Mine Safety Disclosures 

31 

Item 5. Other Information 

31 

Item 6. Exhibits 

31 

Signatures 

32 

 

 

 

 

2

 


 

PART I — FINANCIAL INFORMATION

ITEM  1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)    

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

December 31,

 

2014

 

2013

 

 

 

 

 

 

 

(unaudited)

 

 

 

ASSETS

 

 

 

 

 

CURRENT ASSETS

 

 

 

 

 

Cash and cash equivalents

$

8,366 

 

$

6,537 

Accounts receivable, net

 

52,233 

 

 

43,486 

Other receivables

 

1,033 

 

 

2,552 

Prepaid expenses and other current assets

 

3,489 

 

 

3,077 

Derivative financial instruments

 

477 

 

 

5,572 

TOTAL CURRENT ASSETS

 

65,598 

 

 

61,224 

PROPERTY AND EQUIPMENT

 

 

 

 

 

Oil and natural gas properties, successful efforts method, net

 

669,180 

 

 

691,770 

Other property and equipment, net

 

9,629 

 

 

9,100 

TOTAL PROPERTY AND EQUIPMENT, NET

 

678,809 

 

 

700,870 

OTHER ASSETS

 

 

 

 

 

Investment in partnership — cost

 

9,000 

 

 

9,000 

Deferred financing costs, net

 

9,510 

 

 

10,943 

Derivative financial instruments

 

 —

 

 

3,405 

Advances to operators

 

3,148 

 

 

6,863 

Deposits and other assets

 

1,144 

 

 

1,186 

TOTAL OTHER ASSETS

 

22,802 

 

 

31,397 

TOTAL ASSETS

$

767,209 

 

$

793,491 

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

Accounts payable and accrued liabilities

$

109,520 

 

$

96,095 

Current portion, asset retirement obligations

 

6,450 

 

 

3,844 

Derivative financial instruments

 

15,967 

 

 

4,483 

TOTAL CURRENT LIABILITIES

 

131,937 

 

 

104,422 

LONG-TERM LIABILITIES

 

 

 

 

 

Asset retirement obligations, net of current portion

 

53,346 

 

 

52,179 

Long-term debt

 

677,353 

 

 

766,868 

Notes payable to founder

 

23,931 

 

 

23,331 

Derivative financial instruments

 

15,369 

 

 

4,486 

Other long-term liabilities

 

7,299 

 

 

2,312 

TOTAL LONG-TERM LIABILITIES

 

777,298 

 

 

849,176 

TOTAL LIABILITIES

 

909,235 

 

 

953,598 

COMMITMENTS AND CONTINGENCIES (NOTE 10)

 

 

 

 

 

PARTNERS’ CAPITAL (DEFICIT)

 

(142,026)

 

 

(160,107)

TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)

$

767,209 

 

$

793,491 

 

 

See notes to consolidated financial statements.

3

 


 

 

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

REVENUES

 

 

 

 

 

 

 

 

 

 

 

Oil

$

92,586 

 

$

75,455 

 

$

172,328 

 

$

140,110 

Natural gas

 

17,855 

 

 

17,580 

 

 

36,540 

 

 

31,182 

Natural gas liquids

 

4,924 

 

 

3,963 

 

 

9,866 

 

 

7,024 

Other revenues

 

225 

 

 

506 

 

 

288 

 

 

1,158 

 

 

115,590 

 

 

97,504 

 

 

219,022 

 

 

179,474 

Gain (loss) on sale of oil and gas property

 

(4,607)

 

 

(120)

 

 

68,551 

 

 

(1,190)

Gain (loss) — oil and natural gas derivative contracts

 

(24,729)

 

 

26,147 

 

 

(35,428)

 

 

13,825 

TOTAL REVENUES

 

86,254 

 

 

123,531 

 

 

252,145 

 

 

192,109 

EXPENSES

 

 

 

 

 

 

 

 

 

 

 

Lease and plant operating expense

 

17,528 

 

 

18,067 

 

 

36,582 

 

 

33,650 

Production and ad valorem taxes

 

6,952 

 

 

7,452 

 

 

14,628 

 

 

13,196 

Workover expense

 

2,198 

 

 

4,508 

 

 

4,963 

 

 

8,585 

Exploration expense

 

18,757 

 

 

6,270 

 

 

28,236 

 

 

8,866 

Depreciation, depletion, and amortization expense

 

33,198 

 

 

28,375 

 

 

62,477 

 

 

52,880 

Impairment expense

 

18,300 

 

 

19,191 

 

 

19,202 

 

 

26,546 

Accretion expense

 

613 

 

 

449 

 

 

1,171 

 

 

892 

General and administrative expense

 

13,894 

 

 

9,420 

 

 

38,611 

 

 

18,761 

TOTAL EXPENSES

 

111,440 

 

 

93,732 

 

 

205,870 

 

 

163,376 

INCOME (LOSS) FROM OPERATIONS

 

(25,186)

 

 

29,799 

 

 

46,275 

 

 

28,733 

OTHER INCOME (EXPENSE)

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(13,632)

 

 

(13,659)

 

 

(27,920)

 

 

(26,949)

Interest income

 

 

 

28 

 

 

 

 

98 

TOTAL OTHER INCOME (EXPENSE)

 

(13,626)

 

 

(13,631)

 

 

(27,911)

 

 

(26,851)

INCOME (LOSS) BEFORE STATE INCOME TAXES

 

(38,812)

 

 

16,168 

 

 

18,364 

 

 

1,882 

BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES

 

 —

 

 

 —

 

 

(283)

 

 

 —

NET INCOME (LOSS)

$

(38,812)

 

$

16,168 

 

$

18,081 

 

$

1,882 

 

 

 

See notes to consolidated financial statements.

 

 

4

 


 

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Six Months Ended

 

June 30,

 

2014

 

2013

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income

$

18,081 

 

$

1,882 

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

 

 

 

Depreciation, depletion, and amortization expense

 

62,477 

 

 

52,880 

Impairment expense

 

19,202 

 

 

26,546 

Accretion expense

 

1,171 

 

 

892 

Amortization of loan costs

 

1,433 

 

 

1,409 

Amortization of debt discount

 

255 

 

 

255 

Dry hole expense

 

20,120 

 

 

4,108 

Expired leases

 

359 

 

 

222 

(Gain) loss on derivative contracts

 

35,428 

 

 

(13,825)

Settlements of derivative contracts

 

(4,561)

 

 

12,775 

Interest converted into debt

 

600 

 

 

599 

(Gain) loss on sale of assets

 

(68,551)

 

 

1,190 

Changes in assets and liabilities:

 

 

 

 

 

Restricted cash

 

 —

 

 

2,305 

Accounts receivable

 

(8,747)

 

 

(5,791)

Other receivables

 

1,519 

 

 

(149)

Prepaid expenses and other non-current assets

 

3,345 

 

 

7,837 

Settlement of asset retirement obligation

 

(1,617)

 

 

(716)

Accounts payable, accrued liabilities, and other long-term liabilities

 

8,153 

 

 

(6,327)

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

88,667 

 

 

86,092 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Capital expenditures for property and equipment

 

(165,165)

 

 

(173,612)

Proceeds from sale of property

 

168,097 

 

 

 —

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES

 

2,932 

 

 

(173,612)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from long-term debt

 

79,500 

 

 

89,500 

Repayments of long-term debt

 

(169,270)

 

 

 —

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

 

(89,770)

 

 

89,500 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

 

1,829 

 

 

1,980 

CASH AND CASH EQUIVALENTS, beginning of period

 

6,537 

 

 

5,786 

CASH AND CASH EQUIVALENTS, end of period

$

8,366 

 

$

7,766 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

 

 

 

 

 

Cash paid during the period for interest

$

24,964 

 

$

24,063 

Cash paid (received) during the period for state taxes

$

(125)

 

$

18 

Change in asset retirement obligations

$

2,838 

 

$

747 

Change in accruals or liabilities for capital expenditures

$

11,642 

 

$

(4,822)

 

 

See notes to consolidated financial statements.

 

 

5

 


 

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

 

1.  OPERATIONS, CONSOLIDATION AND BASIS OF PRESENTATION 

Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent energy company engaged primarily in the acquisition, exploration, development, and production of onshore oil and natural gas properties. Our core properties are located primarily in Texas, Louisiana, and Oklahoma. 

The consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2013,  which were filed with the Securities and Exchange Commission in our 2013 Annual Report on Form 10-K.

The consolidated financial statements included herein as of June  30, 2014, and for the three month and six month periods ended June  30, 2014 and 2013, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain minor reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

 

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June  30,  2014, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2013.  

Use of Estimates:  The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

Reclassifications:   Certain amounts in the 2013 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).  

Property and Equipment:   Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

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Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in Accounting Standards Codification (“ASC”) 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. Unproved leasehold costs are assessed quarterly to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.  

Depreciation, Depletion, and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. 

Accounts Receivable, net:  Our receivables arise from the sale of oil and natural gas to third parties and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and gas industry. Accounts receivable are generally not collateralized. Accounts receivable are shown net of an allowance for doubtful accounts of $1.3 million and $1.4 million at June  30,  2014 and December 31, 2013, respectively.

Deferred Financing Costs:  Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the three month periods ended June  30,  2014 and 2013, amortization of deferred financing costs included in interest expense amounted to $0.7 million and $0.7 million, respectively. For the six month periods ended June 30, 2014 and 2013, amortization of deferred financing costs included in interest expense amounted to $1.4 million and $1.4 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $14.2 million and $12.8 million at June  30,  2014 and December 31, 2013, respectively.

Fair Value of Financial Instruments:  The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $473.6 million at June  30,  2014. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.”  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and

7

 


 

losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606).  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  The update is effective for the Company beginning in calendar year 2017.  We are evaluating the impact this standard will have on our consolidated financial statements and related disclosures.

 

NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES

Eagleville Divestiture

On March 25, 2014 we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The initial cash purchase price was $173 million,  subsequently adjusted to approximately $168 million for settlement adjustments through June 30, 2014.  The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date.  As of January 1, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.7 MMBOE.  We recorded a preliminary gain on sale from the Eagleville divestiture of $68.7 million during the first half of 2014, based on a preliminary allocation of basis between the properties sold and properties retained.

The sold portion of Eagleville field contributed approximately $8.6 million and $16.4 million in net pre-tax profit for the three months and six months ended June 30, 2013, respectively, and $6.6 million in the first quarter of 2014, prior to its sale.

Hilltop Divestiture

On October 2, 2013 we closed the sale of certain of our properties in East Texas to Cubic Oil, Inc., comprising a portion of our Hilltop field (“Hilltop divestiture”).  The properties sold were primarily producers of dry natural gas located in Leon County, Texas.  As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2 BCFE. The net cash purchase price was approximately $19 million.  There was no material gain on the sale.  These wells contributed approximately $0.2 million in net pre-tax income during the three months ended June 30, 2013 and $0.1 million net pre-tax loss during the six months ended June 30, 2013.

Weeks Island Acquisition

On October 1, 2013 we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $45 million plus related abandonment costs, which was later modified through settlement adjustments to approximately $42 million cash. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 MMBOE as of the effective date of July 1, 2013.

8

 


 

A summary of the consideration paid and the preliminary allocation of the purchase prices are as follows:

 

 

 

 

 

 

October 1,

 

2013

 

(dollars in thousands)

 

(unaudited)

Summary of Consideration

 

 

Cash

$

41,841 

Fair value of asset retirement obligations assumed

 

5,311 

Total

$

47,152 

 

 

 

Summary of Purchase Price Allocation

 

 

Proved oil and natural gas properties

$

30,279 

Unproved oil and natural gas properties

 

16,873 

Total

$

47,152 

 

The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2013, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during this period.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

Revenue

 

Income

 

 

 

 

 

 

 

(dollars in thousands)

 

(unaudited)

 

 

 

 

 

 

Pro forma results for the six months ended June 30, 2013

$

213,283 

 

$

8,625 

 

 

 

4. PROPERTY AND EQUIPMENT

 

Property and equipment consists of the following:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

June 30,

 

December 31,

 

2014

 

2013

 

(dollars in thousands)

 

(unaudited)

 

 

 

OIL AND NATURAL GAS PROPERTIES

 

 

 

 

 

Unproved properties

$

77,094 

 

$

86,721 

Accumulated impairment

 

(5,191)

 

 

(7,356)

Unproved properties, net

 

71,903 

 

 

79,365 

Proved oil and natural gas properties

 

1,414,221 

 

 

1,405,658 

Accumulated depreciation, depletion, amortization and impairment

 

(816,944)

 

 

(793,253)

Proved oil and natural gas properties, net

 

597,277 

 

 

612,405 

TOTAL OIL AND NATURAL GAS PROPERTIES, net

 

669,180 

 

 

691,770 

LAND

 

1,918 

 

 

1,418 

OTHER PROPERTY AND EQUIPMENT

 

 

 

 

 

Office furniture and equipment, vehicles

 

15,012 

 

 

13,802 

Accumulated depreciation

 

(7,301)

 

 

(6,120)

OTHER PROPERTY AND EQUIPMENT, net

 

7,711 

 

 

7,682 

TOTAL PROPERTY AND EQUIPMENT, net

$

678,809 

 

$

700,870 

 

Capitalized exploratory well costs

 

Deferred exploratory well costs were $6.5 million and $18.4 million at June 30, 2014 and December 31, 2013, respectively.  The decrease in deferred costs during 2014 is primarily the result of the transfer of $13.5 million for the costs of a New Mexico

9

 


 

exploratory well to dry hole expense.  As of June 30, 2014 deferred exploratory well costs include approximately $3.3 million capitalized for greater than one year.

 

 

 

5. FAIR VALUE DISCLOSURES

We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.

Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting dates, which is a Level 1 determination.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $60.3 million were written down to their fair value of $41.1 million, resulting in an impairment charge of $19.2 million for the six months ended June 30,  2014. Oil and gas properties with a carrying amount of $46.5 million were written down to their fair value of $20.0 million, resulting in an impairment charge of $26.5 million for the six months ended June 30, 2013. Oil and gas properties with a carrying amount of $59.1 million were written down to their fair value of $40.8 million, resulting in an impairment charge of $18.3 million for the three months ended June 30, 2014.  For the three months ended June 30, 2013, oil and gas properties with a carrying amount of $35.4 million were written down to their fair value of $16.2 million, resulting in an impairment charge of $19.2 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

 

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We  recorded $0.4 million and $0.4 million in additions to asset retirement obligations measured at fair value during the  six months ended June  30, 2014 and 2013, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June  30, 2014 and December 31, 2013, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

At June 30, 2014 (unaudited):

 

 

 

 

 

 

 

 

 

 

 

Financial Assets:

 

 

 

 

 

 

 

 

 

 

 

Derivative contracts for oil and natural gas

 

 —

 

$

19,739 

 

 

 —

 

$

19,739 

Financial Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Derivative contracts for oil and natural gas

 

 —

 

$

50,598 

 

 

 —

 

$

50,598 

At December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

Financial Assets:

 

 

 

 

 

 

 

 

 

 

 

Derivative contracts for oil and natural gas

 

 —

 

$

27,850 

 

 

 —

 

$

27,850 

Financial Liabilities:

 

 

 

 

 

 

 

 

 

 

 

Derivative contracts for oil and natural gas

 

 —

 

$

27,842 

 

 

 —

 

$

27,842 

The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 6.  

 

10

 


 

6. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also have utilized financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of our lenders under the credit facility described in Note 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes, and we typically hold each instrument to maturity. 

We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.

Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.    

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815. 

11

 


 

Fair Values of Derivative Contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Fair

 

 

Gross

 

Gross amounts

 

Value of Assets

June 30, 2014

 

Fair Value

 

offset against assets

 

presented in

Balance sheet location

 

of Assets

 

in the Balance Sheet

 

the Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

 

 

(unaudited)

Derivative financial instruments, current assets

 

$

7,444 

 

$

(6,967)

 

$

477 

Derivative financial instruments, long-term assets

 

 

12,295 

 

 

(12,295)

 

 

 —

Total

 

$

19,739 

 

$

(19,262)

 

$

477 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Fair

 

 

Gross

 

Gross amounts

 

Value of Liabilities

June 30, 2014

 

Fair Value

 

offset against liabilities

 

presented in

Balance sheet location

 

of Liabilities

 

in the Balance Sheet

 

the Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

 

 

(unaudited)

Derivative financial instruments, current liabilities

 

$

22,934 

 

$

(6,967)

 

$

15,967 

Derivative financial instruments, long-term liabilities

 

 

27,664 

 

 

(12,295)

 

 

15,369 

Total

 

$

50,598 

 

$

(19,262)

 

$

31,336 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Fair

 

 

Gross

 

Gross amounts

 

Value of Assets

December 31, 2013

 

Fair Value

 

offset against assets

 

presented in

Balance sheet location

 

of Assets

 

in the Balance Sheet

 

the Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

Derivative financial instruments, current assets

 

$

13,218 

 

$

(7,646)

 

$

5,572 

Derivative financial instruments, long-term assets

 

 

14,632 

 

 

(11,227)

 

 

3,405 

Total

 

$

27,850 

 

$

(18,873)

 

$

8,977 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Fair

 

 

Gross

 

Gross amounts

 

Value of Liabilities

December 31, 2013

 

Fair Value

 

offset against liabilities

 

presented in

Balance sheet location

 

of Liabilities

 

in the Balance Sheet

 

the Balance Sheet

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

Derivative financial instruments, current liabilities

 

$

12,129 

 

$

(7,646)

 

$

4,483 

Derivative financial instruments, long-term liabilities

 

 

15,713 

 

 

(11,227)

 

 

4,486 

Total

 

$

27,842 

 

$

(18,873)

 

$

8,969 

 

12

 


 

The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives not

 

 

 

Three Months Ended

 

Six Months Ended

designated as hedging

 

Location of

 

June 30,

 

June 30,

instruments under ASC 815

 

Gain (Loss)

 

2014

 

2013

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands)

 

 

 

 

(unaudited)

Oil commodity contracts

 

Gain (loss) —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

oil and natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

derivative contracts

 

$

(23,541)

 

$

16,639 

 

$

(28,510)

 

$

12,210 

Natural gas commodity contracts

 

Gain (loss) —

 

 

 

 

 

 

 

 

 

 

 

 

 

 

oil and natural gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

derivative contracts

 

 

(1,188)

 

 

9,508 

 

 

(6,918)

 

 

1,615 

Total gains (losses) from

 

 

 

 

 

 

 

 

 

 

 

 

 

 

derivatives not designated as hedges

 

 

 

$

(24,729)

 

$

26,147 

 

$

(35,428)

 

$

13,825 

 

 

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility.

If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

13

 


 

We had the following open derivative contracts for natural gas at June  30, 2014 (unaudited):  

 

NATURAL GAS DERIVATIVE CONTRACTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Volume in

 

Weighted

 

Range

Period and Type of Contract

 

MMBtu

 

Average

 

High

 

Low

2014

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

4,755,000 

 

$

4.41 

 

$

5.60 

 

$

4.01 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

5,778,000 

 

 

5.48 

 

 

9.00 

 

 

4.75 

Long Put Options

 

1,670,000 

 

 

4.86 

 

 

6.00 

 

 

4.25 

Long Call Options

 

3,600,901 

 

 

5.77 

 

 

9.00 

 

 

4.50 

Short Put Options

 

5,227,600 

 

 

3.58 

 

 

4.00 

 

 

3.00 

2015

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

3,832,500 

 

 

5.07 

 

 

5.91 

 

 

4.31 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

7,750,000 

 

 

4.59 

 

 

5.75 

 

 

4.51 

Long Put Options

 

7,525,000 

 

 

4.05 

 

 

5.00 

 

 

4.00 

Short Put Options

 

9,102,500 

 

 

3.32 

 

 

4.45 

 

 

3.25 

2016

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

8,418,000 

 

 

4.22 

 

 

4.23 

 

 

4.22 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

455,000 

 

 

7.50 

 

 

7.50 

 

 

7.50 

Long Put Options

 

455,000 

 

 

5.50 

 

 

5.50 

 

 

5.50 

Short Put Options

 

455,000 

 

 

4.00 

 

 

4.00 

 

 

4.00 

2017

 

 

 

 

 

 

 

 

 

 

 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

6,570,000 

 

 

5.00 

 

 

5.00 

 

 

4.98 

Long Put Options

 

6,570,000 

 

 

4.50 

 

 

4.50 

 

 

4.50 

Short Put Options

 

6,570,000 

 

 

4.00 

 

 

4.00 

 

 

4.00 

2018

 

 

 

 

 

 

 

 

 

 

 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

5,475,000 

 

 

5.50 

 

 

5.53 

 

 

5.48 

Long Put Options

 

5,475,000 

 

 

4.50 

 

 

4.50 

 

 

4.50 

Short Put Options

 

5,475,000 

 

 

4.00 

 

 

4.00 

 

 

4.00 

 

 

14

 


 

We had the following open derivative contracts for crude oil at June  30, 2014 (unaudited):  

 

OIL DERIVATIVE CONTRACTS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Volume

 

Weighted

 

Range

Period and Type of Contract

 

in Bbls

 

Average

 

High

 

Low

2014

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

906,200 

 

$

95.97 

 

$

105.48 

 

$

87.50 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

511,520 

 

 

104.00 

 

 

111.30 

 

 

97.00 

Long Put Options

 

519,800 

 

 

91.59 

 

 

95.00 

 

 

70.00 

Long Call Options

 

621,920 

 

 

101.83 

 

 

110.00 

 

 

90.00 

Short Put Options

 

573,528 

 

 

74.39 

 

 

80.00 

 

 

65.00 

2015

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

1,404,500 

 

 

94.36 

 

 

99.30 

 

 

86.45 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

428,850 

 

 

120.81 

 

 

135.98 

 

 

115.00 

Long Put Options

 

1,231,850 

 

 

87.15 

 

 

95.00 

 

 

85.00 

Short Put Options

 

2,545,850 

 

 

71.11 

 

 

75.00 

 

 

60.00 

2016

 

 

 

 

 

 

 

 

 

 

 

Price Swap Contracts 

 

366,000 

 

 

93.00 

 

 

94.92 

 

 

85.35 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

859,700 

 

 

107.97 

 

 

130.00 

 

 

103.87 

Long Put Options

 

859,700 

 

 

85.98 

 

 

95.00 

 

 

80.00 

Short Put Options

 

859,700 

 

 

65.98 

 

 

75.00 

 

 

60.00 

2017

 

 

 

 

 

 

 

 

 

 

 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

744,950 

 

 

107.99 

 

 

113.83 

 

 

104.15 

Long Put Options

 

744,950 

 

 

83.26 

 

 

90.00 

 

 

80.00 

Short Put Options

 

744,950 

 

 

63.26 

 

 

70.00 

 

 

60.00 

2018

 

 

 

 

 

 

 

 

 

 

 

Collar Contracts

 

 

 

 

 

 

 

 

 

 

 

Short Call Options

 

307,400 

 

 

104.39 

 

 

104.65 

 

 

104.15 

Long Put Options

 

307,400 

 

 

80.00