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, 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 1-9735
BERRY PETROLEUM COMPANY, LLC
(Successor in interest to Berry Petroleum Company)
(Exact name of registrant as specified in its charter)
Delaware (State of incorporation or organization) | 77-0079387 (I.R.S. Employer Identification Number) | |
600 Travis, Suite 5100
Houston, Texas 77002
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code:
(281) 840-4000
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 x
Pursuant to the terms of its senior note indentures, the registrant is a voluntary filer of reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934, and has filed all such reports as required by its senior note indentures during the preceding 12 months.
The registrant meets the conditions set forth in General Instructions H(1)(a) and (b) of Form 10-Q as it is an indirect wholly owned subsidiary of Linn Energy, LLC, which is a reporting company under the Securities Exchange Act of 1934 and which has filed with the SEC all materials required to be filed pursuant to Section 13, 14 or 15(d) thereof, and the registrant is therefore filing this Form 10-Q with a reduced disclosure format.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x 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 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 x | Smaller reporting company ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
On December 16, 2013, the registrant was acquired (see Note 1 of Notes to Condensed Financial Statements), as a result of which 100% of its membership interest is currently held by a single member and the registrant deregistered its equity under the Securities Exchange Act of 1934.
TABLE OF CONTENTS
Page | ||
i
GLOSSARY OF TERMS
As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bbls/d. Bbls per day.
Bcf. One billion cubic feet.
BOE. Barrel of oil equivalent, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.
BOE/d. BOE per day.
Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MBOE/d. MBOE per day.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
Mwh. One thousands kilowatts of electricity used continuously for one hour.
Mwh/d. Mwh per day.
NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
ii
PART I – FINANCIAL INFORMATION
Item 1. | Financial Statements |
BERRY PETROLEUM COMPANY, LLC
CONDENSED BALANCE SHEETS
(Unaudited)
(in thousands)
September 30, 2014 | December 31, 2013 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 6,576 | $ | 51,041 | |||
Accounts receivable – trade, net | 133,775 | 122,855 | |||||
Derivative instruments | 23,290 | 5,596 | |||||
Assets held for sale | 379,770 | — | |||||
Other current assets | 45,110 | 30,833 | |||||
Total current assets | 588,521 | 210,325 | |||||
Noncurrent assets: | |||||||
Oil and natural gas properties (successful efforts method) | 4,807,794 | 4,813,659 | |||||
Less accumulated depletion and amortization | (208,367 | ) | (10,394 | ) | |||
4,599,427 | 4,803,265 | ||||||
Other property and equipment | 102,496 | 83,126 | |||||
Less accumulated depreciation | (6,024 | ) | (233 | ) | |||
96,472 | 82,893 | ||||||
Derivative instruments | 2,315 | 2,511 | |||||
Other noncurrent assets | 15,225 | 8,051 | |||||
17,540 | 10,562 | ||||||
Total noncurrent assets | 4,713,439 | 4,896,720 | |||||
Total assets | $ | 5,301,960 | $ | 5,107,045 | |||
LIABILITIES AND MEMBER'S EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued expenses | $ | 259,409 | $ | 264,271 | |||
Derivative instruments | 911 | 20,393 | |||||
Other accrued liabilities | 17,031 | 28,993 | |||||
Current portion of long-term debt | — | 211,558 | |||||
Total current liabilities | 277,351 | 525,215 | |||||
Noncurrent liabilities: | |||||||
Credit facility | 1,173,175 | 1,173,175 | |||||
Senior notes, net | 914,232 | 916,428 | |||||
Derivative instruments | — | 4,649 | |||||
Other noncurrent liabilities | 200,123 | 192,091 | |||||
Total noncurrent liabilities | 2,287,530 | 2,286,343 | |||||
Commitments and contingencies (Note 10) | |||||||
Member’s equity: | |||||||
Additional paid-in capital | 2,483,181 | 2,315,460 | |||||
Accumulated income (deficit) | 253,898 | (19,973 | ) | ||||
2,737,079 | 2,295,487 | ||||||
Total liabilities and member’s equity | $ | 5,301,960 | $ | 5,107,045 | |||
The accompanying notes are an integral part of these condensed financial statements.
1
BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
(in thousands)
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | ||||||||||||||
Revenues and other: | |||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 350,863 | $ | 306,183 | $ | 1,044,359 | $ | 847,670 | |||||||||
Electricity sales | 11,300 | 10,046 | 31,461 | 27,148 | |||||||||||||
Gains (losses) on oil and natural gas derivatives | 44,990 | (45,293 | ) | 22,893 | (10,408 | ) | |||||||||||
Marketing revenues | 2,018 | 1,916 | 9,106 | 6,198 | |||||||||||||
Other revenues | 245 | 162 | 238 | 867 | |||||||||||||
409,416 | 273,014 | 1,108,057 | 871,475 | ||||||||||||||
Expenses: | |||||||||||||||||
Lease operating expenses | 83,684 | 79,105 | 267,069 | 234,132 | |||||||||||||
Electricity generation expenses | 5,892 | 5,401 | 21,904 | 17,034 | |||||||||||||
Transportation expenses | 13,326 | 8,709 | 28,802 | 24,696 | |||||||||||||
Marketing expenses | 1,811 | 1,895 | 6,505 | 5,971 | |||||||||||||
General and administrative expenses | 16,566 | 17,784 | 88,379 | 59,381 | |||||||||||||
Exploration costs | — | 1,624 | — | 5,925 | |||||||||||||
Depreciation, depletion and amortization | 79,725 | 73,467 | 226,109 | 212,217 | |||||||||||||
Taxes, other than income taxes | 24,830 | 14,662 | 71,338 | 42,861 | |||||||||||||
(Gains) losses on sale of assets and other, net | 49,011 | — | 56,635 | (23 | ) | ||||||||||||
274,845 | 202,647 | 766,741 | 602,194 | ||||||||||||||
Other income and (expenses): | |||||||||||||||||
Interest expense, net of amounts capitalized | (19,068 | ) | (24,996 | ) | (66,555 | ) | (74,562 | ) | |||||||||
Other, net | (179 | ) | 37 | (813 | ) | 70 | |||||||||||
(19,247 | ) | (24,959 | ) | (67,368 | ) | (74,492 | ) | ||||||||||
Income before income taxes | 115,324 | 45,408 | 273,948 | 194,789 | |||||||||||||
Income tax expense | 159 | 17,230 | 77 | 72,813 | |||||||||||||
Net income | $ | 115,165 | $ | 28,178 | $ | 273,871 | $ | 121,976 | |||||||||
The accompanying notes are an integral part of these condensed financial statements.
2
BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENT OF MEMBER’S EQUITY
(Unaudited)
(in thousands)
Additional Paid-In Capital | Accumulated Income (Deficit) | Total Member’s Equity | |||||||||
December 31, 2013 | $ | 2,315,460 | $ | (19,973 | ) | $ | 2,295,487 | ||||
Capital contribution from affiliate | 220,000 | — | 220,000 | ||||||||
Distributions to affiliate | (52,279 | ) | — | (52,279 | ) | ||||||
Net income | — | 273,871 | 273,871 | ||||||||
September 30, 2014 | $ | 2,483,181 | $ | 253,898 | $ | 2,737,079 | |||||
The accompanying notes are an integral part of these condensed financial statements.
3
BERRY PETROLEUM COMPANY, LLC
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | |||||||
Cash flow from operating activities: | ||||||||
Net income | $ | 273,871 | $ | 121,976 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 226,109 | 212,217 | ||||||
Stock-based compensation expense | — | 8,491 | ||||||
Amortization and write-off of deferred financing fees | (5,174 | ) | 5,197 | |||||
Change in book overdraft | — | (14,885 | ) | |||||
Losses on sale of assets and other, net | 48,357 | 9,093 | ||||||
Deferred income taxes | 77 | 85,280 | ||||||
Derivatives activities: | ||||||||
Total (gains) losses | (22,893 | ) | 10,408 | |||||
Cash settlements | (18,130 | ) | (849 | ) | ||||
Changes in assets and liabilities: | ||||||||
Increase in accounts receivable – trade, net | (10,611 | ) | (29,975 | ) | ||||
Decrease in other assets | 4,551 | 456 | ||||||
Increase (decrease) in accounts payable and accrued expenses | (16,341 | ) | 332 | |||||
Decrease in other liabilities | (36,626 | ) | (2,435 | ) | ||||
Net cash provided by operating activities | 443,190 | 405,306 | ||||||
Cash flow from investing activities: | ||||||||
Property acquisitions | — | (3,367 | ) | |||||
Development of oil and natural gas properties | (429,940 | ) | (445,869 | ) | ||||
Purchases of other property and equipment | (8,316 | ) | (4,754 | ) | ||||
Proceeds from sale of properties and equipment and other | 256 | 11,530 | ||||||
Net cash used in investing activities | (438,000 | ) | (442,460 | ) | ||||
Cash flow from financing activities: | ||||||||
Proceeds from borrowings | — | 559,900 | ||||||
Repayments of debt | (206,124 | ) | (486,800 | ) | ||||
Dividends paid | — | (13,204 | ) | |||||
Financing fees and other, net | (11,252 | ) | (339 | ) | ||||
Proceeds from stock option exercises | — | 368 | ||||||
Capital contribution from affiliate | 220,000 | — | ||||||
Distributions to affiliate | (52,279 | ) | — | |||||
Excess tax benefit from stock-based compensation | — | 972 | ||||||
Net cash provided by (used in) financing activities | (49,655 | ) | 60,897 | |||||
Net increase (decrease) in cash and cash equivalents | (44,465 | ) | 23,743 | |||||
Cash and cash equivalents: | ||||||||
Beginning | 51,041 | 312 | ||||||
Ending | $ | 6,576 | $ | 24,055 | ||||
The accompanying notes are an integral part of these condensed financial statements.
4
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
Note 1 – Basis of Presentation
Nature of Business
Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until December 2013. On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units (see Note 2). Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member.
The Company’s properties are located in the United States (“U.S.”), in California (South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite and NMWSS—New Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin), Kansas and the Oklahoma Panhandle (Hugoton Basin) and Colorado (Piceance Basin).
Principles of Reporting
The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The results reported in these unaudited condensed financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.
The financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), member’s equity or cash flows.
Predecessor and Successor Reporting
The LINN Energy transaction was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, LinnCo initially, and LINN Energy upon the contribution was treated as the accounting acquirer and the Company was treated as the acquired company for financial reporting purposes. As such, the assets and liabilities of the Company were provisionally recorded at their respective fair values as of the acquisition date. Fair value adjustments related to the transaction have been pushed down to the Company, resulting in assets and liabilities of the Company being recorded at their fair values at December 16, 2013. See Note 2 for additional information.
The Company’s statements of operations subsequent to the transaction include depreciation, depletion and amortization expense on the Company’s oil and natural gas properties, and other property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the transaction is not comparable to its financial information subsequent to the transaction.
As a result of the impact of pushdown accounting, the financial statements and certain note presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of a different basis of accounting between the periods presented.
5
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
Use of Estimates
The preparation of the accompanying condensed financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount 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 the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. 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 ongoing 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 these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Standards
In May 2014, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures.
In April 2014, the FASB issued an ASU that changes the criteria for reporting discontinued operations and enhances disclosures in this area. This ASU is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company early adopted this ASU on a prospective basis beginning with the third quarter of 2014. The adoption had no effect on the Company’s financial statements.
Note 2 – Properties Exchange and LINN Energy Transaction
Properties Exchange
On August 15, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $49 million, equal to the difference between the carrying value and the fair value of the assets exchanged, which is included in “(gains) losses on sale of assets and other, net” in the condensed statements of operations.
In connection with the exchange, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the exchange date, while transaction and integration costs associated with the exchange were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the exchange date. The results of operations of the properties received in the exchange have been included in the condensed financial statements since the exchange date.
6
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following presents changes in net assets as of the exchange date (in thousands):
Assets: | |||
Current | $ | 16,402 | |
Oil and natural gas properties | (49,332 | ) | |
Other property and equipment | 10,142 | ||
Total assets acquired | (22,788 | ) | |
Liabilities: | |||
Current | 7,040 | ||
Asset retirement obligations | 18,789 | ||
Total liabilities assumed | 25,829 | ||
Net assets acquired | $ | (48,617 | ) |
Current assets include receivables and inventory. Current liabilities include payables and environmental liabilities.
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values 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 average 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.
Properties Exchange – Pending
On September 18, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The Company anticipates the transaction will close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
Divestiture – Pending
On October 1, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive purchase and sale agreement to sell certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC for a contract price of $350 million, subject to closing adjustments. The sale is anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. At September 30, 2014, the Company’s condensed balance sheet included current assets of approximately $380 million included in “assets held for sale” and current liabilities of approximately $2 million included in “other accrued liabilities” classified as “held for sale” related to the sale.
LINN Energy Transaction
On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, LinnCo, an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction was valued at
7
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
On the Berry acquisition date, LinnCo contributed Berry to its affiliate, LINN Energy. As a result, the assets, liabilities and results of operations of Berry are not included in LinnCo’s financial statements.
The acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisition were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.
As a result of being formed as a limited liability company on December 16, 2013, the date of the LINN Energy transaction, the Company ceased to be subject to federal and state income taxes, with the exception of the state of Texas. The Company’s net deferred income tax liabilities were assumed by LinnCo in the merger and were not transferred to LINN Energy in the contribution.
Note 3 – Oil and Natural Gas Properties
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
September 30, 2014 | December 31, 2013 | ||||||
(in thousands) | |||||||
Oil and natural gas: | |||||||
Proved properties | $ | 3,897,780 | $ | 3,397,785 | |||
Unproved properties | 910,014 | 1,415,874 | |||||
4,807,794 | 4,813,659 | ||||||
Less accumulated depletion and amortization | (208,367 | ) | (10,394 | ) | |||
$ | 4,599,427 | $ | 4,803,265 | ||||
Note 4 – Debt
The following summarizes the Company’s outstanding debt:
September 30, 2014 | December 31, 2013 | ||||||
(in thousands, except percentages) | |||||||
Credit facility (1) | $ | 1,173,175 | $ | 1,173,175 | |||
10.25% senior notes due June 2014 | — | 205,257 | |||||
6.75% senior notes due November 2020 | 299,970 | 300,000 | |||||
6.375% senior notes due September 2022 | 599,163 | 600,000 | |||||
Net unamortized premiums | 15,099 | 22,729 | |||||
Total debt, net | 2,087,407 | 2,301,161 | |||||
Less current maturities | — | (211,558 | ) | ||||
Total long-term debt, net | $ | 2,087,407 | $ | 2,089,603 | |||
(1) | Variable interest rates of 2.66% and 2.67% at September 30, 2014, and December 31, 2013, respectively. |
8
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
Fair Value
The Company’s debt is recorded at the carrying amount in the condensed balance sheets. The carrying amount of the Company’s Credit Facility, as defined below, approximates fair value because the interest rate is variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.
September 30, 2014 | December 31, 2013 | ||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
(in thousands) | |||||||||||||||
Credit facility | $ | 1,173,175 | $ | 1,173,175 | $ | 1,173,175 | $ | 1,173,175 | |||||||
Senior notes, net | 914,232 | 884,906 | 1,127,986 | 1,128,527 | |||||||||||
Total debt, net | $ | 2,087,407 | $ | 2,058,081 | $ | 2,301,161 | $ | 2,301,702 | |||||||
Credit Facility
The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At September 30, 2014, lender commitments under the Credit Facility were $1.2 billion but the Company had less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants, among other items, and in April 2014, the Company entered into an amendment to the Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.
Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. The Company is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves.
The Company is currently in compliance with all financial and other covenants of the Credit Facility. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected.
At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Credit Facility) or a Base Rate (as defined in the Credit Facility) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of utilization under the Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
Senior Notes Due November 2020
The Company has $300 million in aggregate principal amount of 6.75% senior notes due November 2020 (the “November 2020 Senior Notes”). The November 2020 Senior Notes were recorded at their fair value of $310 million on the acquisition date including a $10 million premium which is being amortized to interest expense over the life of the related notes.
9
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
Senior Notes Due September 2022
The Company has $599 million aggregate principal amount of 6.375% senior notes due September 2022 (the “September 2022 Senior Notes”). The September 2022 Senior Notes were recorded at their fair value of $607 million on the acquisition date including a $7 million premium which is being amortized to interest expense over the life of the related notes.
Repurchases of Senior Notes
In February 2014, in accordance with the indentures related to the senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of its 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”), November 2020 Senior Notes and September 2022 Senior Notes, respectively.
Payment of Senior Notes Due June 2014
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
Senior Notes Covenants
The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions on its equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of the Company’s assets. The Company is in compliance with all financial and other covenants of its senior notes.
Note 5 – Derivative Instruments
The Company hedges a significant portion of its forecasted oil production to reduce exposure to commodity price fluctuations and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company does not directly hedge its NGL production. The Company also, from time to time, enters into derivative contracts for a portion of its natural gas consumption. The Company has not entered into any new commodity derivative positions to date in 2014.
The Company enters into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.
The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 6 for fair value disclosures about oil and natural gas commodity derivatives.
10
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
The following table summarizes derivative positions for the periods indicated as of September 30, 2014:
October 1 - December 31, 2014 | 2015 | ||||||
Oil positions: | |||||||
Fixed price swaps (NYMEX WTI): | |||||||
Hedged volume (MBbls) | 1,242 | — | |||||
Average price ($/Bbl) | $ | 91.26 | $ | — | |||
Collars (NYMEX WTI): | |||||||
Hedged volume (MBbls) | 184 | — | |||||
Average floor price ($/Bbl) | $ | 90.00 | $ | — | |||
Average ceiling price ($/Bbl) | $ | 102.87 | $ | — | |||
Three-way collars (NYMEX WTI): | |||||||
Hedged volume (MBbls) | 782 | 1,095 | |||||
Short put ($/Bbl) | $ | 72.11 | $ | 70.00 | |||
Long put ($/Bbl) | $ | 93.76 | $ | 90.00 | |||
Short call ($/Bbl) | $ | 109.79 | $ | 101.62 | |||
Three-way collars (ICE Brent): | |||||||
Hedged volume (MBbls) | 92 | — | |||||
Short put ($/Bbl) | $ | 80.00 | $ | — | |||
Long put ($/Bbl) | $ | 100.00 | $ | — | |||
Short call ($/Bbl) | $ | 114.05 | $ | — | |||
Oil basis differential positions: | |||||||
ICE Brent - NYMEX WTI basis swaps: | |||||||
Hedged volume (MBbls) | 920 | 2,920 | |||||
Hedged differential ($/Bbl) | $ | 11.60 | $ | 11.60 | |||
Oil timing differential positions: | |||||||
Trade month roll swaps (NYMEX WTI): (1) | |||||||
Hedged volume (MBbls) | 460 | — | |||||
Hedged differential ($/Bbl) | $ | 0.32 | $ | — | |||
(1) | The Company hedges the timing risk associated with the sales price of oil in the Permian Basin. In this operating area, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”). |
Settled derivatives on oil production for the three months and nine months ended September 30, 2014, included volumes of 2,300 MBbls and 6,825 MBbls, respectively, at an average contract price of $92.16 per Bbl. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.
11
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
September 30, 2014 | December 31, 2013 | ||||||
(in thousands) | |||||||
Assets: | |||||||
Commodity derivatives | $ | 28,166 | $ | 28,291 | |||
Liabilities: | |||||||
Commodity derivatives | $ | 3,472 | $ | 45,226 | |||
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $28 million at September 30, 2014. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Gains (Losses) on Derivatives
Gains and losses on oil and natural gas derivatives were net gains of approximately $45 million and $23 million for the three months and nine months ended September 30, 2014, respectively. Net gains for the three months and nine months ended September 30, 2014, include cash settlement payments of approximately $8 million and $19 million, respectively. Gains and losses on oil and natural gas derivatives were net losses of approximately $45 million and $10 million for the three months and nine months ended September 30, 2013, respectively. Net losses for the three months and nine months ended September 30, 2013, include cash settlement payments of approximately $6 million and $1 million, respectively. These amounts are reported on the condensed statements of operations in “gains (losses) on oil and natural gas derivatives.”
Note 6 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 5) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.
Fair Value Hierarchy
In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest
12
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
September 30, 2014 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 28,166 | $ | (2,561 | ) | $ | 25,605 | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 3,472 | $ | (2,561 | ) | $ | 911 | ||||
December 31, 2013 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 28,291 | $ | (20,184 | ) | $ | 8,107 | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 45,226 | $ | (20,184 | ) | $ | 25,042 | ||||
(1) | Represents counterparty netting under agreements governing such derivatives. |
Note 7 – Asset Retirement Obligations
Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the nine months ended September 30, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.3% for the nine months ended September 30, 2014). 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.
The following presents a reconciliation of the Company’s asset retirement obligations (in thousands):
Asset retirement obligations at December 31, 2013 | $ | 94,830 | |
Liabilities added from acquisitions | 20,919 | ||
Liabilities added from drilling | 4,122 | ||
Liabilities associated with assets divested | (2,129 | ) | |
Current year accretion expense | 4,123 | ||
Settlements | (4,536 | ) | |
Asset retirement obligations at September 30, 2014 | $ | 117,329 | |
Note 8 – Income Taxes
The Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the
13
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
operations of the Company. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. Amounts recognized for income taxes are reported in “income tax expense” on the condensed statements of operations.
Note 9 – Equity Incentive Compensation Plans
The successor Company does not have any equity incentive compensation (“EIC”) plans under which it grants stock awards and, therefore, recognized no direct stock compensation expense for the nine months ended September 30, 2014. Prior to the LINN Energy transaction, the Company granted equity awards to its employees under its EIC plans. The total compensation expense recognized by the predecessor Company in the condensed statements of operations for grants under the Company’s EIC plans was approximately $3 million and $8 million for the three months and nine months ended September 30, 2013, respectively. In connection with the LINN Energy transaction, effective December 16, 2013, the predecessor Company’s equity awards were exchanged for LinnCo common shares or LINN Energy equity awards.
Note 10 – Commitments and Contingencies
East Texas Gathering System
The Company is party to certain long-term natural gas gathering agreements for its east Texas production. The agreements contain embedded leases and the transaction has been accounted for as a financing obligation. The fair value of the property associated with this transaction was recorded in the amount of approximately $13 million and is being depreciated over the remaining useful life of the asset. Under the agreements, portions of the payments are recorded as gathering expense and interest expense with the balance recorded as a reduction to the financing obligation. There are no minimum payments required under these agreements.
Carry and Earning Agreement
In January 2011, the Company entered into an amendment relating to certain contractual obligations to a third-party co-owner of certain Piceance Basin assets in Colorado. The amendment waives a $200,000 penalty for each well not spud by February 2011 and requires the Company to reassign to such third party, by January 31, 2020, all of the interest acquired by the Company from the third party in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party’s 50% share. Pursuant to the terms of a further amendment entered into in April 2014, if by September 30, 2015, the Company does not expend $9 million on the construction of either the extension of the road or a new road, the Company is obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. Under the terms of the 2014 amendment, this deadline is subject to further extension to no later than December 31, 2015. Due to the need to obtain regulatory approvals, among other reasons, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by the extended deadline, thus triggering the payment obligation to the third party.
Legal Matters
Department of the Interior Notice of Proposed Debarment
In June 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (“DOI”). Pursuant to the notice, the DOI’s Office of the Inspector General proposed to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company’s purported noncompliance with Bureau of Land Management (“BLM”) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2 million civil penalty relating to the matter. The Company contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The independent compliance review has concluded and the final compliance review reports
14
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
have been submitted to the DOI. The Company has been informed that the DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.
Royalty Class Action
The Company is a defendant in a certain statewide royalty class action case in which the parties have entered into a settlement agreement to settle past claims for approximately $2.4 million. Subject to approval of the settlement agreement by the court, the Company anticipates distribution of settlement funds to begin in the fourth quarter of 2014.
Other
The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its business, financial condition, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
During the three months and nine months ended September 30, 2014, and September 30, 2013, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Note 11 – Related Party Transactions
LINN Energy
All former employees of the Company that were retained after the LINN Energy transaction are now employed by Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, provide services and support to the Company in accordance with an agency agreement and power of attorney between the Company and LOI. For the three months and nine months ended September 30, 2014, the Company incurred management fee expenses of approximately $14 million and $74 million, respectively, for services provided by LOI.
During the second quarter of 2014, LINN Energy made a cash capital contribution of $220 million to the Company which was used to pay in full the remaining outstanding principal amount of its approximately $205 million June 2014 Senior Notes plus accrued interest. For the three months and nine months ended September 30, 2014, the Company made cash distributions of approximately $11 million and $52 million, respectively, to LINN Energy. The Company also has affiliated accounts payable due to LOI of approximately $11 million and $17 million at September 30, 2014, and December 31, 2013, respectively, included in “accounts payable and accrued expenses” on the condensed balance sheets.
Other
One of LINN Energy’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the nine months ended September 30, 2014, the Company paid approximately $176,000 to Superior or its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions. No payments were made during the three months ended September 30, 2014.
15
BERRY PETROLEUM COMPANY, LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS – Continued
(Unaudited)
Note 12 – Supplemental Disclosures to the Condensed Balance Sheets and Condensed Statements of Cash Flows
“Other current assets” reported on the condensed balance sheets primarily consist of inventories. “Other accrued liabilities” reported on the condensed balance sheets include the following:
September 30, 2014 | December 31, 2013 | ||||||
(in thousands) | |||||||
Accrued interest | $ | 11,572 | $ | 18,926 | |||
Accrued compensation | — | 6,749 | |||||
Asset retirement obligations | 3,318 | 3,318 | |||||
Liabilities held for sale | 1,899 | — | |||||
Other | 242 | — | |||||
$ | 17,031 | $ | 28,993 | ||||
Supplemental disclosures to the condensed statements of cash flows are presented below:
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | |||||||
(in thousands) | ||||||||
Cash payments for interest, net of amounts capitalized | $ | 79,090 | $ | 64,571 | ||||
Cash payments for income taxes | $ | — | $ | 622 | ||||
Noncash investing activities: | ||||||||
Accrued capital expenditures | $ | 17,552 | $ | 40,164 | ||||
Asset retirement obligations | $ | 4,122 | $ | 13,222 | ||||
On August 15, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin. See Note 2 for additional information.
16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2013, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The reference to a “Note” herein refers to the accompanying Notes to Condensed Financial Statements contained in Item 1. “Financial Statements.”
Executive Overview
Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy in December 2013 (see “LINN Energy Transaction” below and Note 2). Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member.
The Company’s properties are located in the United States (“U.S.”), in California (South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite and NMWSS—New Steam Floods (“NSF”)), Texas (Permian Basin and east Texas), Utah (Uinta Basin), Kansas and the Oklahoma Panhandle (Hugoton Basin) and Colorado (Piceance Basin).
Results for the three months ended September 30, 2014, included the following:
• | oil, natural gas and NGL sales of approximately $351 million compared to $306 million for the third quarter of 2013; |
• | average daily production of 54.7 MBOE/d compared to 41.4 MBOE/d for the third quarter of 2013; |
• | net income of approximately $115 million compared to $28 million for the third quarter of 2013; |
• | capital expenditures, excluding acquisitions, of approximately $163 million compared to $144 million for the third quarter of 2013; and |
• | 129 wells drilled (all successful) compared to 101 wells drilled (all successful) for the third quarter of 2013. |
Results for the nine months ended September 30, 2014, included the following:
• | oil, natural gas and NGL sales of approximately $1.0 billion compared to $848 million for the nine months ended September 30, 2013; |
• | average daily production of 50.7 MBOE/d compared to 40.2 MBOE/d for the nine months ended September 30, 2013; |
• | net income of approximately $274 million compared to $122 million for the nine months ended September 30, 2013; |
• | net cash provided by operating activities of approximately $443 million compared to $405 million for the nine months ended September 30, 2013; |
• | capital expenditures, excluding acquisitions, of approximately $438 million compared to $451 million for the nine months ended September 30, 2013; and |
• | 317 wells drilled (all successful) compared to 259 wells drilled (all successful) for the nine months ended September 30, 2013. |
LINN Energy Transaction
On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares.
17
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction was valued at approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
Predecessor and Successor Reporting
As a result of the impact of pushdown accounting on the acquisition date (see Note 1), the Company’s financial statements and certain note presentations are separated into two distinct periods, the period before the consummation of the LINN Energy transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of a different basis of accounting between the periods presented. Despite this separate GAAP presentation, the successor had no independent oil and natural gas operations prior to the acquisition, and, accordingly, there were no operational activities that changed as a result of the acquisition of the predecessor.
Properties Exchange
On August 15, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”), in exchange for properties in the Hugoton Basin. The Company received approximately 514 Bcfe of proved reserves, primarily natural gas, as of the exchange date, while ExxonMobil received approximately 20,000 net acres in the Midland Basin, which are located primarily in Midland, Martin and Glasscock counties, and approximately 154 Bcfe of proved reserves.
Properties Exchange – Pending
On September 18, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The Company anticipates the transaction will close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
Divestiture – Pending
On October 1, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, entered into a definitive purchase and sale agreement to sell certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC for a contract price of $350 million, subject to closing adjustments. The sale is anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
Financing and Liquidity
On May 30, 2014, in accordance with the provisions of the indenture related to its 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”), the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy.
18
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
Three Months Ended September 30, 2014, Compared to Three Months Ended September 30, 2013
Successor | Predecessor | |||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Revenues and other: | ||||||||||||
Oil sales | $ | 310,742 | $ | 280,732 | $ | 30,010 | ||||||
Natural gas sales | 34,950 | 16,966 | 17,984 | |||||||||
NGL sales | 5,171 | 8,485 | (3,314 | ) | ||||||||
Total oil, natural gas and NGL sales | 350,863 | 306,183 | 44,680 | |||||||||
Electricity sales | 11,300 | 10,046 | 1,254 | |||||||||
Gains (losses) on oil and natural gas derivatives | 44,990 | (45,293 | ) | 90,283 | ||||||||
Marketing and other revenues | 2,263 | 2,078 | 185 | |||||||||
409,416 | 273,014 | 136,402 | ||||||||||
Expenses: | ||||||||||||
Lease operating expenses | 83,684 | 79,105 | 4,579 | |||||||||
Electricity generation expenses | 5,892 | 5,401 | 491 | |||||||||
Transportation expenses | 13,326 | 8,709 | 4,617 | |||||||||
Marketing expenses | 1,811 | 1,895 | (84 | ) | ||||||||
General and administrative expenses | 16,566 | 17,784 | (1,218 | ) | ||||||||
Exploration costs | — | 1,624 | (1,624 | ) | ||||||||
Depreciation, depletion and amortization | 79,725 | 73,467 | 6,258 | |||||||||
Taxes, other than income taxes | 24,830 | 14,662 | 10,168 | |||||||||
Losses on sale of assets and other, net | 49,011 | — | 49,011 | |||||||||
274,845 | 202,647 | 72,198 | ||||||||||
Other income and (expenses) | (19,247 | ) | (24,959 | ) | 5,712 | |||||||
Income before income taxes | 115,324 | 45,408 | 69,916 | |||||||||
Income tax expense | 159 | 17,230 | (17,071 | ) | ||||||||
Net income | $ | 115,165 | $ | 28,178 | $ | 86,987 | ||||||
19
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Successor | Predecessor | ||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | |||||||||
Average daily production: | |||||||||||
Oil (MBbls/d) | 37.8 | 30.7 | 23 | % | |||||||
Natural gas (MMcf/d) | 93.5 | 50.5 | 85 | % | |||||||
NGL (MBbls/d) | 1.2 | 2.3 | (48 | )% | |||||||
Total (MBOE/d) | 54.7 | 41.4 | 32 | % | |||||||
Weighted average price: (1) | |||||||||||
Oil (Bbl) | $ | 89.24 | $ | 99.47 | (10 | )% | |||||
Natural gas (Mcf) | $ | 4.06 | $ | 3.65 | 11 | % | |||||
NGL (Bbl) | $ | 45.56 | $ | 39.76 | 15 | % | |||||
Average NYMEX prices: | |||||||||||
Oil (Bbl) | $ | 97.17 | $ | 105.82 | (8 | )% | |||||
Natural gas (MMBtu) | $ | 4.06 | $ | 3.58 | 13 | % | |||||
Costs per BOE of production: | |||||||||||
Lease operating expenses | $ | 16.64 | $ | 20.76 | (20 | )% | |||||
Transportation expenses | $ | 2.65 | $ | 2.29 | 16 | % | |||||
General and administrative expenses | $ | 3.29 | $ | 4.67 | (30 | )% | |||||
Depreciation, depletion and amortization | $ | 15.85 | $ | 19.28 | (18 | )% | |||||
Taxes, other than income taxes | $ | 4.94 | $ | 3.85 | 28 | % | |||||
(1) | Does not include the effect of gains (losses) on derivatives. |
20
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $45 million or 15% to approximately $351 million for the three months ended September 30, 2014, from approximately $306 million for the three months ended September 30, 2013, due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Higher natural gas and NGL prices resulted in an increase in revenues of approximately $4 million and $1 million, respectively. Lower oil prices resulted in a decrease in revenues of approximately $36 million.
Average daily production volumes increased to approximately 54.7 MBOE/d for the three months ended September 30, 2014, from 41.4 MBOE/d for the three months ended September 30, 2013. Higher oil and natural gas production volumes resulted in an increase in revenues of approximately $66 million and $14 million, respectively. Lower NGL production volumes resulted in a decrease in revenues of approximately $4 million.
The following table sets forth average daily production by operating area:
Successor | Predecessor | |||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | ||||||||||
Average daily production (MBOE/d): | ||||||||||||
California | 26.6 | 20.8 | 5.8 | 28 | % | |||||||
Uinta Basin | 11.2 | 8.1 | 3.1 | 38 | % | |||||||
Permian Basin | 7.6 | 8.4 | (0.8 | ) | (10 | )% | ||||||
Piceance Basin | 1.9 | 2.2 | (0.3 | ) | (14 | )% | ||||||
Hugoton Basin | 5.6 | — | 5.6 | — | % | |||||||
East Texas | 1.8 | 1.9 | (0.1 | ) | (5 | )% | ||||||
54.7 | 41.4 | 13.3 | 32 | % | ||||||||
The increase in average daily production volumes in California and the Uinta Basin operating areas primarily reflects development capital spending. The decrease in average daily production volumes in the Permian Basin operating area primarily reflects the production volumes related to the properties relinquished in the exchange with ExxonMobil on August 15, 2014. The decrease in average daily production volumes in the Piceance Basin and East Texas operating areas primarily reflects the effects of production declines due to reduced development capital spending. Average daily production volumes in the Hugoton Basin operating area reflect the impact of the properties received in the exchange with ExxonMobil.
Electricity Sales
The following table sets forth selected electricity data:
Successor | Predecessor | ||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | |||||||||
Electricity sales (in thousands) | $ | 11,300 | $ | 10,046 | 12 | % | |||||
Electricity generation expenses (in thousands) | $ | 5,892 | $ | 5,401 | 9 | % | |||||
Electric power produced (Mwh/d) | 2,119 | 1,793 | 18 | % | |||||||
Electric power sold (Mwh/d) | 1,933 | 1,720 | 12 | % | |||||||
Average sales price per Mwh | $ | 71.18 | $ | 63.30 | 12 | % | |||||
Fuel gas cost per MMBtu (including transportation) | $ | 4.17 | $ | 3.60 | 16 | % | |||||
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1) | 14,557 | 13,192 | 10 | % | |||||||
(1) | Estimate is based on the historical allocation of fuel costs to electricity. |
21
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Electricity sales increased by approximately $1 million or 12% to approximately $11 million for the three months ended September 30, 2014, from approximately $10 million for the three months ended September 30, 2013, primarily due to an increase in the average sales price of electricity and electric power sold during the period.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $45 million for the three months ended September 30, 2014, compared to losses of approximately $45 million for the three months ended September 30, 2013, representing a variance of approximately $90 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts partially offset by higher cash settlement payments during the period. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues remained consistent at approximately $2 million for both the three months ended September 30, 2014, and September 30, 2013.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $5 million or 6% to approximately $84 million for the three months ended September 30, 2014, from approximately $79 million for the three months ended September 30, 2013. Lease operating expenses increased primarily due to an increase in steam costs caused by a higher price and volume of natural gas used in steam generation. Lease operating expenses per BOE decreased to $16.64 per BOE for the three months ended September 30, 2014, from $20.76 per BOE for the three months ended September 30, 2013, primarily due to higher production volumes.
The following table sets forth steam information:
Successor | Predecessor | ||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | |||||||||
Average net volume of steam injected (Bbls/d) | 252,006 | 198,774 | 27 | % | |||||||
Fuel gas cost per MMBtu (including transportation) | $ | 4.17 | $ | 3.60 | 16 | % | |||||
Estimated natural gas volumes consumed to produce steam (MMBtu/d) | 90,348 | 70,040 | 29 | % | |||||||
Electricity Generation Expenses
Electricity generation expenses increased by approximately $1 million or 9% to approximately $6 million for the three months ended September 30, 2014, from approximately $5 million for the three months ended September 30, 2013, primarily due to increases in fuel gas cost and fuel gas volumes purchased.
Transportation Expenses
Transportation expenses increased by approximately $4 million or 53% to approximately $13 million for the three months ended September 30, 2014, from approximately $9 million for the three months ended September 30, 2013, primarily due to
22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
higher expenses due to increased production volumes in the Uinta Basin partially offset by favorable marketing contract adjustments.
Marketing Expenses
Marketing expenses primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses remained consistent at approximately $2 million for both the three months ended September 30, 2014, and September 30, 2013.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations. General and administrative expenses decreased by approximately $1 million or 7% to approximately $17 million for the three months ended September 30, 2014, from approximately $18 million for the three months ended September 30, 2013. The decrease was primarily due to lower share-based compensation allocated to the Company by LOI. General and administrative expenses per BOE also decreased to $3.29 per BOE for the three months ended September 30, 2014, from $4.67 per BOE for the three months ended September 30, 2013.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $7 million or 9% to approximately $80 million for the three months ended September 30, 2014, from approximately $73 million for the three months ended September 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per BOE decreased to $15.85 per BOE for the three months ended September 30, 2014, from $19.28 per BOE for the three months ended September 30, 2013, primarily due to a lower oil and natural gas properties basis as a result of the adjustment made to record the properties at fair value on December 16, 2013, the acquisition date.
Taxes, Other Than Income Taxes
Successor | Predecessor | |||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Severance taxes | $ | 8,187 | $ | 5,191 | $ | 2,996 | ||||||
Ad valorem taxes | 12,529 | 5,869 | 6,660 | |||||||||
California carbon allowances | 4,114 | 3,602 | 512 | |||||||||
$ | 24,830 | $ | 14,662 | $ | 10,168 | |||||||
Taxes, other than income taxes increased by approximately $10 million or 69% for the three months ended September 30, 2014, compared to the three months ended September 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to an adjustment to the taxable property basis in California in connection with the LINN Energy transaction. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed.
Losses on Sale of Assets and Other, Net
During the three months ended September 30, 2014, the Company recorded a net loss of approximately $49 million on the noncash exchange of a portion of its Permian Basin properties to ExxonMobil for properties in the Hugoton Basin (see Note 2).
23
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Other Income and (Expenses)
Successor | Predecessor | |||||||||||
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Interest expense, net of amounts capitalized | $ | (19,068 | ) | $ | (24,996 | ) | $ | 5,928 | ||||
Other, net | (179 | ) | 37 | (216 | ) | |||||||
$ | (19,247 | ) | $ | (24,959 | ) | $ | 5,712 | |||||
Other income and (expenses) decreased by approximately $6 million for the three months ended September 30, 2014, compared to the three months ended September 30, 2013. Interest expense decreased primarily due to the amortization of premiums related to the Company’s debt being recorded at fair value on December 16, 2013, the acquisition date, partially offset by higher outstanding debt during the period. See “Debt” in “Liquidity and Capital Resources” below for additional details.
Income Tax Expense
Effective December 16, 2013, the Company became a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. The Company recognized an income tax expense of approximately $159,000 for the three months ended September 30, 2014, compared to income tax expense of approximately $17 million for the three months ended September 30, 2013. The decrease was primarily due to the Company’s conversion from a Subchapter C-corporation to a limited liability company in connection with the LINN Energy transaction.
Net Income
Net income increased by approximately $87 million or 309% to approximately $115 million for the three months ended September 30, 2014, from approximately $28 million for the three months ended September 30, 2013. The increase was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher expenses. See discussions above for explanations of variances.
24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
Nine Months Ended September 30, 2014, Compared to Nine Months Ended September 30, 2013
Successor | Predecessor | |||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Revenues and other: | ||||||||||||
Oil sales | $ | 936,463 | $ | 775,293 | $ | 161,170 | ||||||
Natural gas sales | 88,339 | 50,994 | 37,345 | |||||||||
NGL sales | 19,557 | 21,383 | (1,826 | ) | ||||||||
Total oil, natural gas and NGL sales | 1,044,359 | 847,670 | 196,689 | |||||||||
Electricity sales | 31,461 | 27,148 | 4,313 | |||||||||
Gains (losses) on oil and natural gas derivatives | 22,893 | (10,408 | ) | 33,301 | ||||||||
Marketing and other revenues | 9,344 | 7,065 | 2,279 | |||||||||
1,108,057 | 871,475 | 236,582 | ||||||||||
Expenses: | ||||||||||||
Lease operating expenses | 267,069 | 234,132 | 32,937 | |||||||||
Electricity generation expenses | 21,904 | 17,034 | 4,870 | |||||||||
Transportation expenses | 28,802 | 24,696 | 4,106 | |||||||||
Marketing expenses | 6,505 | 5,971 | 534 | |||||||||
General and administrative expenses | 88,379 | 59,381 | 28,998 | |||||||||
Exploration costs | — | 5,925 | (5,925 | ) | ||||||||
Depreciation, depletion and amortization | 226,109 | 212,217 | 13,892 | |||||||||
Taxes, other than income taxes | 71,338 | 42,861 | 28,477 | |||||||||
(Gains) losses on sale of assets and other, net | 56,635 | (23 | ) | 56,658 | ||||||||
766,741 | 602,194 | 164,547 | ||||||||||
Other income and (expenses) | (67,368 | ) | (74,492 | ) | 7,124 | |||||||
Income before income taxes | 273,948 | 194,789 | 79,159 | |||||||||
Income tax expense | 77 | 72,813 | (72,736 | ) | ||||||||
Net income | $ | 273,871 | $ | 121,976 | $ | 151,895 | ||||||
25
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Successor | Predecessor | ||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | |||||||||
Average daily production: | |||||||||||
Oil (MBbls/d) | 37.2 | 29.8 | 25 | % | |||||||
Natural gas (MMcf/d) | 71.0 | 50.0 | 42 | % | |||||||
NGL (MBbls/d) | 1.6 | 2.1 | (24 | )% | |||||||
Total (MBOE/d) | 50.7 | 40.2 | 26 | % | |||||||
Weighted average price: (1) | |||||||||||
Oil (Bbl) | $ | 92.19 | $ | 95.42 | (3 | )% | |||||
Natural gas (Mcf) | $ | 4.56 | $ | 3.73 | 22 | % | |||||
NGL (Bbl) | $ | 43.68 | $ | 37.05 | 18 | % | |||||
Average NYMEX prices: | |||||||||||
Oil (Bbl) | $ | 99.61 | $ | 98.14 | 1 | % | |||||
Natural gas (MMBtu) | $ | 4.55 | $ | 3.67 | 24 | % | |||||
Costs per BOE of production: | |||||||||||
Lease operating expenses | $ | 19.30 | $ | 21.33 | (10 | )% | |||||
Transportation expenses | $ | 2.08 | $ | 2.25 | (8 | )% | |||||
General and administrative expenses | $ | 6.39 | $ | 5.41 | 18 | % | |||||
Depreciation, depletion and amortization | $ | 16.34 | $ | 19.33 | (15 | )% | |||||
Taxes, other than income taxes | $ | 5.16 | $ | 3.90 | 32 | % | |||||
(1) | Does not include the effect of gains (losses) on derivatives. |
26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales increased by approximately $197 million or 23% to approximately $1.0 billion for the nine months ended September 30, 2014, from approximately $848 million for the nine months ended September 30, 2013, due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Higher natural gas and NGL prices resulted in an increase in revenues of approximately $16 million and $3 million, respectively. Lower oil prices resulted in a decrease in revenues of approximately $33 million.
Average daily production volumes increased to approximately 50.7 MBOE/d for the nine months ended September 30, 2014, from 40.2 MBOE/d for the nine months ended September 30, 2013. Higher oil and natural gas production volumes resulted in an increase in revenues of approximately $195 million and $21 million, respectively. Lower NGL production volumes resulted in a decrease in revenues of approximately $5 million.
The following table sets forth average daily production by operating area:
Successor | Predecessor | |||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | ||||||||||
Average daily production (MBOE/d): | ||||||||||||
California | 25.7 | 20.1 | 5.6 | 28 | % | |||||||
Uinta Basin | 11.0 | 7.6 | 3.4 | 45 | % | |||||||
Permian Basin | 8.4 | 8.2 | 0.2 | 2 | % | |||||||
Piceance Basin | 2.0 | 2.3 | (0.3 | ) | (13 | )% | ||||||
Hugoton Basin | 1.9 | — | 1.9 | — | % | |||||||
East Texas | 1.7 | 2.0 | (0.3 | ) | (15 | )% | ||||||
50.7 | 40.2 | 10.5 | 26 | % | ||||||||
The increase in average daily production volumes in California and the Uinta Basin operating areas primarily reflects development capital spending. The increase in average daily production volumes in the Permian Basin operating area primarily reflects development capital spending partially offset by decreased production volumes related to the properties relinquished in the exchange with ExxonMobil on August 15, 2014. The decrease in average daily production volumes in the Piceance Basin and East Texas operating areas primarily reflects the effects of production declines due to reduced development capital spending. Average daily production volumes in the Hugoton Basin operating area reflect the impact of the properties received in the exchange with ExxonMobil.
Electricity Sales
The following table sets forth selected electricity data:
Successor | Predecessor | ||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | |||||||||
Electricity sales (in thousands) | $ | 31,461 | $ | 27,148 | 16 | % | |||||
Electricity generation expenses (in thousands) | $ | 21,904 | $ | 17,034 | 29 | % | |||||
Electric power produced (Mwh/d) | 2,076 | 1,922 | 8 | % | |||||||
Electric power sold (Mwh/d) | 1,889 | 1,781 | 6 | % | |||||||
Average sales price per Mwh | $ | 63.61 | $ | 55.52 | 15 | % | |||||
Fuel gas cost per MMBtu (including transportation) | $ | 4.77 | $ | 3.70 | 29 | % | |||||
Estimated natural gas volumes consumed to produce electricity (MMBtu/d) (1) | 15,098 | 14,181 | 6 | % | |||||||
(1) | Estimate is based on the historical allocation of fuel costs to electricity. |
27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Electricity sales increased by approximately $4 million or 16% to approximately $31 million for the nine months ended September 30, 2014, from approximately $27 million for the nine months ended September 30 2013, primarily due to an increase in the average sales price of electricity and electric power sold during the period.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $23 million for the nine months ended September 30, 2014, compared to losses of approximately $10 million for the nine months ended September 30, 2013, representing a variance of approximately $33 million. Gains on oil and natural gas derivatives were primarily due to the changes in fair value of the derivative contracts during the period partially offset by higher cash settlement payments during the period. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 5 and Note 6 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” in “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Sales of third-party natural gas are recorded as marketing revenues. Marketing and other revenues increased by approximately $2 million or 32% to approximately $9 million for the nine months ended September 30, 2014, from approximately $7 million for the nine months ended September 30, 2013, primarily due to an increase in natural gas prices during the first quarter of 2014.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $33 million or 14% to approximately $267 million for the nine months ended September 30, 2014, from approximately $234 million for the nine months ended September 30, 2013. Lease operating expenses increased primarily due to an increase in steam costs caused by a higher price and volume of natural gas used in steam generation. Lease operating expenses per BOE decreased to $19.30 per BOE for the nine months ended September 30, 2014, from $21.33 per BOE for the nine months ended September 30, 2013, primarily due to higher production volumes.
The following table sets forth steam information:
Successor | Predecessor | ||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | |||||||||
Average net volume of steam injected (Bbls/d) | 245,329 | 195,566 | 25 | % | |||||||
Fuel gas cost per MMBtu (including transportation) | $ | 4.77 | $ | 3.70 | 29 | % | |||||
Estimated natural gas volumes consumed to produce steam (MMBtu/d) | 87,742 | 67,179 | 31 | % | |||||||
Electricity Generation Expenses
Electricity generation expenses increased by approximately $5 million or 29% to approximately $22 million for the nine months ended September 30, 2014, from approximately $17 million for the nine months ended September 30, 2013, primarily due to increases in fuel gas cost and fuel gas volumes purchased.
28
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Transportation Expenses
Transportation expenses increased by approximately $4 million or 17% to approximately $29 million for the nine months ended September 30, 2014, from approximately $25 million for the nine months ended September 30, 2013, primarily due to increased production volumes in the Uinta Basin partially offset by favorable marketing contract adjustments.
Marketing Expenses
Marketing expenses primarily represent third-party activities associated with the Company’s long-term firm transportation contracts. The Company’s current production is insufficient to fully utilize its capacity. To optimize its remaining capacity, the Company purchases third-party natural gas at the market rate in its producing areas and utilizes asset management agreements. Purchases of third-party natural gas are recorded as marketing expenses. Marketing expenses increased by approximately $1 million or 9% to approximately $7 million for the nine months ended September 30, 2014, from approximately $6 million for the nine months ended September 30, 2013, primarily due to an increase in natural gas prices during the first quarter of 2014.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations. General and administrative expenses increased by approximately $29 million or 49% to approximately $88 million for the nine months ended September 30, 2014, from approximately $59 million for the nine months ended September 30, 2013. The increase was primarily due to higher share-based compensation allocated to the Company by LOI during the first quarter of 2014, as well as higher personnel expenses, transition expenses, professional services expenses and various other administrative expenses. General and administrative expenses per BOE also increased to $6.39 per BOE for the nine months ended September 30, 2014, from $5.41 per BOE for the nine months ended September 30, 2013.
Exploration Costs
The Company recorded no exploration costs for the nine months ended September 30, 2014. For the nine months ended September 30, 2013, the Company recorded exploration costs of approximately $6 million primarily related to the expiration of certain undeveloped leases in the Permian Basin.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased by approximately $14 million or 7% to approximately $226 million for the nine months ended September 30, 2014, from approximately $212 million for the nine months ended September 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per BOE decreased to $16.34 per BOE for the nine months ended September 30, 2014, from $19.33 per BOE for the nine months ended September 30, 2013, primarily due to a lower oil and natural gas properties basis as a result of the adjustment made to record the properties at fair value on December 16, 2013, the acquisition date.
Taxes, Other Than Income Taxes
Successor | Predecessor | |||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Severance taxes | $ | 19,429 | $ | 13,534 | $ | 5,895 | ||||||
Ad valorem taxes | 38,882 | 19,314 | 19,568 | |||||||||
California carbon allowances | 13,002 | 10,013 | 2,989 | |||||||||
Other | 25 | — | 25 | |||||||||
$ | 71,338 | $ | 42,861 | $ | 28,477 | |||||||
Taxes, other than income taxes increased by approximately $28 million or 66% for the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to an adjustment to the taxable property basis in California in connection with the LINN Energy transaction. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed.
29
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
(Gains) Losses on Sale of Assets and Other, Net
During the nine months ended September 30, 2014, the Company recorded a net loss of approximately $49 million on the noncash exchange of a portion of its Permian Basin properties to ExxonMobil for properties in the Hugoton Basin (see Note 2).
Other Income and (Expenses)
Successor | Predecessor | |||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Interest expense, net of amounts capitalized | $ | (66,555 | ) | $ | (74,562 | ) | $ | 8,007 | ||||
Other, net | (813 | ) | 70 | (883 | ) | |||||||
$ | (67,368 | ) | $ | (74,492 | ) | $ | 7,124 | |||||
Other income and (expenses) decreased by approximately $7 million for the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. Interest expense decreased primarily due to the amortization of premiums related to the Company’s debt being recorded at fair value on December 16, 2013, the acquisition date, partially offset by higher outstanding debt during the period. See “Debt” in “Liquidity and Capital Resources” below for additional details.
Income Tax Expense
Effective December 16, 2013, the Company became a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes, and therefore, recognition has not been given to federal and state income taxes for the operations of the Company. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. The Company recognized an income tax expense of approximately $77,000 for the nine months ended September 30, 2014, compared to income tax expense of approximately $73 million for the nine months ended September 30, 2013. The decrease was primarily due to the Company’s conversion from a Subchapter C-corporation to a limited liability company in connection with the LINN Energy transaction.
Net Income
Net income increased by approximately $152 million or 125% to approximately $274 million for the nine months ended September 30, 2014, from approximately $122 million for the nine months ended September 30, 2013. The increase was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher expenses. See discussions above for explanations of variances.
Liquidity and Capital Resources
The Company has utilized funds from debt offerings, borrowings under its Credit Facility and net cash provided by operating activities for capital resources and liquidity. Historically, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the nine months ended September 30, 2014, the Company’s total capital expenditures were approximately $438 million. LINN Energy continually evaluates the capital needs of the Company along with those of its other operating areas. LINN Energy establishes a capital plan each calendar year for all of its operations based on development opportunities and the expected cash flow from operations for that year. The capital plan may be revised during the year as a result of drilling outcomes or significant changes in cash flows. To the extent net cash provided by operating activities is higher or lower than currently anticipated, LINN Energy may adjust the Company’s capital plan accordingly or adjust borrowings under the Company’s Credit Facility, as needed. However, at September 30, 2014, the Company had less than $1 million of available borrowing capacity under its Credit Facility.
LINN Energy continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in adding reserves from its drilling program. The Company’s Credit Facility and indentures governing its senior notes impose certain restrictions on the Company’s ability to obtain additional debt financing. Following the LINN Energy transaction, the Company does not intend to obtain additional borrowing capacity under its Credit Facility or access the capital markets separately from LINN Energy. The Company intends to finance its operations, including
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
its future capital expenditures, with net cash provided by operating activities and funding from LINN Energy. The Company believes such resources will be sufficient to conduct the Company’s business and operations.
Any cash generated by the Company is currently being used by the Company to fund its activities and is not currently being distributed to LINN Energy for further distribution to its unitholders. To the extent that the Company generates cash in excess of its needs, the indentures governing its senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and the Company may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Company’s indentures. The Company’s restricted payments basket was approximately $314 million at September 30, 2014, and may be increased in accordance with the terms of the Company’s indentures by, among other things, 50% of the Company’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
Statements of Cash Flows
The following is a comparative cash flow summary:
Successor | Predecessor | |||||||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | Variance | ||||||||||
(in thousands) | ||||||||||||
Net cash: | ||||||||||||
Provided by operating activities | $ | 443,190 | $ | 405,306 | $ | 37,884 | ||||||
Used in investing activities | (438,000 | ) | (442,460 | ) | 4,460 | |||||||
Provided by (used in) financing activities | (49,655 | ) | 60,897 | (110,552 | ) | |||||||
Net increase (decrease) in cash and cash equivalents | $ | (44,465 | ) | $ | 23,743 | $ | (68,208 | ) | ||||
Operating Activities
Cash provided by operating activities for the nine months ended September 30, 2014, was approximately $443 million, compared to approximately $405 million for the nine months ended September 30, 2013. The increase was primarily due to higher production related revenues principally due to increased oil and natural gas production volumes and higher natural gas and NGL prices, partially offset by higher expenses and higher cash settlement payments on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2014 | Nine Months Ended September 30, 2013 | |||||||
(in thousands) | ||||||||
Cash flow from investing activities: | ||||||||
Property acquisitions | $ | — | $ | (3,367 | ) | |||
Capital expenditures | (438,256 | ) | (450,623 | ) | ||||
Proceeds from sale of properties and equipment and other | 256 | 11,530 | ||||||
$ | (438,000 | ) | $ | (442,460 | ) | |||
The primary use of cash in investing activities is for the development of the Company’s oil and natural gas properties. Capital expenditures decreased primarily due to lower spending on development activities during 2014.
Financing Activities
Cash used in financing activities of approximately $50 million for the nine months ended September 30, 2014, was primarily related to cash distributions of approximately $42 million and $10 million made to LINN Energy during the second and third
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
quarters of 2014, respectively. Cash provided by financing activities for the nine months ended September 30, 2013, included net borrowings of approximately $73 million under the Company’s Credit Facility.
Debt
The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At September 30, 2014, lender commitments under the facility were $1.2 billion but the Company had less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants, among other items, and in April 2014, the Company entered into an amendment to the Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.
As of September 30, 2014, the Company was in compliance with all financial and other covenants of its Credit Facility. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected. For information related to the Credit Facility, see Note 4.
In February 2014, in accordance with the indentures related to the senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of its June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes, respectively.
On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 11).
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Off-Balance Sheet Arrangements
The Company does not currently have any off-balance sheet arrangements.
Contingencies
See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Commitments and Contractual Obligations
The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2013 Annual Report on Form 10-K. With the exceptions of: (i) the Company’s payment of the remaining outstanding principal amount of the June 2014 Senior Notes and (ii) an amendment to the Company’s Credit Facility that extended the maturity date from May 2016 to April 2019, there have been no significant changes to the Company’s contractual obligations from December 31, 2013. See Note 4 for additional information about the Company’s debt instruments.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based upon the condensed financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1 of Notes to Condensed Financial Statements.
Cautionary Statement
This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include content about the Company’s:
• | business strategy; |
• | financial strategy; |
• | ability to obtain additional funding from LINN Energy; |
• | effects of legal proceedings; |
• | drilling locations; |
• | oil, natural gas and NGL reserves; |
• | realized oil, natural gas and NGL prices; |
• | production volumes; |
• | capital expenditures; |
• | economic and competitive advantages; |
• | credit and capital market conditions; |
• | regulatory changes; |
• | lease operating expenses, general and administrative expenses and development costs; |
• | future operating results; |
• | plans, objectives, expectations and intentions; and |
• | integration of the assets and operations acquired in the properties exchanges, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business. |
All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the forward-looking statements or events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2013, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2013 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Financial Statements contained in Item 1. “Financial Statements.”
Commodity Price Risk
An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and, from time to time, natural gas and provide long-term cash flow predictability to manage its business. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. Put options are designed to provide a fixed price floor with the opportunity for upside.
The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of derivatives contracts, the level of LINN Energy’s acquisition activity and overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time.
At September 30, 2014, the fair value of fixed price swaps, collars and three-way collars was a net asset of approximately $11 million. A 10% increase in the index oil price above the September 30, 2014, price would result in a net liability of approximately $10 million, which represents a decrease in the fair value of approximately $21 million; conversely, a 10% decrease in the index oil price below the September 30, 2014, price would result in a net asset of approximately $36 million, which represents an increase in the fair value of approximately $25 million. At September 30, 2014, the Company had no outstanding natural gas derivative instruments.
At December 31, 2013, the fair value of fixed price swaps, collars and three-way collars was a net liability of approximately $6 million. A 10% increase in the index oil price above the December 31, 2013, price would result in a net liability of approximately $83 million, which represents a decrease in the fair value of approximately $77 million; conversely, a 10% decrease in the index oil price below the December 31, 2013, price would result in a net asset of approximately $67 million, which represents an increase in the fair value of approximately $73 million. At December 31, 2013, the Company had no outstanding natural gas derivative instruments.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the
data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at September 30, 2014, and December 31, 2013, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.
The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flow and ability to pay distributions could be impacted.
Interest Rate Risk
At September 30, 2014, and December 31, 2013, the Company had long-term debt outstanding under its Credit Facility of approximately $1.2 billion which incurred interest at floating rates (see Note 4). A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $12 million increase in annual interest expense.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 6). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.
At September 30, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.84%. A 1% increase in the average public bond yield spread would result in no significant increase or decrease in net income for the nine months ended September 30, 2014. At September 30, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0.12% and 0.46%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $111,000 decrease in net income for the nine months ended September 30, 2014.
At December 31, 2013, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 0.91%. A 1% increase in the average public bond yield spread would result in an estimated $169,000 increase in net income for the year ended December 31, 2013. At December 31, 2013, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0.17% and 0.38%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $98,000 decrease in net income for the year ended December 31, 2013.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and LINN Energy’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the
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period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2014.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
There were no changes in the Company’s internal controls over financial reporting during the third quarter of 2014 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting. LINN Energy continues to integrate certain business operations, information systems, processes and related internal control over financial reporting as a result of the acquisition of the Company. The Company will continue to assess the effectiveness of its internal control over financial reporting as integration activities continue.
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Part II – Other Information
Item 1. Legal Proceedings
Department of the Interior Notice of Proposed Debarment
In June 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (“DOI”). Pursuant to the notice, the DOI’s Office of the Inspector General proposed to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company’s purported noncompliance with Bureau of Land Management (“BLM”) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2 million civil penalty relating to the matter. The Company contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The independent compliance review has concluded and the final compliance review reports have been submitted to the DOI. The Company has been informed that DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.
Royalty Class Action
The Company is a defendant in a certain statewide royalty class action case in which the parties have entered into a settlement agreement to settle past claims for approximately $2.4 million. Subject to approval of the settlement agreement by the court, the Company anticipates distribution of settlement funds to begin in the fourth quarter of 2014.
Other
The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material adverse effect on its business, financial condition, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 1A. Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, results of operations or liquidity are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013. As of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.
Item 3. Defaults Upon Senior Securities
This item is intentionally omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10‑Q.
Item 4. Mine Safety Disclosures
Not applicable
Item 5. Other Information
None
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Item 6. Exhibits
Exhibit Number | Description | |
2.1† | Exchange Agreement by and among Linn Energy Holdings, LLC, Berry Petroleum Company, LLC and Exxon Mobil Corporation, dated as of September 18, 2014 (incorporated herein by reference to Exhibit 2.1 to Linn Energy, LLC’s Quarterly Report on Form 10-Q filed on November 4, 2014) | |
2.2*† | Purchase and Sale Agreement by and among Berry Petroleum Company, LLC d/b/a in the State of Texas as Berry Oil Company and Linn Operating, Inc., as Seller, and EIGF TE GP Resource Holdings L.P., FDL Capital, LLC, and KNR Resource Holdings I L.P., as Buyers, executed on October 1, 2014 | |
31.1* | Section 302 Certification of Chief Executive Officer | |
31.2* | Section 302 Certification of Chief Financial Officer | |
32.1* | Section 906 Certification of Chief Executive Officer | |
32.2* | Section 906 Certification of Chief Financial Officer | |
101.INS** | XBRL Instance Document | |
101.SCH** | XBRL Taxonomy Extension Schema Document | |
101.CAL** | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF** | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB** | XBRL Taxonomy Extension Label Linkbase Data Document | |
101.PRE** | XBRL Taxonomy Extension Presentation Linkbase Document | |
* | Filed herewith. |
** | Furnished herewith. |
† | The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S‑K. The Company will furnish copies of such schedules to the Securities and Exchange Commission upon request. |
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SIGNATURE
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, thereto duly authorized.
BERRY PETROLEUM COMPANY, LLC | |
(Registrant) | |
Date: November 12, 2014 | /s/ David B. Rottino |
David B. Rottino Executive Vice President, Business Development and Chief Accounting Officer (As Duly Authorized Officer and Chief Accounting Officer) | |
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