Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2017
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______________ to _______________
Commission file number: 000-51719
LINN ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware | 81-5366183 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
600 Travis Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code
(281) 840-4000
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer ¨ | |
Non-accelerated filer ¨ (Do not check if a smaller reporting company) | Smaller reporting company x | |
Emerging growth company ¨ | ||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ¨ No x
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $1.1 billion on June 30, 2017, based on $30.54 per share, the last reported sales price of the shares on the OTCQB market on such date.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨
As of January 31, 2018, there were 77,229,257 shares of Class A common stock, par value $0.001 per share, outstanding.
Documents Incorporated By Reference:
Certain information called for in Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this Annual Report on Form 10-K.
TABLE OF CONTENTS
Page | ||
i
Glossary of Terms
As commonly used in the oil and natural gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:
Basin. A large area with a relatively thick accumulation of sedimentary rocks.
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
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.
Development well. A well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A stratum of rock that is recognizable from adjacent strata consisting primarily of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per day.
MMMBtu. One billion British thermal units.
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Glossary of Terms - Continued
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
Productive well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves. Reserves that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Royalty interest. An interest that entitles the owner of such interest to a share of the mineral production from a property or to a share of the proceeds there from. It does not contain the rights and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.
Spacing. The number of wells which conservation laws allow to be drilled on a given area of land.
Standardized measure of discounted future net cash flows. The after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the regulations of the Securities and Exchange and discounted using an annual discount rate of 10%.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, natural gas and NGL regardless of whether such acreage contains proved reserves.
Unproved reserves. Reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
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Glossary of Terms - Continued
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Maintenance on a producing well to restore or increase production.
Zone. A stratigraphic interval containing one or more reservoirs.
iv
Part I
Item 1. Business
This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and assumptions as of the date of this filing. These statements by their nature are subject to a number of risks and uncertainties. Actual results may differ materially from those discussed in the forward-looking statements. For more information, see “Cautionary Statement Regarding Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”
References
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. is not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of the Predecessor through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 4). The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Overview
LINN Energy is an independent oil and natural gas company that was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017 (the “Effective Date”).
The Company’s properties are currently located in the United States (“U.S.”), in the Hugoton Basin, east Texas and north Louisiana (“TexLa”), Michigan/Illinois, the Mid-Continent, the Permian Basin and the Rockies. The Company also owns a 50% equity interest in Roan Resources LLC (“Roan”), which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma.
Proved reserves at December 31, 2017, were approximately 1,968 Bcfe, of which approximately 70% were natural gas, 22% were natural gas liquids (“NGL”) and 8% were oil. Approximately 97% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $1.05 billion. At December 31, 2017, the Company operated 10,545 or approximately 66% of its 15,918 gross productive wells.
Strategy
The Company’s current focus is the development of the Merge/SCOOP/STACK through its equity interest in Roan, as well as through its midstream operations in that area. Additionally, the Company is pursuing emerging horizontal opportunities in the Mid-Continent and TexLa regions while continuing to add value by efficiently operating and applying new technology to
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Item 1. Business - Continued
a diverse set of long-life producing assets. Prior to the Company’s emergence from voluntary reorganization under Chapter 11, the Company was an upstream master limited partnership with a strategy to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.
Recent Developments
Strategic Plan to Separate into Three Companies
In December 2017, the Company announced its intention to separate LINN Energy into three standalone companies during 2018. The proposed separation will further maximize shareholder value by giving shareholders focused exposure to three unique companies. The Company is continuing to evaluate the structure and potential tax consequences of any such separation.
Roan Resources LLC. A pure play high growth company focused in the prolific Merge/SCOOP/STACK play. LINN Energy, Inc., which currently trades on the OTCQB market under the ticker LNGG, will serve as a holding company solely for the existing 50 percent equity interest of Roan and would prepare to up list on either the NYSE or NASDAQ in 2018.
Blue Mountain Midstream LLC. A rapidly expanding and highly economic midstream business centered in the core of the Merge. The Board continues to evaluate all options which include, among other things, hiring a separate management team, establishing an independent capital structure, pursuing additional third party acreage dedication, exploring potential strategic alternatives and/or a separate public listing independent from LNGG. The Chisholm Trail Midstream business in the Merge is expected to be the primary asset for Blue Mountain at separation.
“NewCo”. The Company expects to form a new public company comprised of the following assets: Hugoton, Michigan/Illinois, Arkoma, Northwest STACK, East Texas and North Louisiana. “NewCo” is expected to be unlevered and generate significant free cash flow with a strategic focus on developing its growth oriented assets and returning capital to shareholders.
Divestitures
Below are the Company’s completed divestitures in 2017:
• | On November 30, 2017, the Company completed the sale of its interest in properties located in the Williston Basin (the “Williston Assets Sale”). Cash proceeds received from the sale of these properties were approximately $255 million, net of costs to sell of approximately $3 million, and the Company recognized a net gain of approximately $116 million. |
• | On November 30, 2017, the Company completed the sale of its interest in properties located in Wyoming (the “Washakie Assets Sale”). Cash proceeds received from the sale of these properties were approximately $193 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $175 million. |
• | On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certain properties located in south Texas (the “South Texas Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $48 million, net of costs to sell of approximately $1 million, and the Company recognized a combined net gain of approximately $14 million. |
• | On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million. |
• | On July 31, 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin in California (the “San Joaquin Basin Sale”). Cash proceeds received from the sale of these properties were |
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Item 1. Business - Continued
approximately $253 million, net of costs to sell of approximately $4 million, and the Company recognized a net gain of approximately $120 million.
• | On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $2 million. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year from the date of sale. |
• | On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $73 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $30 million. |
• | On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $559 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $277 million. |
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its consolidated financial statements.
Divestitures – Pending
On February 13, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in conventional properties located in west Texas for a contract price of $119.5 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On January 15, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Altamont Bluebell Field in Utah for a contract price of $132 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On December 18, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its Oklahoma waterflood and Texas Panhandle properties for a contract price of $122 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
The Company continues to market its remaining assets located in the Permian Basin and the Drunkards Wash Field in Utah.
Roan Contribution
On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. As of August 31, 2017, the date of the Roan Contribution, the Company recognized its equity investment at a carryover basis of approximately $452 million.
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Item 1. Business - Continued
Construction of Cryogenic Plant
In July 2017 the Company renamed its subsidiary LINN Midstream, LLC to Blue Mountain Midstream LLC (“Blue Mountain”) and entered into a definitive agreement with BCCK Engineering, Inc. (“BCCK”) to construct the Chisholm Trail Cryogenic Gas Plant. Blue Mountain’s assets include the Chisholm Trail midstream business (“Chisholm Trail”) located in Oklahoma. Chisholm Trail is located in the Merge/SCOOP/STACK play in the Mid-Continent region and has approximately 30 miles of existing natural gas gathering pipeline and approximately 60 MMcf/d of current refrigeration capacity. Infrastructure expansions are underway to add 35 miles of low pressure gathering pipelines, increase compression throughput and construct a new 225 MMcf/d cryogenic natural gas processing facility with a total capacity of 250 MMcf/d. The Chisholm Trail Cryogenic Gas Plant is expected to be commissioned during the second quarter of 2018.
2018 Oil and Natural Gas Capital Budget
For 2018, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $134 million, including approximately $34 million related to its oil and natural gas capital program and approximately $98 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Financing Activities
Tender Offer
On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of the tender offer).
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million, and on October 4, 2017, the Company’s Board authorized another increase up to a total of $400 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Company’s Revolving Credit Facility (as defined below). In accordance with the SEC’s regulations regarding issuer tender offers, the Company’s share repurchase program was suspended concurrent with the December 14, 2017, announcement of the intent to commence a tender offer. The program was resumed in February 2018 following the expiration of the tender offer.
During the period from June 2017 through December 2017, the Company repurchased an aggregate of 5,690,192 shares of Class A common stock at an average price of $34.85 per share for a total cost of approximately $198 million. At January 31, 2018, approximately $202 million was available for share repurchases under the program.
Revolving Credit Facility
On August 4, 2017, the Company entered into a credit agreement with Holdco II (as defined below), as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million. The maximum commitment amount was $425 million at December 31, 2017. See Note 6 for additional information about the Revolving Credit Facility.
As of December 31, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $381 million of available borrowing capacity (which includes a $44 million reduction for outstanding letters of credit). The maturity date is August 4, 2020.
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Item 1. Business - Continued
Listing on the OTCQB Market
On the Effective Date, the Predecessor’s units were canceled and ceased to trade on the OTC Markets Group Inc.’s Pink marketplace. In April 2017, the Successor’s Class A common stock was approved for trading on the OTCQB market under the symbol “LNGG.”
Operating Regions
The Company’s properties are currently located in six operating regions in the U.S.:
• | Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; |
• | TexLa, which includes properties located in east Texas and north Louisiana; |
• | Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; |
• | Mid-Continent, which includes Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform; |
• | Permian Basin, which includes properties located in west Texas and southeast New Mexico; and |
• | Rockies, which includes Utah properties located in the Uinta Basin. |
The Company also owns a 50% equity interest in Roan, which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma. During 2017, the Company divested of its properties located in previous operating regions California and South Texas. See above and Note 4 for details of the Company’s divestitures.
Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in southwest Kansas extending through the Oklahoma Panhandle into the central portion of the Texas Panhandle. The sale of the Company’s Texas Panhandle properties is currently pending and is anticipated to close in the first quarter of 2018, subject to closing conditions. The Company’s Kansas and Oklahoma Panhandle properties primarily produce from the Council Grove and Chase formations at depths ranging from 2,200 feet to 3,100 feet. The Company’s properties in this region are primarily mature, low-decline natural gas wells.
The Company also owns and operates the Jayhawk natural gas processing plant in southwest Kansas with a capacity of approximately 450 MMcf/d, allowing it to receive maximum value from the liquids-rich natural gas produced in the area. The Company’s production in the area is delivered to the plant via a system of approximately 3,840 miles of pipeline and related facilities operated by the Company, of which approximately 1,165 miles of pipeline are owned by the Company.
Hugoton Basin proved reserves represented approximately 47% of total proved reserves at December 31, 2017, all of which were classified as proved developed. This region produced approximately 166 MMcfe/d of the Company’s 2017 average daily production. During 2017, the Company invested approximately $1 million for plant and pipeline construction activities and approximately $1 million to develop the properties in this region.
TexLa
The TexLa region consists of properties located in east Texas and north Louisiana and primarily produces natural gas from the Cotton Valley, Travis Peak and Bossier Sand formations at depths ranging from 7,000 feet to 12,500 feet. The Company’s properties in this region are primarily mature, low-decline natural gas wells. To more efficiently transport its natural gas in east Texas to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 635 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area.
TexLa proved reserves represented approximately 19% of total proved reserves at December 31, 2017, of which 84% were classified as proved developed. This region produced approximately 82 MMcfe/d of the Company’s 2017 average daily
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Item 1. Business - Continued
production. During 2017, the Company invested approximately $31 million to develop the properties in this region and approximately $8 million in exploration activity.
Michigan/Illinois
The Michigan/Illinois region consists primarily of natural gas properties in the Antrim Shale formation in north Michigan and oil properties in south Illinois. These wells produce at depths ranging from 500 feet to 4,000 feet. To more efficiently transport its natural gas in Michigan to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 1,480 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area.
Michigan/Illinois proved reserves represented approximately 12% of total proved reserves at December 31, 2017, all of which were classified as proved developed. This region produced approximately 29 MMcfe/d of the Company’s 2017 average daily production. During 2017, the Company invested approximately $1 million to develop the properties in this region.
Mid-Continent
The Mid-Continent region consists of Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform. The sale of the Company’s Oklahoma waterflood properties is currently pending and is anticipated to close in the first quarter of 2018, subject to closing conditions. The Company’s properties in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 3,500 feet to 19,000 feet. The Company’s properties in this region are primarily mature, low-decline oil and natural gas wells.
Mid-Continent proved reserves represented approximately 12% of total proved reserves at December 31, 2017, all of which were classified as proved developed. This region produced approximately 98 MMcfe/d of the Company’s 2017 average daily production. During 2017, the Company invested approximately $97 million for plant and pipeline construction activities primarily associated with the Chisholm Trail Cryogenic Gas Plant, approximately $37 million to develop the properties in this region and approximately $111 million in exploration activity.
Permian Basin
The Company’s properties are located in west Texas and southeast New Mexico and are primarily mature, low-decline oil and natural gas wells including several waterflood properties located across the basin. During 2017, the Company divested certain of its properties located in the Permian Basin, and the Company continues to market its remaining assets located in the Permian Basin. Permian Basin proved reserves represented approximately 6% of total proved reserves at December 31, 2017, all of which were classified as proved developed. This region produced approximately 45 MMcfe/d of the Company’s 2017 average daily production. During 2017, the Company invested approximately $2 million to develop the properties in this region.
Rockies
The Rockies region currently consists of Utah properties located in the Uinta Basin. During 2017, the Company divested its properties located in Wyoming (Green River, Washakie and Powder River basins) and North Dakota (Williston Basin). The sale of the Company’s interest in properties located in the Altamont Bluebell Field is currently pending and is anticipated to close in the first quarter of 2018, subject to closing conditions. The Company continues to market its remaining assets located in the Drunkards Wash Field. Rockies proved reserves represented approximately 4% of total proved reserves at December 31, 2017, all of which were classified as proved developed. This region produced approximately 202 MMcfe/d of the Company’s 2017 average daily production. During 2017, the Company invested approximately $48 million to develop the properties in this region.
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Item 1. Business - Continued
Drilling and Acreage
The following table sets forth the wells drilled during the years indicated:
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Gross wells: | ||||||||
Productive | 90 | 211 | 388 | |||||
Dry | — | 1 | 5 | |||||
90 | 212 | 393 | ||||||
Net development wells: | ||||||||
Productive | 12 | 26 | 139 | |||||
Dry | — | — | 1 | |||||
12 | 26 | 140 | ||||||
Net exploratory wells: | ||||||||
Productive | 9 | 7 | 1 | |||||
Dry | — | — | 1 | |||||
9 | 7 | 2 | ||||||
The total wells above exclude 38 gross wells (32 net wells) drilled by the Company in California during the year ended December 31, 2015. There were no wells drilled by the Company in California during the years ended December 31, 2017, or December 31, 2016. The total wells above also exclude 20 and 196 gross wells (18 and 163 net wells) drilled by Berry during the period from January 1, 2016 through December 3, 2016, and the year ended December 31, 2015, respectively.
There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2017, or December 31, 2016. There were two lateral segments added to existing vertical wellbores during the year ended December 31, 2015. As of December 31, 2017, the Company had 17 gross (2 net) wells in progress, and no wells were temporarily suspended.
This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of oil, natural gas or NGL, regardless of whether they generate a reasonable rate of return.
The following table sets forth information about the Company’s drilling locations and net acres of leasehold interests as of December 31, 2017:
Total (1) | ||
Proved undeveloped | 8 | |
Other locations | 4,202 | |
Total drilling locations | 4,210 | |
Leasehold interests – net acres (in thousands) | 2,254 | |
(1) | Does not include optimization projects. |
As shown in the table above, as of December 31, 2017, the Company had 8 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm, DeGolyer and MacNaughton, assigned proved undeveloped
7
Item 1. Business - Continued
reserves as of such date) and the Company had identified 4,202 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that the Company has under existing leases. Successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved. The number of unproved drilling locations that will be reclassified as proved drilling locations will depend on the Company’s drilling program, its commitment to capital and commodity prices.
Productive Wells
The following table sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2017. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline or other connections to commence deliveries. The number of wells below does not include approximately 2,204 gross productive wells in which the Company owns a royalty interest only.
Natural Gas Wells | Oil Wells | Total Wells | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Operated (1) | 7,232 | 6,399 | 3,313 | 3,093 | 10,545 | 9,492 | |||||||||||
Nonoperated (2) | 4,438 | 1,064 | 935 | 98 | 5,373 | 1,162 | |||||||||||
11,670 | 7,463 | 4,248 | 3,191 | 15,918 | 10,654 | ||||||||||||
(1) | The Company had 5 operated wells with multiple completions at December 31, 2017. |
(2) | The Company had 1 nonoperated wells with multiple completions at December 31, 2017. |
Developed and Undeveloped Acreage
The following table sets forth information relating to leasehold acreage as of December 31, 2017:
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
(in thousands) | |||||||||||||||||
Leasehold acreage | 3,621 | 2,245 | 26 | 9 | 3,647 | 2,254 | |||||||||||
Future Acreage Expirations
The Company’s investment in developed and undeveloped acreage comprises numerous leases. The terms and conditions under which the Company maintains exploration or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. If production is not established or the Company takes no other action to extend the terms of the related leases, undeveloped acreage will expire. The Company currently has no material undeveloped acreage due to expire during the next three years.
Programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions. The Company utilizes various methods to manage the expiration of leases, including drilling the acreage prior to lease expiration or extending lease terms.
Production, Price and Cost History
The results of operations of the Company’s California properties and Berry are reported as discontinued operations for all periods presented (see Note 4). Unless otherwise indicated, information presented herein relates only to LINN Energy’s continuing operations.
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Item 1. Business - Continued
The Company’s natural gas production is primarily sold under short-term market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. In certain circumstances, the Company has entered into natural gas processing contracts whereby the residue natural gas is sold under short-term contracts but the related NGL are sold under long-term contracts. In all such cases, the residue natural gas and NGL are sold at market-sensitive index prices. As of December 31, 2017, the Company had natural gas delivery commitments under a long-term contract of approximately 12 Bcf to be delivered in 2018, approximately 16 Bcf to be delivered each year from 2019 through 2025 and approximately 4 Bcf to be delivered in 2026. The Company expects to fulfill these delivery commitments with existing proved developed reserves dedicated to its Blue Mountain midstream business. If production is not sufficient to meet contractual delivery commitments, the Company may be subject to shortfall penalties. As of December 31, 2017, the Company had no NGL delivery commitments under long-term contracts.
The Company’s natural gas production is sold to purchasers under spot price contracts, percentage-of-index contracts or percentage-of-proceeds contracts. Under percentage-of-index contracts, the Company receives a price for natural gas and NGL based on indexes published for the producing area. Under percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residue natural gas and NGL recovered after transportation and processing of natural gas. These purchasers sell the residue natural gas and NGL based primarily on spot market prices.
The Company’s natural gas is transported through its own and third-party gathering systems and pipelines. The Company incurs processing, gathering and transportation expenses to move its natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume, distance shipped and the fee charged by the third-party processor or transporter.
The Company’s oil production is primarily sold under short-term market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. As of December 31, 2017, the Company had no oil delivery commitments under long-term contracts.
The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the years indicated:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
Total production: | ||||||||||||||||
Natural gas (MMcf) | 118,110 | 29,223 | 187,068 | 200,488 | ||||||||||||
Oil (MBbls) | 5,442 | 1,191 | 8,088 | 10,018 | ||||||||||||
NGL (MBbls) | 6,287 | 1,263 | 9,281 | 9,347 | ||||||||||||
Total (MMcfe) | 188,481 | 43,945 | 291,285 | 316,677 | ||||||||||||
Total production – Equity method investments: (1) | ||||||||||||||||
Total (MMcfe) | 9,235 | — | — | — | ||||||||||||
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Item 1. Business - Continued
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
Average daily production: | ||||||||||||||||
Natural gas (MMcf/d) | 386 | 495 | 511 | 549 | ||||||||||||
Oil (MBbls/d) | 17.8 | 20.2 | 22.1 | 27.4 | ||||||||||||
NGL (MBbls/d) | 20.5 | 21.4 | 25.4 | 25.6 | ||||||||||||
Total (MMcfe/d) | 616 | 745 | 796 | 867 | ||||||||||||
Average daily production – Equity method investments: (1) | ||||||||||||||||
Total (MMcfe/d) | 30 | — | — | — | ||||||||||||
Weighted average prices: (2) | ||||||||||||||||
Natural gas (Mcf) | $ | 2.69 | $ | 3.41 | $ | 2.28 | $ | 2.56 | ||||||||
Oil (Bbl) | $ | 47.42 | $ | 49.16 | $ | 39.00 | $ | 43.42 | ||||||||
NGL (Bbl) | $ | 21.28 | $ | 24.37 | $ | 14.26 | $ | 12.66 | ||||||||
Average NYMEX prices: | ||||||||||||||||
Natural gas (MMBtu) | $ | 3.00 | $ | 3.66 | $ | 2.46 | $ | 2.66 | ||||||||
Oil (Bbl) | $ | 50.53 | $ | 53.04 | $ | 43.32 | $ | 48.80 | ||||||||
Costs per Mcfe of production: | ||||||||||||||||
Lease operating expenses | $ | 1.11 | $ | 1.13 | $ | 1.02 | $ | 1.11 | ||||||||
Transportation expenses | $ | 0.60 | $ | 0.59 | $ | 0.55 | $ | 0.53 | ||||||||
General and administrative expenses (3) | $ | 0.62 | $ | 1.63 | $ | 0.82 | $ | 0.90 | ||||||||
Depreciation, depletion and amortization | $ | 0.71 | $ | 1.07 | $ | 1.18 | $ | 1.64 | ||||||||
Taxes, other than income taxes | $ | 0.25 | $ | 0.34 | $ | 0.23 | $ | 0.31 | ||||||||
Total production – Discontinued operations: (4) | ||||||||||||||||
Total (MMcfe) | 4,326 | 1,755 | 92,437 | 116,909 | ||||||||||||
(1) | Represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017. |
(2) | Does not include the effect of gains (losses) on derivatives. |
(3) | General and administrative expenses for the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended December 31, 2016, and December 31, 2015, include approximately $41 million, $50 million, $34 million and $47 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the two months ended February 28, 2017, and the years ended December 31, 2016, and December 31, 2015, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
(4) | Total production of the Company’s California properties reported as discontinued operations for 2017 is for the period from January 1, 2017 through July 31, 2017. Total production of Berry reported as discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
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Item 1. Business - Continued
The following table sets forth information regarding production volumes for fields with greater than 15% of the Company’s total proved reserves for each of the years indicated:
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Total production: | ||||||||
Hugoton Basin Field: | ||||||||
Natural gas (MMcf) | 34,363 | 38,501 | 41,294 | |||||
Oil (MBbls) | 45 | 27 | 21 | |||||
NGL (MBbls) | 2,968 | 2,983 | 3,061 | |||||
Total (MMcfe) | 52,437 | 56,566 | 59,787 | |||||
Green River Basin Field: | ||||||||
Natural gas (MMcf) | * | 44,668 | * | |||||
Oil (MBbls) | * | 477 | * | |||||
NGL (MBbls) | * | 1,349 | * | |||||
Total (MMcfe) | * | 55,625 | * | |||||
* | Represented less than 15% of the Company’s total proved reserves for the year indicated. The Company sold its properties in the Green River Basin Field in May 2017. |
Reserve Data
Proved Reserves
The following table sets forth estimated proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2017, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton:
Proved Reserves | |||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total (Bcfe) | ||||||||
Proved reserves – LINN Energy: | |||||||||||
Proved developed reserves | 1,323 | 27.0 | 70.5 | 1,908 | |||||||
Proved undeveloped reserves | 54 | 0.1 | 1.0 | 60 | |||||||
Total proved reserves | 1,377 | 27.1 | 71.5 | 1,968 | |||||||
Proved reserves – Equity method investments: (1) | |||||||||||
Proved developed reserves | 130 | 6.2 | 12.0 | 239 | |||||||
Proved undeveloped reserves | 213 | 12.5 | 27.8 | 455 | |||||||
Total proved reserves | 343 | 18.7 | 39.8 | 694 | |||||||
Standardized measure of discounted future net cash flows (in millions): (2) | |||
LINN Energy | $ | 1,045 | |
Equity Method Investments (1) | $ | 598 | |
Representative NYMEX prices: (3) | |||
Natural gas (MMBtu) | $ | 2.98 | |
Oil (Bbl) | $ | 51.34 | |
(1) | Represents the Company’s 50% equity interest in Roan. |
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Item 1. Business - Continued
(2) | This measure is not intended to represent the market value of estimated reserves. |
(3) | In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
During the year ended December 31, 2017, the Company’s PUDs decreased to 60 Bcfe from 266 at December 31, 2016, representing a decrease of approximately 206 Bcfe. The decrease was primarily due to the sale of approximately 243 Bcfe of PUDs related to the 2017 divestitures and the development of approximately 15 Bcfe of PUDs during 2017, partially offset by approximately 52 Bcfe of PUDs added as a result of the Company’s drilling activities. During the year ended December 31, 2017, the Company incurred approximately $10 million in capital expenditures to convert 52 Bcfe of reserves that were classified as PUDs at December 31, 2016, to proved developed reserves.
Based on the December 31, 2017 reserve reports, the amounts of capital expenditures estimated to be incurred in 2018, 2019 and 2020 to develop the Company’s PUDs are approximately $23 million, $14 million and $14 million, respectively. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices. None of the 60 Bcfe of PUDs at December 31, 2017, has remained undeveloped for five years or more. All PUD properties are included in the Company’s current five-year development plan.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGL that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions regarding the timing of future production, which may prove to be inaccurate.
The reserve estimates reported herein were prepared by independent engineers, DeGolyer and MacNaughton. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company. When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by the Company with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by the Company’s Corporate Reserves Manager, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 30 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer. Reserve estimates of Roan were reviewed and approved by Roan’s President and Chief Executive Officer. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.” The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.
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Item 1. Business - Continued
Operational Overview
General
The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects intended to not only replace production, but also to add value through reserve and production growth and future operational synergies. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.
Principal Customers
For the year ended December 31, 2017, no individual customer exceeded 10% of the Company’s sales of oil, natural gas and NGL. If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area. If the Company were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of the large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the prices and volumes of oil, natural gas and NGL that the Company is able to sell.
Competition
The oil and natural gas industry is highly competitive. The Company encounters strong competition from other independent operators in contracting for drilling and other related services, as well as hiring trained personnel. The Company is also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. The Company is unable to predict when, or if, such shortages may occur or how they would affect its drilling program.
Operating Hazards and Insurance
The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. The Company may be liable for environmental damages caused by previous owners of property it purchases and leases. As a result, the Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds otherwise available, or result in the loss of properties. In addition, the Company participates in wells on a nonoperated basis, as well as through its equity method investment in Roan, and therefore may be limited in its ability to control the risks associated with the operation of such wells.
In accordance with customary industry practices, the Company maintains insurance against some, but not all, potential losses. The Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities. The Company has elected to self-insure for certain items for which it has determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on the Company’s financial position, results of operations and cash flows. For more information about potential risks that could affect the Company, see Item 1A. “Risk Factors.”
Title to Properties
Prior to the commencement of drilling operations, the Company conducts a title examination and performs curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations. Prior to completing an acquisition of producing leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions. As a result, the Company has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry.
13
Item 1. Business - Continued
Seasonal Nature of Business
Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the U.S. in which the Company operates. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, Company operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.
The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.
Environmental Matters and Regulation
The Company’s operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company’s operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations may:
• | require the acquisition of various permits before drilling commences; |
• | require notice to stakeholders of proposed and ongoing operations; |
• | require the installation of expensive pollution control equipment; |
• | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; |
• | limit or prohibit drilling activities on lands located within wilderness, wetlands, areas inhabited by endangered species and other protected areas; |
• | require remedial measures to prevent pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells; |
• | impose substantial liabilities for pollution resulting from operations; and |
• | require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases. |
These laws and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary fines or penalties, the imposition of investigatory or remedial requirements, and the issuance of orders enjoining future operations. Moreover, accidental releases or spills may occur in the course of the Company’s operations, which may result in significant costs and liabilities, including third-party claims for damage to property, natural resources or persons. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly requirements for the oil and natural gas industry could have a significant impact on operating costs.
The environmental laws and regulations applicable to the Company and its operations include, among others, the following U.S. federal laws and regulations:
• | Clean Air Act (“CAA”), which governs air emissions; |
• | Clean Water Act (“CWA”), which governs discharges to and excavations within the waters of the U.S.; |
• | Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”); |
• | The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills; |
• | Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures; |
14
Item 1. Business - Continued
• | National Environmental Policy Act (“NEPA”), which governs oil and natural gas production activities on federal lands; |
• | Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste; |
• | Safe Drinking Water Act (“SDWA”), which governs the underground injection and disposal of wastewater; |
• | Endangered Species Act (“ESA”), which restricts activities that may affect endangered and threatened species or their habitats; and |
• | U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages. |
Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGL that may be produced from the Company’s wells and to limit the number of wells or locations it can drill. The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment.
The Company believes that it substantially complies with all current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, financial condition, results of operations or cash flows. Future regulatory issues that could impact the Company include new rules or legislation relating to the items discussed below.
Climate Change
In December 2009, the U.S. Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In May 2016, the EPA finalized rules that set additional emissions limits for volatile organic compounds and established new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rules include first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In June 2017, EPA issued a proposal to stay certain of these requirements for two years and reconsider the entirety of the 2016 rules; however, the rules currently remain in effect. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. In addition, in 2015, the U.S. participated in the United Nations Climate Change Conference, which led to the creation of the Paris Agreement. The Paris Agreement requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. In June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. Legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the U.S., and a number of states have begun taking actions to control and/or reduce emissions of GHGs.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause the Company to incur significant costs in preparing for or responding to those effects.
15
Item 1. Business - Continued
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Company performs hydraulic fracturing as part of its operations. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, in February 2014, EPA published permitting guidance under the SDWA addressing the use of diesel in fracturing hydraulic operations, and in May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, in March 2015, the Department of the Interior’s Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and strengthening standards for well-bore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. Following years of litigation, the BLM rescinded the rule in December 2017. However, in January 2018, California and several environmental groups filed lawsuits challenging BLM’s rescission of the rule; those lawsuits are pending in the U.S. District Court for the Northern District of California. In addition, from time to time legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.
There may be other attempts to further regulate hydraulic fracturing under the SDWA, TSCA and/or other statutory or regulatory mechanisms. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Moreover, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, many states in which the Company operates have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. In addition, the regulation or prohibition of hydraulic fracturing is the subject of significant political activity in a number of jurisdictions, some of which have resulted in tighter regulation, bans, and/or recognition of local government authority to implement such restrictions. In many instances, litigation has ensued, some of which remains pending. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for the Company to perform fracturing to stimulate production from tight formations. In addition, any such additional regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect the Company’s revenues, results of operations and net cash provided by operating activities.
Hydraulic fracturing operations require the use of a significant amount of water. The Company’s inability to locate sufficient amounts of water, or dispose of or recycle water used in its drilling and production operations, could adversely impact its operations. Moreover, new environmental initiatives and regulations could include restrictions on the Company’s ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes in some of the states where the Company operates. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect the Company, either directly or indirectly, depending on the wells affected.
Solid and Hazardous Waste
Although oil and natural gas wastes generally are exempt from regulation as hazardous wastes under RCRA and some comparable state statutes, it is possible some wastes the Company generates presently or in the future may be subject to regulation under RCRA or other applicable statutes. The EPA and various state agencies have limited the disposal options for
16
Item 1. Business - Continued
certain wastes, including hazardous wastes, and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. For example, in December 2016, the EPA and several environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If the EPA proposes revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Furthermore, certain wastes generated by the Company’s oil and natural gas operations that are currently exempt from designation as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.
In addition, CERCLA, also known as the Superfund law, imposes cleanup obligations, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed of or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While petroleum and crude oil fractions are not included in the definition of hazardous substances under CERCLA and some of its state analogs because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances under CERCLA in the past.
Endangered Species Act
Some of the Company’s operations may be located in areas that are designated as habitats for endangered or threatened species under the ESA. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues to make listing decisions and critical habitat designations where necessary, including for over 250 species as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The Company believes that it is currently in substantial compliance with the ESA. However, the designation of previously unprotected species as being endangered or threatened, if located in the areas of the Company’s operations, could cause the Company to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.
Air Emissions
In August 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. These standards require operators to capture the gas from natural gas well completions and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and existing wells that are refractured. Further, the rules also establish specific requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The EPA amended these rules in December 2014 to specify requirements for different flowback stages and to expand the rules to cover more storage vessels, among other changes. These rules may require changes to the Company’s operations, including the installation of new equipment to control emissions.
The Company’s costs for environmental compliance may increase in the future based on new environmental regulations. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands. In December 2017, the BLM finalized a suspension of certain requirements of the rules until
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Item 1. Business - Continued
2019. However, California, New Mexico, and several environmental groups filed lawsuits challenging BLM’s suspension of the rules; those lawsuits are pending in the U.S. District Court for the Northern District of California. Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. The EPA has also adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Further, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion in October 2015 and has announced that it intends to complete most initial area designations under the standard by April 30, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements or delay, or limit the Company’s ability to obtain permits, and result in increased expenditures for pollution control equipment. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase the Company’s costs of development, which costs could be significant.
Water Resources
The CWA and analogous state laws restrict the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the U.S., a term broadly defined to include, among other things, certain wetlands. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the U.S. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit. In addition, the EPA and the Army Corps of Engineers (“Corps”) released a rule to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, which went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the rule revising the WOTUS definition nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” However, in January 2018, the U.S. Supreme Court ruled that the rule revising the WOTUS definition must be reviewed first in the federal district courts, which may result in a withdrawal of the stay by the Sixth Circuit. In addition, the EPA has proposed to repeal the rule revising the WOTUS definition, and in January 2018 the EPA released a final rule that delays implementation of the rule revising the WOTUS definition until 2020 to allow time for the EPA to reconsider the definition of “waters of the United States.” Several states and environmental groups have since filed lawsuits challenging the delay rule. To the extent the rule revising the WOTUS definition is implemented, it could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements.
Also, in June 2016, the EPA finalized wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works; for certain facilities, compliance is required by August 29, 2019. This pending restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.
Natural Gas Sales and Transportation
Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. The Company believes that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change
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Item 1. Business - Continued
based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of the Company’s natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event the Company’s gathering facilities are reclassified to FERC-regulated transmission services, it may be required to charge lower rates and its revenues could thereby be reduced.
FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers which engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. Should the Company fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, it could be subject to substantial penalties and fines.
Pipeline Safety Regulations
The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to the Company’s pipelines. These determinations may affect the costs the Company incurs in complying with applicable safety regulations.
Worker Safety
The Occupational Safety and Health Act (“OSHA”) and analogous state laws regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of the Company’s operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
Future Impacts and Current Expenditures
The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2017, the Company did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of its facilities. The Company is not aware of any environmental issues or claims that will require material capital expenditures during 2018 or that will otherwise have a material impact on its financial position, results of operations or cash flows.
Employees
As of December 31, 2017, the Company employed approximately 970 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. The Company believes that its relationship with its employees is satisfactory.
Principal Executive Offices
The Company is a Delaware corporation with headquarters in Houston, Texas. The principal executive offices are located at 600 Travis, Houston, Texas 77002. The main telephone number is (281) 840-4000.
Available Information
The Company’s internet website is www.linnenergy.com. The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to these reports are available free of charge on or through its website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Information on the Company’s website should not be considered a part of, or incorporated by reference into, this Annual Report on Form 10‑K.
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Item 1. Business - Continued
The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Company files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K 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 discussions about the Company’s:
• | business strategy; |
• | acquisition and disposition strategy; |
• | financial strategy; |
• | plans to separate into three standalone companies; |
• | ability to comply with covenants under the Revolving Credit Facility; |
• | 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 |
• | taxes. |
All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1. “Business;” Item 1A. “Risk Factors;” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. 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 Annual Report on Form 10-K 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 Annual Report on Form 10-K are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the 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” and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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Item 1A. Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our shares are described below. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
Business Risks
We emerged from bankruptcy in February 2017, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our emergence from bankruptcy could adversely affect our business and relationships with customers, vendors, royalty and working interest owners, employees, service providers and suppliers. Due to uncertainties, many risks exist, including the following:
• | vendors or other contract counterparties could terminate their relationship or require financial assurances or enhanced performance; |
• | the ability to renew existing contracts and compete for new business may be adversely affected; |
• | the ability to attract, motivate and/or retain key executives and employees may be adversely affected; |
• | employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and |
• | competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted. |
The occurrence of one or more of these events could adversely affect our business, operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
We may be subject to risks in connection with divestitures.
In 2017, we completed divestitures of a significant portion of our non-core assets and we have additional divestitures pending, as discussed in Item 1. “Business – Recent Developments.” In addition, in December 2017, we announced our intention to separate the Company into three standalone companies during 2018, and to continue to strategically divest non-core assets. In connection with these or other future transactions, we may sell our core or non-core assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.
Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Our announced intention to separate into three standalone companies is subject to numerous conditions and risks and there can be no assurance that the separation will be completed or that the expected benefits from the proposed separation to us or our shareholders will be realized.
We have announced an intention to separate into three standalone companies. The legal and tax structure as well as the timing for these separation transactions continue to evolve and there can be no assurance that a transaction will be completed on the proposed timing or at all. In addition, if the proposed separation is completed, such separation could subject shareholders to dividend taxation and/or withholding, or other adverse tax consequences, including under the Foreign Investment in Real Property Tax Act of 1980. We expect that the process of completing the proposed separation will involve
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Item 1A. Risk Factors - Continued
dedication of significant time and resources and the incurrence of significant costs and expenses and there can be no assurance that the expected benefits from the proposed separation to us or our shareholders will be realized.
The ability to identify and attract qualified management teams for the proposed standalone companies is critical and may be difficult to achieve on the proposed timing or at all.
A successful outcome for the proposed separation transactions is dependent upon identifying and attracting management teams for each of the standalone companies. Roan Resources LLC has appointed a Chief Executive Officer and certain other members of its executive management team, but other positions remain open. Active searches and discussions regarding executive management teams for each of the other two proposed standalone companies are ongoing but no decisions have been finalized as to Chief Executive Officer or other critical management positions. The identification and hiring of these management teams is critical to the success of the separation and may delay or impede our ability to complete the separation transactions.
The ability to attract and retain key personnel is critical to the success of our proposed separation transactions and our ongoing business and may be affected by significant uncertainty.
The success of our ongoing business, as well as our ability to consummate the proposed separation transaction, depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
Our financial information after the impact of fresh start accounting and numerous divestitures may not be meaningful to investors.
Upon our emergence from bankruptcy, we adopted fresh start accounting and, as a result, our assets and liabilities were recorded at fair value as of the fresh start reporting date, which differ materially from the recorded values of assets and liabilities on our historical consolidated balance sheets. As a result of the adoption of fresh start accounting, along with the numerous divestitures of properties in 2017, the Company’s historical results of operations and period-to-period comparisons of those results and certain other financial data may not be meaningful or indicative of future results. The lack of comparable historical financial information may discourage investors from purchasing our common stock.
Commodity prices are volatile, and prolonged depressed prices or a further decline in prices would reduce our revenues, profitability and net cash provided by operating activities and would significantly affect our financial condition and results of operations.
Our revenues, profitability, cash flow and the carrying value of our properties depend on the prices of and demand for oil, natural gas and NGL. Historically, the oil, natural gas and NGL markets have been very volatile and are expected to continue to be volatile in the future, and prolonged depressed prices or a further decline in prices will significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our net cash provided by operating activities. In addition, revenues from certain wells may exceed production costs and nevertheless not generate sufficient return on capital. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for them, market uncertainty and a variety of additional factors that are beyond our control, such as:
• | the domestic and foreign supply of and demand for oil, natural gas and NGL; |
• | the price and level of foreign imports; |
• | the level of consumer product demand; |
• | weather conditions; |
• | overall domestic and global economic conditions; |
• | political and economic conditions in oil and natural gas producing and consuming countries; |
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Item 1A. Risk Factors - Continued
• | the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain price and production controls; |
• | the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices; |
• | technological advances affecting energy consumption; |
• | domestic and foreign governmental regulations and taxation; |
• | the impact of energy conservation efforts; |
• | the proximity and capacity of pipelines and other transportation facilities; and |
• | the price and availability of alternative fuels. |
Prolonged depressed prices or a further decline in prices would reduce our revenues, profitability and net cash provided by operating activities and would significantly affect our financial condition and results of operations.
Future declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in the period incurred.
We evaluate the impairment of our oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Future declines in oil, natural gas and NGL prices, changes in expected capital development, increases in operating costs or adverse changes in well performance, among other things, may result in us having to make material write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in the period incurred.
Disruptions in the capital and credit markets, continued low commodity prices and other factors may restrict our ability to raise capital on favorable terms, or at all.
Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy, and in certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business and financial condition.
We may not be able to obtain funding under the Revolving Credit Facility because of a decrease in our borrowing base, or obtain new financing, which could adversely affect our operations and financial condition.
On August 4, 2017, the Company entered into a senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million. The maximum commitment amount was $425 million at December 31, 2017. As of December 31, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $381 million of available borrowing capacity (which includes a $44 million reduction for outstanding letters of credit).
Redetermination of the borrowing base under the Revolving Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October, with the first scheduled borrowing base redetermination to occur on March 15, 2018. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the Revolving Credit Facility exceeding the borrowing base, we will be required to repay the deficiency. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under the Revolving Credit Facility, which could result in an event of default.
In the future, we may not be able to access adequate funding under the Revolving Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under the Revolving Credit Facility involves evaluating the estimated value of some of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at
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Item 1A. Risk Factors - Continued
the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.
Our Revolving Credit Facility also restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If net cash provided by operating activities or cash available under the Revolving Credit Facility is not sufficient to meet our capital requirements, the failure to obtain such additional debt or equity financing could result in a curtailment of our development operations, which in turn could lead to a decline in our reserves.
We may be unable to maintain compliance with the covenants in the Revolving Credit Facility, which could result in an event of default under the Revolving Credit Facility that, if not cured or waived, would have a material adverse effect on our business and financial condition.
Under the Revolving Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0, as well as various affirmative and negative covenants. If we were to violate any of the covenants under the Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under the Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due.
Restrictive covenants in the Revolving Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in the Revolving Credit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:
• | incur additional liens; |
• | incur additional indebtedness; |
• | merge, consolidate or sell our assets; |
• | pay dividends or make other distributions or repurchase or redeem our stock; |
• | make certain investments; and |
• | enter into transactions with our affiliates. |
The Revolving Credit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under our Revolving Credit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under the Revolving Credit Facility may elect to declare all borrowings outstanding thereunder, if any, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under the Revolving Credit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under the Revolving Credit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in the Revolving Credit Facility. The restrictions contained in the Revolving Credit Facility could:
• | limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and |
• | adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest. |
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Item 1A. Risk Factors - Continued
Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our net cash provided by operating activities, financial condition and results of operations.
To achieve more predictable net cash provided by operating activities and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into commodity derivative contracts for a portion of our production. Commodity derivative arrangements expose us to the risk of financial loss in some circumstances, including situations when production is less than expected. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the sale of our underlying physical commodity, which may adversely affect our net cash provided by operating activities, financial condition and results of operations.
We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
While we have hedged a portion of our estimated production for 2018 and 2019, our anticipated production volumes remain mostly unhedged. Based on current expectations for future commodity prices, reduced hedging market liquidity and potential reduced counterparty willingness to enter into new hedges with us, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
Counterparty failure may adversely affect our derivative positions.
We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our net cash provided by operating activities, financial condition and results of operations would be adversely affected.
Unless we replace our reserves, our future reserves and production will decline, which would adversely affect our net cash provided by operating activities, financial condition and results of operations.
Producing oil, natural gas and NGL reservoirs are characterized by declining production rates that vary depending on reservoir characteristics and other factors. The overall rate of decline for our production will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our net cash provided by operating activities, financial condition and results of operations. In addition, given restrictive covenants under our Revolving Credit Facility and general market conditions, we may be unable to finance potential acquisitions of reserves on terms that are acceptable to us or at all. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
No one can measure underground accumulations of oil, natural gas and NGL in an exact manner. Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural gas and NGL prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. An independent petroleum engineering firm prepares estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by
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Item 1A. Risk Factors - Continued
actual amounts could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Decreases in commodity prices can result in a reduction of our estimated reserves if development of those reserves would not be economic at those lower prices. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGL we ultimately recover being different from our reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil, natural gas and NGL reserves. We base the estimated discounted future net cash flows from our proved reserves on an unweighted average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
• | actual prices we receive for oil, natural gas and NGL; |
• | the amount and timing of actual production; |
• | capital and operating expenditures; |
• | the timing and success of development activities; |
• | supply of and demand for oil, natural gas and NGL; and |
• | changes in governmental regulations or taxation. |
In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future net cash flows, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Our development operations require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to sustain our operations at current levels and could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development and production of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for other purposes. Our net cash provided by operating activities and access to capital are subject to a number of variables, including:
• | our proved reserves; |
• | the level of oil, natural gas and NGL we are able to produce from existing wells; |
• | the prices at which we are able to sell our oil, natural gas and NGL; |
• | the level of operating expenses; and |
• | our ability to acquire, locate and produce new reserves. |
If our net cash provided by operating activities decreases, we may have limited ability to obtain the capital or financing necessary to sustain our operations at current levels and could lead to a decline in our reserves.
We may decide not to drill some of the prospects we have identified, and locations that we decide to drill may not yield oil, natural gas and NGL in commercially viable quantities.
Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGL prices, the generation of additional seismic or geological information, the current and future availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects. In addition, the cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, natural gas and NGL to be commercially viable after drilling, operating and other costs. As a result, we may not be able to increase or sustain our reserves or production, which in turn could have an adverse effect on our business, financial condition, results of operations and cash flows.
26
Item 1A. Risk Factors - Continued
Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect our financial position, results of operations and cash flows.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil, natural gas and NGL can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
• | the high cost, shortages or delivery delays of equipment and services; |
• | unexpected operational events; |
• | adverse weather conditions; |
• | facility or equipment malfunctions; |
• | title problems; |
• | pipeline ruptures or spills; |
• | compliance with environmental and other governmental requirements; |
• | unusual or unexpected geological formations; |
• | loss of drilling fluid circulation; |
• | formations with abnormal pressures; |
• | fires; |
• | blowouts, craterings and explosions; and |
• | uncontrollable flows of oil, natural gas and NGL or well fluids. |
Any of these events can cause increased costs or restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling program or significant increase in costs could adversely affect our financial position, results of operations and cash flows.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2017, nonoperated wells represented approximately 34% of our owned gross wells, or approximately 11% of our owned net wells. We have limited ability to influence or control the operation or future development of these nonoperated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues, and lead to unexpected future costs.
We have limited control over the operations of the Roan joint venture, which could adversely affect our business.
We have limited control over the operations of Roan Resources LLC (“Roan”). Although we own a 50% equity interest in Roan, we do not control its board of directors. Because of this limited control:
• | Roan may take actions contrary to our strategy or objectives; |
• | we have limited ability to influence Roan’s financial performance or operating results; |
• | we have limited ability to influence the day to day operations of Roan or its properties, including compliance with environmental, safety and other regulations; and |
• | we are dependent on third parties for financial reporting matters upon which our financial statements are based. |
Since Roan represents a significant investment of ours, adverse developments in Roan’s business could adversely affect our business.
Our business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with our ability to market the oil, natural gas and NGL we produce, which could adversely affect our business, results of operations and cash flows.
27
Item 1A. Risk Factors - Continued
The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering systems and pipelines. The amount of oil, natural gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, natural gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, natural gas and NGL we produce, and could adversely affect our business, results of operations and cash flows.
Regulatory Risks
Because we handle oil, natural gas and NGL and other hydrocarbons, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
The operations of our wells, gathering systems, turbines, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business, the substances we handle and the ownership or operation of our properties. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. In addition, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance. For a more detailed discussion of environmental and regulatory matters impacting our business, see Item 1. “Business – Environmental Matters and Regulation.”
We are subject to complex and evolving federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have resulted in delays and increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil, natural gas and NGL we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the regulatory environment could change in ways that might substantially increase the financial
28
Item 1A. Risk Factors - Continued
and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our financial condition and results of operations. For a description of the laws and regulations that affect us, see Item 1. “Business – Environmental Matters and Regulation.”
We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine emissions, greenhouse gases and hydraulic fracturing. Changes in environmental laws and regulations occur frequently, and any changes that result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements could require significant expenditures by us or other operators of the properties to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations or financial condition. Increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2017‑2019 National Enforcement Initiatives, through which the EPA will purportedly address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.
Legislation and regulation of hydraulic fracturing, including with respect to seismic activity allegedly related to hydraulic fracturing, could adversely affect our business.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. For a description of the laws and regulations that affect us, including our hydraulic fracturing operations, see Item 1. “Business – Environmental Matters and Regulation.” If adopted, certain bills could result in additional permitting and disclosure requirements for hydraulic fracturing operations as well as various restrictions on those operations. Any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our business, financial position, results of operations and net cash provided by operating activities.
Hydraulic fracturing operations require the use of a significant amount of water. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes in some of the states where we operate. Such issues have sometimes led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect us, either directly or indirectly, depending on the wells affected.
Legislation and regulation of greenhouse gases could adversely affect our business, and we are subject to risks associated with climate change.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented regulations to restrict emissions of GHGs under existing provisions of the CAA. In May 2016, the EPA finalized rules that set additional emissions limits for volatile organic compounds and established new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In June 2017, EPA issued a proposal to stay certain of these requirements for two years and reconsider the entirety of the 2016 rules; however, the rules currently remain in effect. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. In addition, in 2015, the U.S. participated in the United Nations Climate Change Conference, which led to the creation of the Paris Agreement. The Paris Agreement requires member countries to review and “represent a
29
Item 1A. Risk Factors - Continued
progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. In June 2017, the United States announced its withdrawal from the Paris Agreement, although the earliest possible effective date of withdrawal is November 2020. Despite the planned withdrawal, certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. Legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the U.S., and a number of states have begun taking actions to control and/or reduce emissions of GHGs. Any such additional regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our business, financial position, results of operations and net cash provided by operating activities.
In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to those effects.
Uncertainty regarding derivatives legislation could have an adverse impact on our ability to hedge risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted in 2010, expands federal oversight and regulation of the derivatives markets and entities, such as us, that participate in those markets. Those markets involve derivative transactions, which include certain instruments, such as interest rate swaps, forward contracts, option contracts, financial contracts and other contracts, used in our risk management activities. The Dodd-Frank Act requires that most swaps ultimately will be cleared through a registered clearing facility and that they be traded on a designated exchange or swap execution facility, with certain exceptions for entities that use swaps to hedge or mitigate commercial risk. The Dodd-Frank Act requirements relating to derivative transactions have not been fully implemented by the SEC and the Commodities Futures Trading Commission and the current presidential administration has indicated a desire to repeal and/or replace certain provisions of the Dodd-Frank Act. Uncertainty regarding the current law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties. In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, or IDCs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the Tax Cuts and Jobs Act of 2017 (which was signed on December 22, 2017), Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. It is unclear whether any of the foregoing or similar proposals will be considered and enacted as part of future tax reform legislation and if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development and any such change could have an adverse effect on our financial position, results of operations and cash flows.
Recent changes in U.S. federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition.
The Tax Cuts and Jobs Act of 2017 may affect our cash flows, results of operations and financial condition. Among other items, the Tax Cuts and Jobs Act of 2017 repealed the deduction for certain U.S. production activities and provided for a new limitation on the deduction for interest expense. Given the scope of this law and the potential interdependency of its changes,
30
Item 1A. Risk Factors - Continued
it is difficult at this time to assess whether the overall effect of the Tax Cuts and Jobs Act of 2017 will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.
Stockholder Risks
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Funds associated with Fir Tree Inc., York Capital Management Global Advisors, LLC, Elliott Management Corporation and P. Schoenfeld Asset Management LP collectively owned approximately 55% of our outstanding Class A common stock as of December 31, 2017. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions that, in their judgment, could enhance their investment in the Company. Such transactions might adversely affect us or other holders of our Class A common stock.
Our significant concentration of share ownership may adversely affect the trading price of our Class A common stock.
As of December 31, 2017, approximately 55% of our Class A common stock was beneficially owned by four holders, each of which has a representative on our Board of Directors. Our significant concentration of share ownership may adversely affect the trading price of our Class A common stock because of the lack of trading volume in our stock and because investors may perceive disadvantages in owning shares in companies with significant stockholders.
Our ability to pay dividends may impact the trading price of our Class A common stock.
We are not currently paying a cash dividend; however, the Board of Directors periodically reviews our liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility. Our ability to pay dividends or for us to receive dividends from our operating companies may negatively impact the trading price of our Class A common stock.
Certain provisions of our Certificate of Incorporation and our Bylaws may make it difficult for stockholders to change the composition of our Board of Directors and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board of Directors determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:
• | authorize our Board of Directors to issue preferred stock and to determine the price and other terms; |
• | including preferences and voting rights, of those shares without stockholder approval; |
• | establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and |
• | limit the persons who may call special meetings of stockholders. |
These provisions could enable the Board of Directors to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board of Directors, which is responsible for appointing the members of our management.
Item 1B. Unresolved Staff Comments
None
31
Item 2. Properties
Information concerning proved reserves, production, wells, acreage and related matters are contained in Item 1. “Business.”
The Company’s obligations under its Revolving Credit Facility are secured by mortgages on substantially all of the Company’s oil and natural gas properties. See Note 6 for additional details about the Revolving Credit Facility.
Offices
The Company’s principal corporate office is located at 600 Travis, Houston, Texas 77002. The Company maintains additional offices in Illinois, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas and Utah.
Item 3. Legal Proceedings
On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the Plan was subject to certain conditions set forth in the Plan. On February 28, 2017 (the “Effective Date”), all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.
The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest of approximately $31 million. The Company has vigorously disputed that Wells Fargo is entitled to any default interest based on the plain language of the Plan and Confirmation Order. A hearing was held on April 27, 2017, and on November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest. The ruling has been appealed by Wells Fargo and that appeal is pending.
The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 4. Mine Safety Disclosures
Not applicable
32
Part II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Since April 10, 2017, the Successor’s Class A common stock has been listed on the OTCQB market under the trading symbol “LNGG.” No established public trading market existed for the Class A common stock prior to April 10, 2017. From May 24, 2016 through February 28, 2017, the Predecessor’s units were listed on the OTC Markets Group Inc.’s Pink marketplace under the trading symbol “LINEQ.” Prior to May 24, 2016, the Predecessor’s units were listed on the NASDAQ Global Select Market (“NASDAQ”).
In connection with the Company’s reorganization and emergence from bankruptcy, on the Effective Date, all units in the Predecessor outstanding prior to the emergence were canceled. Simultaneous with the cancellation of the units, the Successor authorized for issuance 270,000,000 shares of Class A common stock and 30,000,000 shares of preferred stock, par value $0.001 per share, and issued 91,708,500 shares of Class A common stock primarily to holders of certain classes of claims in the Chapter 11 cases.
At the close of business on January 31, 2018, there were approximately 44 stockholders of record.
The following table sets forth the range of high and low last reported sales prices per share of the Successor and per unit of the Predecessor, as reported by the OTC or NASDAQ, for the periods indicated.
Share/Unit Price Range | ||||||||
Period | High | Low | ||||||
2017: | ||||||||
October 1 – December 31 | $ | 40.25 | $ | 36.50 | ||||
July 1 – September 30 | $ | 37.10 | $ | 31.35 | ||||
April 10 – June 30 | $ | 31.65 | $ | 26.28 | ||||
January 1 – February 28 | $ | 0.14 | $ | 0.09 | ||||
2016: | ||||||||
October 1 – December 31 | $ | 0.34 | $ | 0.05 | ||||
July 1 – September 30 | $ | 0.10 | $ | 0.05 | ||||
April 1 – June 30 | $ | 0.48 | $ | 0.08 | ||||
January 1 – March 31 | $ | 1.95 | $ | 0.33 | ||||
Dividends/Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See the information incorporated by reference in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding securities authorized for issuance under the Company’s equity compensation plans, which information is incorporated by reference into this Item 5.
Sales of Unregistered Securities
None
33
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued |
Issuer Purchases of Equity Securities
The Company’s Board of Directors has authorized the repurchase of up to $400 million of the Company’s outstanding shares of Class A common stock. Purchases may be made from time to time in negotiated purchases or in the open market, including through Rule 10b5-1 prearranged stock trading plans designed to facilitate the repurchase of the Company’s shares during times it would not otherwise be in the market due to self-imposed trading blackout periods or possible possession of material nonpublic information. The timing and amounts of any such repurchases of shares will be subject to market conditions and certain other factors, and will be in accordance with applicable securities laws and other legal requirements, including restrictions contained in the Company’s then current credit facility. The repurchase plan does not obligate the Company to acquire any specific number of shares and may be discontinued at any time.
The following sets forth information with respect to the Company’s repurchases of its shares of Class A common stock during the fourth quarter of 2017:
Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (1) | ||||||||||
(in thousands) | ||||||||||||||
October 1 – 31 | 590,118 | $ | 38.09 | 590,118 | $ | 220,572 | ||||||||
November 1 – 30 | 373,615 | $ | 38.63 | 373,615 | $ | 206,139 | ||||||||
December 1 – 31 | 118,861 | $ | 37.25 | 118,861 | $ | 201,712 | ||||||||
Total | 1,082,594 | $ | 38.18 | 1,082,594 | ||||||||||
(1) | On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of Class A common stock. In accordance with SEC regulations regarding issuer tender offers, the Company’s share repurchase program was suspended as of December 14, 2017 and resumed in February 2018. |
34
Item 6. | Selected Financial Data |
The selected financial data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data.”
Because of numerous acquisitions and divestitures of properties, as well as the impact of the adoption of fresh start accounting on February 28, 2017, the Company’s historical results of operations and period-to-period comparisons of those results and certain other financial data may not be meaningful or indicative of future results. The results of operations of the Company’s California properties and Berry are reported as discontinued operations for all periods presented (see Note 4).
Successor | Predecessor | |||||||||||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | For the Year Ended December 31, | ||||||||||||||||||||||
2016 | 2015 | 2014 | 2013 | |||||||||||||||||||||
(in thousands, except per share and per unit amounts) | ||||||||||||||||||||||||
Statement of operations data: | ||||||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 709,363 | $ | 188,885 | $ | 874,161 | $ | 1,065,795 | $ | 2,305,573 | $ | 2,022,916 | ||||||||||||
Gains (losses) on oil and natural gas derivatives | 13,533 | 92,691 | (164,330 | ) | 1,027,014 | 1,127,395 | 182,906 | |||||||||||||||||
Depreciation, depletion and amortization | 133,711 | 47,155 | 342,614 | 520,219 | 758,996 | 809,608 | ||||||||||||||||||
Interest expense, net of amounts capitalized | 12,361 | 16,725 | 184,870 | 456,749 | 496,210 | 413,581 | ||||||||||||||||||
Income tax expense (benefit) | 388,942 | (166 | ) | 11,194 | (6,393 | ) | 4,368 | (2,199 | ) | |||||||||||||||
Income (loss) from continuing operations | 352,672 | 2,397,609 | (367,343 | ) | (3,754,220 | ) | (462,024 | ) | (658,515 | ) | ||||||||||||||
Income (loss) from discontinued operations | 82,995 | (548 | ) | (1,804,513 | ) | (1,005,591 | ) | 10,215 | (32,822 | ) | ||||||||||||||
Net income (loss) | 435,667 | 2,397,061 | (2,171,856 | ) | (4,759,811 | ) | (451,809 | ) | (691,337 | ) | ||||||||||||||
Net income (loss) attributable to common stockholders/ unitholders | 432,860 | 2,397,061 | (2,171,856 | ) | (4,759,811 | ) | (451,809 | ) | (691,337 | ) | ||||||||||||||
Income (loss) from continuing operations per share/unit: | ||||||||||||||||||||||||
Basic | 3.99 | 6.80 | (1.04 | ) | (10.94 | ) | (1.43 | ) | (2.80 | ) | ||||||||||||||
Diluted | 3.92 | 6.80 | (1.04 | ) | (10.94 | ) | (1.43 | ) | (2.80 | ) | ||||||||||||||
Income (loss) from discontinued operations per share/unit: | ||||||||||||||||||||||||
Basic | 0.95 | (0.01 | ) | (5.12 | ) | (2.93 | ) | 0.03 | (0.14 | ) | ||||||||||||||
Diluted | 0.93 | (0.01 | ) | (5.12 | ) | (2.93 | ) | 0.03 | (0.14 | ) | ||||||||||||||
Net income (loss) per share/unit: | ||||||||||||||||||||||||
Basic | 4.94 | 6.79 | (6.16 | ) | (13.87 | ) | (1.40 | ) | (2.94 | ) | ||||||||||||||
Diluted | 4.85 | 6.79 | (6.16 | ) | (13.87 | ) | (1.40 | ) | (2.94 | ) | ||||||||||||||
Dividends/distributions declared per share/unit | $ | — | $ | — | $ | — | $ | 0.938 | $ | 2.90 | $ | 2.90 | ||||||||||||
Weighted average shares/units outstanding: | ||||||||||||||||||||||||
Basic | 87,646 | 352,792 | 352,653 | 343,323 | 328,918 | 237,544 | ||||||||||||||||||
Diluted | 88,719 | 352,792 | 352,653 | 343,323 | 328,918 | 237,544 | ||||||||||||||||||
35
Item 6. Selected Financial Data - Continued
Successor | Predecessor | |||||||||||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | At or for the Year Ended December 31, | ||||||||||||||||||||||
2016 | 2015 | 2014 | 2013 | |||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Cash flow data: | ||||||||||||||||||||||||
Net cash provided by (used in): | ||||||||||||||||||||||||
Operating activities | $ | 281,164 | $ | (20,814 | ) | $ | 880,514 | $ | 1,249,457 | $ | 1,711,890 | $ | 1,166,212 | |||||||||||
Investing activities | 1,242,018 | (58,756 | ) | (235,840 | ) | (310,417 | ) | (2,021,025 | ) | (818,317 | ) | |||||||||||||
Financing activities | (1,113,029 | ) | (560,932 | ) | 48,015 | (938,681 | ) | 258,773 | (296,967 | ) | ||||||||||||||
Balance sheet data: | ||||||||||||||||||||||||
Total assets | $ | 2,881,123 | $ | 4,660,591 | $ | 9,936,880 | $ | 16,632,820 | $ | 16,436,499 | ||||||||||||||
Current portion of long-term debt, net | — | 1,937,729 | 2,841,518 | — | — | |||||||||||||||||||
Long-term debt, net | — | — | 4,447,308 | 8,125,213 | 6,796,015 | |||||||||||||||||||
Liabilities subject to compromise | — | 4,305,005 | — | — | — | |||||||||||||||||||
Total equity (deficit) | 2,351,557 | (2,396,988 | ) | (268,901 | ) | 4,543,605 | 5,891,427 | |||||||||||||||||
36
Item 6. Selected Financial Data - Continued
Successor | Predecessor | |||||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | At or for the Year Ended December 31, | ||||||||||||||||
2016 | 2015 | 2014 | 2013 | |||||||||||||||
Production data: | ||||||||||||||||||
Average daily production – Continuing operations: | ||||||||||||||||||
Natural gas (MMcf/d) | 386 | 495 | 511 | 549 | 492 | 440 | ||||||||||||
Oil (MBbls/d) | 17.8 | 20.2 | 22.1 | 27.4 | 33.8 | 31.0 | ||||||||||||
NGL (MBbls/d) | 20.5 | 21.4 | 25.4 | 25.6 | 31.7 | 29.6 | ||||||||||||
Total (MMcfe/d) | 616 | 745 | 796 | 867 | 885 | 804 | ||||||||||||
Average daily production – Equity method investments: (1) | ||||||||||||||||||
Total (MMcfe/d) | 30 | — | — | — | — | — | ||||||||||||
Average daily production – Discontinued operations: (2) | ||||||||||||||||||
Total (MMcfe/d) | 14 | 30 | 253 | 321 | 325 | 18 | ||||||||||||
Reserves data: (3) | ||||||||||||||||||
Proved reserves – Continuing operations: | ||||||||||||||||||
Natural gas (Bcf) | 1,377 | 2,290 | 2,212 | 3,552 | 2,715 | |||||||||||||
Oil (MMBbls) | 27 | 73 | 74 | 148 | 169 | |||||||||||||
NGL (MMBbls) | 72 | 104 | 97 | 146 | 184 | |||||||||||||
Total (Bcfe) | 1,968 | 3,350 | 3,240 | 5,318 | 4,827 | |||||||||||||
Proved reserves – Equity method investments: (1) | ||||||||||||||||||
Total (Bcfe) | 694 | — | — | — | — | |||||||||||||
Proved reserves – Discontinued operations: | ||||||||||||||||||
Total (Bcfe) | — | 170 | 1,248 | 1,986 | 1,576 | |||||||||||||
(1) | Represents the Company’s 50% equity interest in Roan. |
(2) | Production of the Company’s California properties reported as discontinued operations for 2017 is for the period from January 1, 2017 through July 31, 2017. Production of Berry reported as discontinued operations for 2016 and 2013 is for the periods from January 1, 2016 through December 3, 2016, and December 17, 2013 through December 31, 2013, respectively. |
(3) | In accordance with Securities and Exchange Commission regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements based on expectations, estimates and assumptions. Actual results may differ materially from those discussed in the 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 Regarding Forward-Looking Statements” in Item 1. “Business” and in Item 1A. “Risk Factors.”
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. is not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of the Predecessor through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see below and Note 4). The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Executive Overview
LINN Energy is an independent oil and natural gas company that was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further below and in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date and classified it as discontinued operations.
The Company’s properties are located in six operating regions in the United States (“U.S.”):
• | Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; |
• | TexLa, which includes properties located in east Texas and north Louisiana; |
• | Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; |
• | Mid-Continent, which includes Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform; |
• | Permian Basin, which includes properties located in west Texas and southeast New Mexico; and |
• | Rockies, which includes Utah properties located in the Uinta Basin. |
38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The Company also owns a 50% equity interest in Roan, which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma. During 2017, the Company divested of its properties located in previous operating regions California and South Texas. See below and Note 4 for details of the Company’s divestitures.
For a discussion of the Company’s operating regions, see Item 1. “Business.”
For the year ended December 31, 2017, the Company’s results included the following:
• | oil, natural gas and NGL sales of approximately $709 million and $189 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to $874 million for 2016; |
• | average daily production of approximately 616 MMcfe/d and 745 MMcfe/d for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to 796 MMcfe/d for 2016; |
• | net income attributable to common stockholders/unitholders of approximately $433 million and $2.4 billion for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to net loss attributable to unitholders of approximately $2.2 billion for 2016; |
• | net cash provided by operating activities from continuing operations of approximately $265 million and net cash used in operating activities of approximately $30 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to net cash provided by operating activities of approximately $831 million for 2016; |
• | capital expenditures of approximately $299 million and $46 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to $172 million for 2016; and |
• | 90 wells drilled (all successful) compared to 212 wells drilled (211 successful) for 2016. |
Predecessor and Successor Reporting
As a result of the application of fresh start accounting (see Note 3), the Company’s consolidated financial statements and certain note presentations are separated into two distinct periods, the period before the Effective Date (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 presentation, there was continuity of the Company’s operations.
Chapter 11 Proceedings
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.
On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC (“LAC”) and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Plan of Reorganization
In accordance with the Plan, on the Effective Date:
• | The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed wholly owned subsidiary of the Predecessor and the |
39
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
borrower under the Credit Agreement (as amended, the “Successor Credit Facility”) entered into in connection with the reorganization, in exchange for equity interests in Holdco II and the issuance of interests in the Successor Credit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash, an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor, which the Predecessor distributed to certain of its creditors in satisfaction of their claims, and the Successor’s agreement to honor certain obligations of the Predecessor under the Plan. In connection with this transfer, certain entities composing the Successor guaranteed the Successor Credit Facility. Contemporaneously with the reorganization transactions and pursuant to the Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims.
• | The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“Predecessor Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Successor Credit Facility. As a result, all outstanding obligations under the Predecessor Credit Facility were canceled. |
• | Holdco II, as borrower, entered into the Successor Credit Facility with the holders of claims under the Predecessor Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million. For additional information, see “Financing Activities” below. |
• | The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below. As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. |
• | The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. |
• | All units of the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Successor issued in the aggregate 89,229,892 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. |
• | The Successor entered into a registration rights agreement with certain parties, pursuant to which the Company agreed to, among other things, file a registration statement with the Securities and Exchange Commission within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). |
• | By operation of the Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Successor formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Successor and five directors selected by a six-person selection committee. |
40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Rights Offerings
On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”). In accordance with the Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the eligible creditors were offered the right to purchase Class A common stock from the Successor in connection with the consummation of the Plan for an aggregate purchase price of $530 million.
Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the shares that were not duly subscribed to pursuant to the offerings at the discounted per share price set forth in the Backstop Commitment Agreement by parties other than Backstop Parties. Pursuant to the Backstop Commitment Agreement, the Backstop Parties were entitled to receive, on the Effective Date, a commitment premium equal to 4.0% of the $530 million committed amount, of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement.
On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the rights offerings and the related issuances of Class A common stock were completed.
Divestitures
Below are the Company’s completed divestitures in 2017:
• | On November 30, 2017, the Company completed the sale of its interest in properties located in the Williston Basin (the “Williston Assets Sale”). Cash proceeds received from the sale of these properties were approximately $255 million, net of costs to sell of approximately $3 million, and the Company recognized a net gain of approximately $116 million. |
• | On November 30, 2017, the Company completed the sale of its interest in properties located in Wyoming (the “Washakie Assets Sale”). Cash proceeds received from the sale of these properties were approximately $193 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $175 million. |
• | On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certain properties located in south Texas (the “South Texas Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $48 million, net of costs to sell of approximately $1 million, and the Company recognized a combined net gain of approximately $14 million. |
• | On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million. |
• | On July 31, 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin in California (the “San Joaquin Basin Sale”). Cash proceeds received from the sale of these properties were approximately $253 million, net of costs to sell of approximately $4 million, and the Company recognized a net gain of approximately $120 million. |
• | On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $2 million. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year from the date of sale. |
• | On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $73 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $30 million. |
41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
• | On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $559 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $277 million. |
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its consolidated financial statements.
Divestitures – Pending
On February 13, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in conventional properties located in west Texas for a contract price of $119.5 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On January 15, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Altamont Bluebell Field in Utah for a contract price of $132 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On December 18, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its Oklahoma waterflood and Texas Panhandle properties for a contract price of $122 million, subject to closing adjustments. Proceeds from the sale are expected to be added as additional cash on the Company’s balance sheet to be used for general corporate purposes. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
The Company continues to market its remaining assets located in the Permian Basin and the Drunkards Wash Field in Utah.
Roan Contribution
On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. As of August 31, 2017, the date of the Roan Contribution, the Company recognized its equity investment at a carryover basis of approximately $452 million.
Construction of Cryogenic Plant
In July 2017 the Company renamed its subsidiary LINN Midstream, LLC to Blue Mountain Midstream LLC (“Blue Mountain”) and entered into a definitive agreement with BCCK Engineering, Inc. (“BCCK”) to construct the Chisholm Trail Cryogenic Gas Plant. Blue Mountain’s assets include the Chisholm Trail midstream business (“Chisholm Trail”) located in Oklahoma. Chisholm Trail is located in the Merge/SCOOP/STACK play in the Mid-Continent region and has approximately 30 miles of existing natural gas gathering pipeline and approximately 60 MMcf/d of current refrigeration capacity. Infrastructure expansions are underway to add 35 miles of low pressure gathering pipelines, increase compression throughput and construct a new 225 MMcf/d cryogenic natural gas processing facility with a total capacity of 250 MMcf/d. The Chisholm Trail Cryogenic Gas Plant is expected to be commissioned during the second quarter of 2018.
42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
2018 Oil and Natural Gas Capital Budget
For 2018, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $134 million, including approximately $34 million related to its oil and natural gas capital program and approximately $98 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Financing Activities
Tender Offer
On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of the tender offer).
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million, and on October 4, 2017, the Company’s Board authorized another increase up to a total of $400 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Company’s Revolving Credit Facility (as defined below). In accordance with the SEC’s regulations regarding issuer tender offers, the Company’s share repurchase program was suspended concurrent with the December 14, 2017, announcement of the intent to commence a tender offer. The program was resumed in February 2018 following the expiration of the tender offer.
During the period from June 2017 through December 2017, the Company repurchased an aggregate of 5,690,192 shares of Class A common stock at an average price of $34.85 per share for a total cost of approximately $198 million. At January 31, 2018, approximately $202 million was available for share repurchases under the program.
Revolving Credit Facility
On August 4, 2017, the Company entered into a credit agreement with Holdco II, as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million. The maximum commitment amount was $425 million at December 31, 2017. See Note 6 for additional information about the Revolving Credit Facility.
As of December 31, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $381 million of available borrowing capacity (which includes a $44 million reduction for outstanding letters of credit). The maturity date is August 4, 2020.
Listing on the OTCQB Market
On the Effective Date, the Predecessor’s units were canceled and ceased to trade on the OTC Markets Group Inc.’s Pink marketplace. In April 2017, the Successor’s Class A common stock was approved for trading on the OTCQB market under the symbol “LNGG.”
43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
The following table reflects the Company’s results of operations for each of the Successor and Predecessor periods presented:
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
(in thousands) | ||||||||||||
Revenues and other: | ||||||||||||
Natural gas sales | $ | 317,529 | $ | 99,561 | $ | 426,307 | ||||||
Oil sales | 258,055 | 58,560 | 315,472 | |||||||||
NGL sales | 133,779 | 30,764 | 132,382 | |||||||||
Total oil, natural gas and NGL sales | 709,363 | 188,885 | 874,161 | |||||||||
Gains (losses) on oil and natural gas derivatives | 13,533 | 92,691 | (164,330 | ) | ||||||||
Marketing and other revenues (1) | 103,782 | 16,551 | 129,813 | |||||||||
826,678 | 298,127 | 839,644 | ||||||||||
Expenses: | ||||||||||||
Lease operating expenses | 208,446 | 49,665 | 296,891 | |||||||||
Transportation expenses | 113,128 | 25,972 | 161,574 | |||||||||
Marketing expenses | 69,008 | 4,820 | 29,736 | |||||||||
General and administrative expenses (2) | 117,548 | 71,745 | 237,841 | |||||||||
Exploration costs | 3,137 | 93 | 4,080 | |||||||||
Depreciation, depletion and amortization | 133,711 | 47,155 | 342,614 | |||||||||
Impairment of long-lived assets | — | — | 165,044 | |||||||||
Taxes, other than income taxes | 47,553 | 14,877 | 67,648 | |||||||||
(Gains) losses on sale of assets and other, net | (623,072 | ) | 829 | 16,257 | ||||||||
69,459 | 215,156 | 1,321,685 | ||||||||||
Other income and (expenses) | (6,754 | ) | (16,717 | ) | (185,707 | ) | ||||||
Reorganization items, net | (8,851 | ) | 2,331,189 | 311,599 | ||||||||
Income (loss) from continuing operations before income taxes | 741,614 | 2,397,443 | (356,149 | ) | ||||||||
Income tax expense (benefit) | 388,942 | (166 | ) | 11,194 | ||||||||
Income (loss) from continuing operations | 352,672 | 2,397,609 | (367,343 | ) | ||||||||
Income (loss) from discontinued operations, net of income taxes | 82,995 | (548 | ) | (1,804,513 | ) | |||||||
Net income (loss) | 435,667 | 2,397,061 | (2,171,856 | ) | ||||||||
Net income attributable to noncontrolling interests | 2,807 | — | — | |||||||||
Net income (loss) attributable to common stockholders/unitholders | $ | 432,860 | $ | 2,397,061 | $ | (2,171,856 | ) | |||||
(1) | Marketing and other revenues for the two months ended February 28, 2017, and the year ended December 31, 2016, include approximately $6 million and $69 million, respectively, of management fee revenues recognized by the Company from Berry. Management fee revenues are included in “other revenues” on the consolidated statements of operations. |
(2) | General and administrative expenses for the ten months ended December 31, 2017, the two months ended February 28, 2017, and the year ended December 31, 2016, include approximately $41 million, $50 million and $34 million, respectively, of noncash share-based compensation expenses. In addition, general and administrative expenses for the two months ended February 28, 2017, and the year ended December 31, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
44
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
Average daily production: | ||||||||||||
Natural gas (MMcf/d) | 386 | 495 | 511 | |||||||||
Oil (MBbls/d) | 17.8 | 20.2 | 22.1 | |||||||||
NGL (MBbls/d) | 20.5 | 21.4 | 25.4 | |||||||||
Total (MMcfe/d) | 616 | 745 | 796 | |||||||||
Average daily production – Equity method investments: (1) | ||||||||||||
Total (MMcfe/d) | 30 | — | — | |||||||||
Weighted average prices: (2) | ||||||||||||
Natural gas (Mcf) | $ | 2.69 | $ | 3.41 | $ | 2.28 | ||||||
Oil (Bbl) | $ | 47.42 | $ | 49.16 | $ | 39.00 | ||||||
NGL (Bbl) | $ | 21.28 | $ | 24.37 | $ | 14.26 | ||||||
Average NYMEX prices: | ||||||||||||
Natural gas (MMBtu) | $ | 3.00 | $ | 3.66 | $ | 2.46 | ||||||
Oil (Bbl) | $ | 50.53 | $ | 53.04 | $ | 43.32 | ||||||
Costs per Mcfe of production: | ||||||||||||
Lease operating expenses | $ | 1.11 | $ | 1.13 | $ | 1.02 | ||||||
Transportation expenses | $ | 0.60 | $ | 0.59 | $ | 0.55 | ||||||
General and administrative expenses (3) | $ | 0.62 | $ | 1.63 | $ | 0.82 | ||||||
Depreciation, depletion and amortization | $ | 0.71 | $ | 1.07 | $ | 1.18 | ||||||
Taxes, other than income taxes | $ | 0.25 | $ | 0.34 | $ | 0.23 | ||||||
Average daily production – Discontinued operations: (4) | ||||||||||||
Total (MMcfe/d) | 14 | 30 | 253 | |||||||||
(1) | Represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017. |
(2) | Does not include the effect of gains (losses) on derivatives. |
(3) | General and administrative expenses for the ten months ended December 31, 2017, the two months ended February 28, 2017, and the year ended December 31, 2016, include approximately $41 million, $50 million and $34 million, respectively, of noncash share-based compensation expenses. In addition, general and administrative expenses for the two months ended February 28, 2017, and the year ended December 31, 2016, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
(4) | Production of the Company’s California properties reported as discontinued operations for 2017 is for the period from January 1, 2017 through July 31, 2017. Production of Berry reported as discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
45
Item 7. 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 $24 million or 3% to approximately $709 million and $189 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $874 million for the year ended December 31, 2016, due to higher commodity prices, partially offset by lower production volumes. Higher natural gas, oil and NGL prices resulted in an increase in revenues of approximately $81 million, $58 million and $57 million, respectively.
Average daily production volumes decreased to approximately 616 MMcfe/d and 745 MMcfe/d for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately 796 MMcfe/d for the year ended December 31, 2016. Lower natural gas, oil and NGL production volumes resulted in a decrease in revenues of approximately $91 million, $56 million and $25 million, respectively.
The following table sets forth average daily production by region:
Successor | Predecessor | ||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | |||||||
Average daily production (MMcfe/d): | |||||||||
Rockies | 184 | 294 | 330 | ||||||
Hugoton Basin | 167 | 159 | 180 | ||||||
Mid-Continent | 97 | 109 | 101 | ||||||
TexLa | 82 | 80 | 72 | ||||||
Permian Basin | 44 | 49 | 56 | ||||||
Michigan/Illinois | 29 | 29 | 30 | ||||||
South Texas | 13 | 25 | 27 | ||||||
616 | 745 | 796 | |||||||
Equity method investments | 30 | — | — | ||||||
The increase from 2016 in average daily production volumes in the TexLa region primarily reflects increased development capital spending in the region. The decrease from 2016 in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Roan Contribution on August 31, 2017, partially offset by increased development capital spending in the region. The decreases in average daily production volumes in the Rockies, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017. See Note 4 for additional information of divestitures. In addition, the decreases in average daily production volumes in these and the remaining regions reflect lower production volumes as a result of reduced development capital spending, as well as marginal well shut-ins, driven by continued low commodity prices. Equity method investments represents the Company’s 50% equity interest in Roan. Production of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $14 million and $93 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to losses on oil and natural gas derivatives of approximately $164 million for the year ended December 31, 2016, representing a variance of approximately $271 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivative 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.
46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
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 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues recognized by the Company from Berry (in the Predecessor periods) and helium sales revenue. Marketing and other revenues decreased by approximately $9 million or 7% to approximately $104 million and $17 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $130 million for the year ended December 31, 2016. The decrease was primarily due to the management fee revenues from Berry included in the Predecessor periods, partially offset by higher revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
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 decreased by approximately $39 million or 13% to approximately $208 million and $50 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $297 million for the year ended December 31, 2016. The decrease was primarily due to reduced labor costs for field operations as a result of cost savings initiatives and the divestitures completed in 2017. Lease operating expenses per Mcfe increased to $1.11 per Mcfe and $1.13 per Mcfe for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to $1.02 per Mcfe for the year ended December 31, 2016.
Transportation Expenses
Transportation expenses decreased by approximately $23 million or 14% to approximately $113 million and $26 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $162 million for the year ended December 31, 2016. The decrease was primarily due to reduced costs as a result of lower production volumes and as a result of the divestitures completed in 2017. Transportation expenses per Mcfe increased to $0.60 per Mcfe and $0.59 per Mcfe for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to $0.55 per Mcfe for the year ended December 31, 2016.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $44 million or 148% to approximately $69 million and $5 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $30 million for the year ended December 31, 2016. The increase was primarily due to higher expenses associated with the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses in the Predecessor periods include costs incurred by LINN Energy associated with the operations of Berry. General and administrative expenses decreased by approximately $48 million or 20% to approximately $118 million and $72 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $238 million for the year ended December 31, 2016. The decrease was primarily due to lower salaries and benefits related expenses, the costs associated with the operations of Berry in the Predecessor periods, lower various other administrative expenses including insurance and rent, and lower professional services expenses, partially offset by higher noncash share-based compensation expenses principally driven by the immediate vesting of certain awards on the Effective Date. General and administrative expenses per Mcfe were $0.62 per Mcfe and $1.63 per Mcfe for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to $0.82 per Mcfe for the year ended December 31, 2016.
47
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
For professional services expenses related to the Chapter 11 proceedings that were incurred since the Petition Date, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs decreased by approximately $1 million to approximately $3 million and $93,000 for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $4 million for the year ended December 31, 2016. The decrease was primarily due to lower seismic data expenses.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $162 million or 47% to approximately $134 million and $47 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from approximately $343 million for the year ended December 31, 2016. The decrease was primarily due to lower rates as a result of the application of fresh start accounting, as well as lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $0.71 per Mcfe and $1.07 per Mcfe for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from $1.18 per Mcfe for the year ended December 31, 2016.
Impairment of Long-Lived Assets
The Company recorded no impairment charges for the ten months ended December 31, 2017, or the two months ended February 28, 2017. During the year ended December 31, 2016, the Company recorded an impairment charge of approximately $165 million associated with proved oil and natural gas properties in the Mid-Continent and Rockies regions due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves.
Taxes, Other Than Income Taxes
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
(in thousands) | ||||||||||||
Severance taxes | $ | 30,074 | $ | 9,107 | $ | 38,166 | ||||||
Ad valorem taxes | 17,337 | 5,744 | 28,450 | |||||||||
Other | 142 | 26 | 1,032 | |||||||||
$ | 47,553 | $ | 14,877 | $ | 67,648 | |||||||
Severance taxes, which are a function of revenues generated from production, increased primarily due to higher commodity prices, partially offset by lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to divestitures completed in 2017 and lower estimated valuations on certain of the Company’s properties.
(Gains) Losses on Sale of Assets and Other, Net
During the ten months ended December 31, 2017, the Company recorded the following amounts related to divestitures (see Note 4):
• | Net gain of approximately $277 million, including costs to sell of approximately $6 million, on the Jonah Assets Sale; |
• | Net gain of approximately $175 million, including costs to sell of approximately $2 million, on the Washakie Assets Sale; |
• | Net gain of approximately $116 million, including costs to sell of approximately $3 million, on the Williston Assets Sale; |
• | Net gain of approximately $30 million, including costs to sell of approximately $1 million, on the Salt Creek Assets Sale; |
• | Net gain of approximately $29 million on the Permian Assets Sales; |
• | Advisory fees of approximately $17 million associated with the Roan Contribution; and |
48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
• | Net gain of approximately $14 million, including costs to sell of approximately $1 million, on the South Texas Assets Sales. |
Other Income and (Expenses)
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
(in thousands) | ||||||||||||
Interest expense, net of amounts capitalized | $ | (12,361 | ) | $ | (16,725 | ) | $ | (184,870 | ) | |||
Earnings from equity method investments | 11,840 | 157 | 699 | |||||||||
Other, net | (6,233 | ) | (149 | ) | (1,536 | ) | ||||||
$ | (6,754 | ) | $ | (16,717 | ) | $ | (185,707 | ) | ||||
Interest expense decreased primarily due to lower outstanding debt during 2017, the Company’s discontinuation of interest expense recognition on the senior notes for the two months ended February 28, 2017, as a result of the Chapter 11 proceedings, and lower amortization of discounts and financing fees. For the two months ended February 28, 2017, and the period from May 12, 2016 through December 31, 2016, contractual interest, which was not recorded, on the senior notes was approximately $37 million and $143 million, respectively. See “Debt” under “Liquidity and Capital Resources” below for additional details.
The Second Lien Notes were accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. For the two months ended February 28, 2017, and the period from May 12, 2016 through December 31, 2016, unrecorded contractual interest on the Second Lien Notes was approximately $20 million and $76 million, respectively.
Equity method investments primarily include the Company’s 50% equity interest in Roan. The Company’s equity earnings consists of its share of Roan’s earnings and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. See Note 4 for additional information.
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.
49
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table summarizes the components of reorganization items included on the consolidated statements of operations:
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
(in thousands) | ||||||||||||
Gain on settlement of liabilities subject to compromise | $ | — | $ | 3,724,750 | $ | — | ||||||
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | — | (1,000,000 | ) | — | ||||||||
Fresh start valuation adjustments | — | (591,525 | ) | — | ||||||||
Income tax benefit related to implementation of the Plan | — | 264,889 | — | |||||||||
Legal and other professional advisory fees | (8,902 | ) | (46,961 | ) | (56,656 | ) | ||||||
Unamortized deferred financing fees, discounts and premiums | — | — | (52,045 | ) | ||||||||
Gains related to interest payable on Predecessor’s Second Lien Notes | — | — | 551,000 | |||||||||
Terminated contracts | — | (6,915 | ) | (66,052 | ) | |||||||
Other | 51 | (13,049 | ) | (64,648 | ) | |||||||
Reorganization items, net | $ | (8,851 | ) | $ | 2,331,189 | $ | 311,599 | |||||
Income Tax Expense (Benefit)
The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $389 million and an income tax benefit of approximately $166,000 for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to an income tax expense of approximately $11 million for the year ended December 31, 2016.
Income (Loss) from Discontinued Operations, Net of Income Taxes
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale) and the deconsolidation of Berry, the Company has classified the results of operations of its California properties and Berry as discontinued operations. Income from discontinued operations, net of income taxes was approximately $83 million for the ten months ended December 31, 2017, compared to losses of approximately $548,000 and $1.8 billion for the two months ended February 28, 2017, and the year ended December 31, 2016, respectively. See Note 4 for additional information.
Net Income (Loss) Attributable to Common Stockholders/Unitholders
Net income attributable to common stockholders/unitholders increased by approximately $5.0 billion to net income of approximately $433 million and $2.4 billion for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, from a net loss of approximately $2.2 billion for the year ended December 31, 2016. The increase was primarily due to higher gains included in reorganization items, income compared to losses from discontinued operations, gains on the divestitures completed in 2017, gains compared to losses on commodity derivatives, lower expenses, lower impairment charges and higher production revenues. See discussion above for explanations of variances.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
Year Ended December 31, 2016, Compared to Year Ended December 31, 2015
Predecessor | |||||||||||
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Revenues and other: | |||||||||||
Natural gas sales | $ | 426,307 | $ | 512,538 | $ | (86,231 | ) | ||||
Oil sales | 315,472 | 434,961 | (119,489 | ) | |||||||
NGL sales | 132,382 | 118,296 | 14,086 | ||||||||
Total oil, natural gas and NGL sales | 874,161 | 1,065,795 | (191,634 | ) | |||||||
Gains (losses) on oil and natural gas derivatives | (164,330 | ) | 1,027,014 | (1,191,344 | ) | ||||||
Marketing and other revenues (1) | 129,813 | 141,647 | (11,834 | ) | |||||||
839,644 | 2,234,456 | (1,394,812 | ) | ||||||||
Expenses: | |||||||||||
Lease operating expenses | 296,891 | 352,077 | (55,186 | ) | |||||||
Transportation expenses | 161,574 | 167,023 | (5,449 | ) | |||||||
Marketing expenses | 29,736 | 35,278 | (5,542 | ) | |||||||
General and administrative expenses (2) | 237,841 | 285,996 | (48,155 | ) | |||||||
Exploration costs | 4,080 | 9,473 | (5,393 | ) | |||||||
Depreciation, depletion and amortization | 342,614 | 520,219 | (177,605 | ) | |||||||
Impairment of long-lived assets | 165,044 | 4,960,144 | (4,795,100 | ) | |||||||
Taxes, other than income taxes | 67,648 | 97,685 | (30,037 | ) | |||||||
(Gains) losses on sale of assets and other, net | 16,257 | (194,805 | ) | 211,062 | |||||||
1,321,685 | 6,233,090 | (4,911,405 | ) | ||||||||
Other income and (expenses) | (185,707 | ) | 238,021 | (423,728 | ) | ||||||
Reorganization items, net | 311,599 | — | 311,599 | ||||||||
Loss from continuing operations before income taxes | (356,149 | ) | (3,760,613 | ) | 3,404,464 | ||||||
Income tax expense (benefit) | 11,194 | (6,393 | ) | 17,587 | |||||||
Loss from continuing operations | (367,343 | ) | (3,754,220 | ) | 3,386,877 | ||||||
Loss from discontinued operations, net of income taxes | (1,804,513 | ) | (1,005,591 | ) | (798,922 | ) | |||||
Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | $ | 2,587,955 | |||
(1) | Marketing and other revenues for the years ended December 31, 2016, and December 31, 2015 include approximately $69 million and $78 million, respectively, of management fee revenues recognized by the Company from Berry. Management fee revenues are included in “other revenues” on the consolidated statements of operations. |
(2) | General and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include approximately $34 million and $47 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
51
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Predecessor | ||||||||||
Year Ended December 31, | ||||||||||
2016 | 2015 | Variance | ||||||||
Average daily production: | ||||||||||
Natural gas (MMcf/d) | 511 | 549 | (7 | )% | ||||||
Oil (MBbls/d) | 22.1 | 27.4 | (19 | )% | ||||||
NGL (MBbls/d) | 25.4 | 25.6 | (1 | )% | ||||||
Total (MMcfe/d) | 796 | 867 | (8 | )% | ||||||
Weighted average prices: (1) | ||||||||||
Natural gas (Mcf) | $ | 2.28 | $ | 2.56 | (11 | )% | ||||
Oil (Bbl) | $ | 39.00 | $ | 43.42 | (10 | )% | ||||
NGL (Bbl) | $ | 14.26 | $ | 12.66 | 13 | % | ||||
Average NYMEX prices: | ||||||||||
Natural gas (MMBtu) | $ | 2.46 | $ | 2.66 | (8 | )% | ||||
Oil (Bbl) | $ | 43.32 | $ | 48.80 | (11 | )% | ||||
Costs per Mcfe of production: | ||||||||||
Lease operating expenses | $ | 1.02 | $ | 1.11 | (8 | )% | ||||
Transportation expenses | $ | 0.55 | $ | 0.53 | 4 | % | ||||
General and administrative expenses (2) | $ | 0.82 | $ | 0.90 | (9 | )% | ||||
Depreciation, depletion and amortization | $ | 1.18 | $ | 1.64 | (28 | )% | ||||
Taxes, other than income taxes | $ | 0.23 | $ | 0.31 | (26 | )% | ||||
Average daily production – Discontinued operations: (3) | ||||||||||
Total (MMcfe/d) | 253 | 321 | (21 | )% | ||||||
(1) | Does not include the effect of gains (losses) on derivatives. |
(2) | General and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include approximately $34 million and $47 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include expenses incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
(3) | Production of Berry reported as discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
52
Item 7. 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 decreased by approximately $192 million or 18% to approximately $874 million for the year ended December 31, 2016, from approximately $1.1 billion for the year ended December 31, 2015, due to lower natural gas and oil prices, and lower production volumes, partially offset by higher NGL prices. Lower natural gas and oil prices resulted in a decrease in revenues of approximately $52 million and $36 million, respectively. Higher NGL prices resulted in an increase in revenues of approximately $15 million.
Average daily production volumes decreased to approximately 796 MMcfe/d for the year ended December 31, 2016, from approximately 867 MMcfe/d for the year ended December 31, 2015. Lower oil, natural gas and NGL production volumes resulted in a decrease in revenues of approximately $84 million, $34 million and $1 million, respectively.
The following table sets forth average daily production by region:
Predecessor | |||||||||||
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
Average daily production (MMcfe/d): | |||||||||||
Rockies | 330 | 359 | (29 | ) | (8 | )% | |||||
Hugoton Basin | 180 | 193 | (13 | ) | (7 | )% | |||||
Mid-Continent | 101 | 100 | 1 | 2 | % | ||||||
TexLa | 72 | 72 | — | — | |||||||
Permian Basin | 56 | 80 | (24 | ) | (30 | )% | |||||
Michigan/Illinois | 30 | 31 | (1 | ) | (3 | )% | |||||
South Texas | 27 | 32 | (5 | ) | (14 | )% | |||||
796 | 867 | (71 | ) | (8 | )% | ||||||
The decreases in average daily production volumes primarily reflect reduced development capital spending throughout the Company’s various operating regions, as well as marginal well shut-ins, driven by continued low commodity prices. The decrease in average daily production volumes in the Permian Basin region also reflects lower production volumes as a result of the sale of its remaining position in Howard County in the Permian Basis (the “Howard County Assets Sale”) on August 31, 2015.
Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $164 million for the year ended December 31, 2016, compared to gains of approximately $1.0 billion for the year ended December 31, 2015, representing a variance of approximately $1.2 billion. Losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts and the impact of the declining maturity schedule from period to period of the Company’s hedges. The fair value on unsettled derivative 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 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
53
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues recognized by the Company from Berry and helium sales revenue. Marketing and other revenues decreased by approximately $12 million or 8% to approximately $130 million for the year ended December 31, 2016, from approximately $142 million for the year ended December 31, 2015. The decrease was primarily due to lower management fee revenues from Berry, principally driven by reduced salaries and benefits related expenses at the Company, as well as lower revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms, partially offset by higher helium sales revenue in the Hugoton Basin.
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 decreased by approximately $55 million or 16% to approximately $297 million for the year ended December 31, 2016, from approximately $352 million for the year ended December 31, 2015. The decrease was primarily due to cost savings initiatives and lower workover activities. Lease operating expenses per Mcfe also decreased to $1.02 per Mcfe for the year ended December 31, 2016, from $1.11 per Mcfe for the year ended December 31, 2015.
Transportation Expenses
Transportation expenses decreased by approximately $5 million or 3% to approximately $162 million for the year ended December 31, 2016, from approximately $167 million for the year ended December 31, 2015. The decrease was primarily due to reduced costs as a result of lower production volumes, partially offset by higher costs from nonoperated properties in the Rockies region. Transportation expenses per Mcfe increased to $0.55 per Mcfe for the year ended December 31, 2016, from $0.53 per Mcfe for the year ended December 31, 2015.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $5 million or 16% to approximately $30 million for the year ended December 31, 2016, from approximately $35 million for the year ended December 31, 2015. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include costs incurred by LINN Energy associated with the operations of Berry. General and administrative expenses decreased by approximately $48 million or 17% to approximately $238 million for the year ended December 31, 2016, from approximately $286 million for the year ended December 31, 2015. The decrease was primarily due to lower professional services expenses, lower acquisition expenses, lower salaries and benefits related expenses and lower various other administrative expenses including rent. General and administrative expenses for the year ended December 31, 2015, was impacted by advisory fees related to alliance agreements entered into with certain private capital investors. General and administrative expenses per Mcfe also decreased to $0.82 per Mcfe for the year ended December 31, 2016, from $0.90 per Mcfe for the year ended December 31, 2015.
For professional services expenses related to the Chapter 11 proceedings that were incurred since the Petition Date, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs decreased by approximately $5 million to approximately $4 million for the year ended December 31, 2016, from approximately $9 million for the year ended December 31, 2015. The decrease was primarily due to lower dry hole costs and lower leasehold impairment expenses on unproved properties.
54
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $177 million or 34% to approximately $343 million for the year ended December 31, 2016, from approximately $520 million for the year ended December 31, 2015. The decrease was primarily due to lower rates as a result of the impairments recorded in 2015 and 2016, as well as lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.18 per Mcfe for the year ended December 31, 2016, from $1.64 per Mcfe for the year ended December 31, 2015.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges associated with proved and unproved oil and natural gas properties:
Predecessor | |||||||
Year Ended December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Mid-Continent region | $ | 141,902 | $ | 405,370 | |||
Rockies region | 23,142 | 1,592,256 | |||||
Hugoton Basin region | — | 1,667,768 | |||||
TexLa region | — | 352,422 | |||||
Permian Basin region | — | 71,990 | |||||
South Texas region | — | 42,433 | |||||
Proved oil and natural gas properties | 165,044 | 4,132,239 | |||||
TexLa region | — | 416,846 | |||||
Permian Basin region | — | 226,922 | |||||
Rockies region | — | 184,137 | |||||
Unproved oil and natural gas properties | — | 827,905 | |||||
Impairment of long-lived assets | $ | 165,044 | $ | 4,960,144 | |||
The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves.
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2016, the Company had no significant gains or losses from the sale of assets. During the year ended December 31, 2015, the Company recorded a net gain of approximately $177 million, including costs to sell of approximately $1 million, on the Howard County Assets Sale. See Note 3 for additional details of divestitures and exchanges of properties.
Taxes, Other Than Income Taxes
Predecessor | |||||||||||
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Severance taxes | $ | 38,166 | $ | 53,016 | $ | (14,850 | ) | ||||
Ad valorem taxes | 28,450 | 44,716 | (16,266 | ) | |||||||
Other | 1,032 | (47 | ) | 1,079 | |||||||
$ | 67,648 | $ | 97,685 | $ | (30,037 | ) | |||||
55
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Taxes, other than income taxes decreased by approximately $30 million or 31% for the year ended December 31, 2016, compared to the year ended December 31, 2015. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower natural gas and oil prices and lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to lower estimated valuations on certain of the Company’s properties.
Other Income and (Expenses)
Predecessor | |||||||||||
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Interest expense, net of amounts capitalized | $ | (184,870 | ) | $ | (456,749 | ) | $ | 271,879 | |||
Gain on extinguishment of debt | — | 708,050 | (708,050 | ) | |||||||
Earnings from equity method investments | 699 | 685 | 14 | ||||||||
Other, net | (1,536 | ) | (13,965 | ) | 12,429 | ||||||
$ | (185,707 | ) | $ | 238,021 | $ | (423,728 | ) | ||||
Other income and (expenses) decreased by approximately $424 million for the year ended December 31, 2016, compared to the year ended December 31, 2015. Interest expense decreased primarily due to the Company’s discontinuation of interest expense recognition on the senior notes for the period from May 12, 2016 through December 31, 2016, as a result of the Chapter 11 proceedings, lower outstanding debt during the period principally as a result of the senior notes repurchased and exchanged during 2015, and lower amortization of discounts and financing fees. For the period from May 12, 2016 through December 31, 2016, contractual interest, which was not recorded, on the senior notes was approximately $143 million. For the year ended December 31, 2015, the Company recorded a gain on extinguishment of debt of approximately $708 million as a result of the repurchases of a portion of its senior notes. Other expenses decreased primarily due to lower write-offs of deferred financing fees related to the LINN Credit Facility and lower bank fees. See “Debt” under “Liquidity and Capital Resources” below for additional details.
The $1.0 billion in aggregate principal amount of Second Lien Notes issued in November 2015 were accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. For the period from May 12, 2016 through December 31, 2016, unrecorded contractual interest on the Second Lien Notes was approximately $76 million.
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.
56
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table summarizes the components of reorganization items included on the consolidated statement of operations:
Predecessor | |||
Year Ended December 31, 2016 | |||
(in thousands) | |||
Legal and other professional advisory fees | $ | (56,656 | ) |
Unamortized deferred financing fees, discounts and premiums | (52,045 | ) | |
Gain related to interest payable on Predecessor’s Second Lien Notes | 551,000 | ||
Terminated contracts | (66,052 | ) | |
Other | (64,648 | ) | |
Reorganization items, net | $ | 311,599 | |
Income Tax Expense (Benefit)
The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $11 million for the year ended December 31, 2016, compared to an income tax benefit of approximately $6 million for the year ended December 31, 2015. The increased income tax expense is primarily due to additional expense recognized related to unit-based compensation in 2016 for which there was no windfall benefit offset as in 2015.
Loss from Discontinued Operations, Net of Income Taxes
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale) and the deconsolidation of Berry, the Company has classified the results of operations of its California properties and Berry as discontinued operations. Loss from discontinued operations, net of income taxes was approximately $1.8 billion and $1.0 billion for the years ended December 31, 2016, and December 31, 2015, respectively. See Note 4 for additional information.
Net Loss
Net loss decreased by approximately $2.6 billion to approximately $2.2 billion for the year ended December 31, 2016, from approximately $4.8 billion for the year ended December 31, 2015. The decrease was primarily due to lower impairment charges and lower expenses, including interest, partially offset by losses compared to gains on oil and natural gas derivatives for the comparative period, higher loss from discontinued operations, the gain on extinguishment of debt in 2015 and lower production revenues. See discussion above for explanations of variances.
57
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Liquidity and Capital Resources
Since its emergence from Chapter 11 bankruptcy in February 2017, the Company’s sources of cash have primarily consisted of proceeds from its 2017 divestitures of oil and natural gas properties and net cash provided by operating activities. As a result of divesting certain oil and natural gas properties, the Company received over $1.5 billion in net cash proceeds and repaid all of its outstanding debt as of July 31, 2017. The Company has also used its cash to fund capital expenditures, principally for the development of its oil and natural gas properties, and plant and pipeline construction, as well as repurchases of its Class A common stock. Based on current expectations, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations.
Prior to its emergence from bankruptcy, the Company utilized funds from debt and equity offerings, borrowings under its credit facilities and net cash provided by operating activities for liquidity and capital resources, and the primary use was for the development of oil and natural gas properties, as well as for acquisitions.
See below for details regarding capital expenditures for the periods presented:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Oil and natural gas | $ | 199,866 | $ | 39,409 | $ | 126,876 | $ | 286,028 | ||||||||
Plant and pipeline | 93,318 | 4,990 | 36,433 | 2,539 | ||||||||||||
Other | 5,626 | 1,243 | 8,315 | 45,387 | ||||||||||||
Capital expenditures, excluding acquisitions | $ | 298,810 | $ | 45,642 | $ | 171,624 | $ | 333,954 | ||||||||
Capital expenditures, excluding acquisitions – discontinued operations | $ | 2,033 | $ | 436 | $ | 23,128 | $ | 183,741 | ||||||||
The increase in capital expenditures in 2017 was primarily due to oil and natural gas development activities in the Merge/SCOOP/STACK and plant and pipeline construction activities associated with the Chisholm Trail Cryogenic Gas Plant. For 2018, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $134 million, including approximately $34 million related to its oil and natural gas capital program and approximately $98 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Statements of Cash Flows
The following is a comparative cash flow summary:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Net cash: | ||||||||||||||||
Provided by (used in) operating activities | $ | 281,164 | $ | (20,814 | ) | $ | 880,514 | $ | 1,249,457 | |||||||
Provided by (used in) investing activities | 1,242,018 | (58,756 | ) | (235,840 | ) | (310,417 | ) | |||||||||
Provided by (used in) financing activities | (1,113,029 | ) | (560,932 | ) | 48,015 | (938,681 | ) | |||||||||
Net increase (decrease) in cash and cash equivalents | $ | 410,153 | $ | (640,502 | ) | $ | 692,689 | $ | 359 | |||||||
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Operating Activities
Cash provided by operating activities was approximately $281 million and cash used in operating activities was approximately $21 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to approximately $881 million for the year ended December 31, 2016. The decrease was primarily due to lower cash settlements on derivatives, partially offset by higher production related revenues principally due to higher commodity prices. In addition, in February 2017, restricted cash increased by approximately $80 million in order to fund the settlement of certain claims and pay certain professional fees in accordance with the Plan.
Cash provided by operating activities for the year ended December 31, 2016, was approximately $881 million, compared to approximately $1.2 billion for the year ended December 31, 2015. The decrease was primarily due to lower cash settlements on derivatives and lower production related revenues principally due to lower commodity prices and lower production volumes, partially offset by lower expenses.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Cash flow from investing activities: | ||||||||||||||||
Capital expenditures | $ | (260,316 | ) | $ | (58,006 | ) | $ | (215,857 | ) | $ | (599,050 | ) | ||||
Deconsolidation of Berry Petroleum Company, LLC | — | — | (28,549 | ) | — | |||||||||||
Investment in discontinued operations | — | — | — | (132,332 | ) | |||||||||||
Proceeds from sale of properties and equipment and other | 1,156,691 | (166 | ) | (4,690 | ) | 345,770 | ||||||||||
Net cash provided by (used in) investing activities – continuing operations | 896,375 | (58,172 | ) | (249,096 | ) | (385,612 | ) | |||||||||
Net cash provided by (used in) investing activities – discontinued operations | 345,643 | (584 | ) | 13,256 | 75,195 | |||||||||||
Net cash provided by (used in) investing activities | $ | 1,242,018 | $ | (58,756 | ) | $ | (235,840 | ) | $ | (310,417 | ) | |||||
The primary use of cash in investing activities is for the development of the Company’s oil and natural gas properties. Capital expenditures increased in 2017 primarily due to higher spending on development activities in the Company’s Mid-Continent, Rockies and TexLa regions. Capital expenditures decreased during 2016 and 2015 primarily due to lower spending on development activities throughout the Company’s various operating regions as a result of continued low commodity prices. The Company made no acquisitions of properties during 2017, 2016 or 2015. The Company has classified the cash flows of its California properties and Berry as discontinued operations.
Proceeds from sale of properties and equipment and other for the ten months ended December 31, 2017, include cash proceeds received of approximately $258 million from the Williston Assets sale, $195 million from the Washakie Assets Sale, approximately $49 million from the South Texas Assets Sales, approximately $31 million from the Permian Basin Assets Sales, approximately $74 million from the Salt Creek Assets Sale and approximately $565 million from the Jonah Assets Sale. An additional $3 million received from the 2017 divestitures and approximately $12 million received from the pending divestiture remains in escrow and is currently classified as restricted cash. See Note 4 for additional details of divestitures. Proceeds from the sale of properties and equipment and other for the year ended December 31, 2015, include approximately $276 million in net cash proceeds received from the Howard County Assets Sale in August 2015.
59
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Financing Activities
Cash used in financing activities was approximately $1.1 billion and $561 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively, compared to cash provided by financing activities of approximately $48 million for the year ended December 31, 2016. During the year ended December 31, 2015, cash used in financing activities was approximately $939 million. In 2017, the primary use of cash in financing activities was for repayments of debt. During the year ended December 31, 2016, the Company borrowed approximately $979 million under its credit facility, including approximately $919 million in February 2016 which represented the remaining undrawn amount that was available. In addition, during the year ended December 31, 2016, the Company repaid approximately $913 million under its credit facility and term loan, primarily using the net cash proceeds from canceled derivative contracts (see Note 7).
The following provides a comparative summary of proceeds from borrowings and repayments of debt:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Proceeds from borrowings: | ||||||||||||||||
Successor Credit Facility | $ | 190,000 | $ | — | $ | — | $ | — | ||||||||
Predecessor Credit Facility | — | — | 978,500 | 1,445,000 | ||||||||||||
$ | 190,000 | $ | — | $ | 978,500 | $ | 1,445,000 | |||||||||
Repayments of debt: | ||||||||||||||||
Successor Credit Facility | $ | (790,000 | ) | $ | — | $ | — | $ | — | |||||||
Successor Term Loan | (300,000 | ) | — | — | — | |||||||||||
Predecessor Credit Facility | — | (1,038,986 | ) | (814,298 | ) | (1,275,000 | ) | |||||||||
Predecessor senior notes | — | — | — | (553,461 | ) | |||||||||||
Predecessor bridge loan and term loan | — | — | (98,911 | ) | — | |||||||||||
$ | (1,090,000 | ) | $ | (1,038,986 | ) | $ | (913,209 | ) | $ | (1,828,461 | ) | |||||
On February 28, 2017, the Company canceled its obligations under the Predecessor Credit Facility and entered into the Successor Credit Facility, which was a net transaction and is reflected as such on the consolidated statement of cash flows. In addition, in February 2017, the Company made a $30 million payment to holders of claims under the Second Lien Notes, and also issued 41,359,806 shares of Class A common stock to participants in the rights offerings extended by the Company to certain holders of claims arising under the Second Lien Notes and the Unsecured Notes for net proceeds of approximately $514 million. See Note 15 for details about the Company’s borrowings and repayments of debt that were reflected as noncash transactions.
60
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Debt
The following summarizes the Company’s outstanding debt:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands, except percentages) | ||||||||
Revolving credit facility | $ | — | $ | — | ||||
Predecessor credit facility | — | 1,654,745 | ||||||
Predecessor term loan | — | 284,241 | ||||||
6.50% senior notes due May 2019 | — | 562,234 | ||||||
6.25% senior notes due November 2019 | — | 581,402 | ||||||
8.625% senior notes due April 2020 | — | 718,596 | ||||||
12.00% senior secured second lien notes due December 2020 | — | 1,000,000 | ||||||
7.75% senior notes due February 2021 | — | 779,474 | ||||||
6.50% senior notes due September 2021 | — | 381,423 | ||||||
Net unamortized deferred financing fees | — | (1,257 | ) | |||||
Total debt, net | — | 5,960,858 | ||||||
Less current portion, net (1) | — | (1,937,729 | ) | |||||
Less liabilities subject to compromise (2) | — | (4,023,129 | ) | |||||
Long-term debt | $ | — | $ | — | ||||
(1) | Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016. |
(2) | The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled. |
As of January 31, 2018, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit).
In connection with the entry into the Revolving Credit Facility in August 2017, the Successor Credit Facility was terminated and repaid in full. On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes were canceled.
During the year ended December 31, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $927 million of its outstanding senior notes as follows:
• | 6.50% senior notes due May 2019 – $53 million; |
• | 6.25% senior notes due November 2019 – $395 million; |
• | 8.625% senior notes due April 2020 – $295 million; |
• | 7.75% senior notes due February 2021 – $36 million; and |
• | 6.50% senior notes due September 2021 – $148 million. |
In connection, with the repurchases, the Company paid approximately $553 million in cash.
For additional information related to the Company’s outstanding debt, see Note 6.
61
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million, and on October 4, 2017, the Company’s Board authorized another increase up to a total of $400 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 through December 2017, the Company repurchased an aggregate of 5,690,192 shares of Class A common stock at an average price of $34.85 per share for a total cost of approximately $198 million.
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are participants in the Revolving Credit Facility. The Revolving Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; 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.
Dividends/Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility.
Contingencies
See Item 3. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Off-Balance Sheet Arrangements
The Company enters into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit. In addition, the Company enters into other contractual agreements in the normal course of business for processing and transportation as well as for other oil and natural gas activities. Other than the items discussed above, there are no other arrangements, transactions or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or capital resource positions.
62
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Commitments and Contractual Obligations
The following is a summary of the Company’s commitments and contractual obligations as of December 31, 2017:
Payments Due | ||||||||||||||||||||
Contractual Obligations | Total | 2018 | 2019 – 2020 | 2021 – 2022 | 2023 and Beyond | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Operating lease obligations: | ||||||||||||||||||||
Office, property and equipment leases | $ | 5,292 | $ | 2,812 | $ | 2,468 | $ | 12 | $ | — | ||||||||||
Other: | ||||||||||||||||||||
Commodity derivatives | 12,952 | 10,103 | 2,849 | — | — | |||||||||||||||
Asset retirement obligations | 164,553 | 3,926 | 8,613 | 7,731 | 144,283 | |||||||||||||||
Capital commitments | 36,035 | 36,020 | 10 | 5 | — | |||||||||||||||
$ | 218,832 | $ | 52,861 | $ | 13,940 | $ | 7,748 | $ | 144,283 | |||||||||||
Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based on the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. 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.
Below are expanded discussions of the Company’s more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of its financial statements. See Note 1 for details about additional accounting policies and estimates made by Company management.
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1.
Fresh Start Accounting
Upon the Company’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of ASC 852 which resulted in the Company becoming a new entity for financial reporting purposes. In accordance with ASC 852, the Company was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.
Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations” (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes” (“ASC 740”). The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh start accounting were reflected on the consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the consolidated statement of operations for the two months ended February 28, 2017. As a result of the application of fresh start accounting and the effects of the implementation of the
63
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
plan of reorganization, the consolidated financial statements on or after February 28, 2017, are not comparable with the consolidated financial statements prior to that date. See Note 3 for additional information.
Oil and Natural Gas Reserves
Proved reserves are based on the quantities of oil, natural gas and NGL that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The independent engineering firm, DeGolyer and MacNaughton, prepared a reserve and economic evaluation of all of the Company properties on a well-by-well basis as of December 31, 2017, and the reserve estimates reported herein were prepared by DeGolyer and MacNaughton. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer.
Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations as well as the Company’s application of fresh start accounting. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years.
The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various economic assumptions and the judgments of the individuals preparing the estimates. In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data” and see also Item 1. “Business.”
Oil and Natural Gas Properties
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use.
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) 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
64
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.
The Company recorded no impairment charges associated with proved oil and natural gas properties during 2017. Based on the analysis described above, for the years ended December 31, 2016, and December 31, 2015, the Company recorded noncash impairment charges of approximately $165 million and $4.1 billion, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.
The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2017, or December 31, 2016. Based on the analysis described above, for the year ended December 31, 2015, the Company recorded noncash impairment charges of approximately $828 million associated with unproved oil and natural gas properties. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Accounting for Investment in Roan Resources LLC
The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. See Note 5 for additional details about the Company’s investment in Roan.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risks are attributable to fluctuations in commodity prices and interest rates. These risks can affect the Company’s business, financial condition, operating results and cash flows. See below for quantitative and qualitative information about these risks.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Commodity Price Risk
The Company’s most significant market risk relates to prices of oil, natural gas and NGL. The Company expects commodity prices to remain volatile and unpredictable. As commodity prices decline or rise significantly, revenues and cash flows are
65
Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Continued
likewise affected. In addition, future declines in commodity prices may result in noncash write-downs of the Company’s carrying amounts of its assets.
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The Company does not enter into derivative contracts for trading purposes. The appropriate level of production to be hedged is an ongoing consideration based on a variety of factors, including among other things, current and future expected commodity market prices, the Company’s overall risk profile, including leverage and size and scale considerations, as well as any requirements for or restrictions on levels of hedging contained in any credit facility or other debt instrument applicable at the time. In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain higher revenues for its production if commodity prices recover during the duration of the contracts. As a result, the appropriate percentage of production volumes to be hedged may change over time.
At December 31, 2017, the fair value of fixed price swaps and collars was a net liability of approximately $2 million. A 10% increase in the index oil and natural gas prices above the December 31, 2017, prices would result in a net liability of approximately $45 million, which represents a decrease in the fair value of approximately $43 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2017, prices would result in a net asset of approximately $38 million, which represents an increase in the fair value of approximately $40 million.
At December 31, 2016, the fair value of fixed price swaps and collars was a net liability of approximately $85 million. A 10% increase in the index oil and natural gas prices above the December 31, 2016, prices would result in a net liability of approximately $183 million, which represents a decrease in the fair value of approximately $98 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2016, prices would result in a net asset of approximately $13 million, which represents an increase in the fair value of approximately $98 million.
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 depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts. Additionally, 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 flows could be impacted.
Interest Rate Risk
At December 31, 2017, the Company had no debt outstanding under the Revolving Credit Facility. At December 31, 2016, the Company had debt outstanding under the Predecessor Credit Facility of approximately $1.9 billion which incurred interest at floating rates. A 1% increase in the respective market rates would result in an estimated $19 million increase in annual interest expense.
66
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page | |
67
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. The Company’s internal control over financial reporting is a process designed under the supervision of its Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated 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 risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2017, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework (2013) by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2017, based on those criteria.
/s/ Linn Energy, Inc.
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Linn Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Linn Energy, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, statements of equity, and statements of cash flows for the ten months ended December 31, 2017 (Successor), the two months ended February 28, 2017 and for the years ended December 31, 2016 and 2015 (Predecessor), and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the ten months ended December 31, 2017 (Successor), the two months ended February 28, 2017 and for the years ended December 31, 2016 and 2015 (Predecessor), in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 27, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis of Presentation
As discussed in Note 2 to the consolidated financial statements, the Company emerged from bankruptcy on February 28, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 2.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 2005.
Houston, Texas
February 27, 2018
69
To the Stockholders and Board of Directors
Linn Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Linn Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2017 and 2016, the related consolidated statements of operations, statements of equity, and statements of cash flows for the ten months ended December 31, 2017 (Successor), the two months ended February 28, 2017 and for the years ended December 31, 2016 and 2015 (Predecessor), and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of 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.
/s/ KPMG LLP
Houston, Texas
February 27, 2018
70
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands, except share and unit amounts) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 464,508 | $ | 694,857 | ||||
Accounts receivable – trade, net | 140,485 | 198,064 | ||||||
Derivative instruments | 9,629 | — | ||||||
Restricted cash | 56,445 | 1,602 | ||||||
Other current assets | 79,771 | 105,310 | ||||||
Assets held for sale | 106,963 | — | ||||||
Current assets of discontinued operations | — | 701 | ||||||
Total current assets | 857,801 | 1,000,534 | ||||||
Noncurrent assets: | ||||||||
Oil and natural gas properties (successful efforts method) | 950,083 | 12,349,117 | ||||||
Less accumulated depletion and amortization | (49,619 | ) | (9,843,908 | ) | ||||
900,464 | 2,505,209 | |||||||
Other property and equipment | 480,729 | 618,262 | ||||||
Less accumulated depreciation | (28,658 | ) | (217,724 | ) | ||||
452,071 | 400,538 | |||||||
Derivative instruments | 469 | — | ||||||
Deferred income taxes | 198,417 | — | ||||||
Equity method investments | 464,926 | 6,200 | ||||||
Other noncurrent assets | 6,975 | 7,784 | ||||||
Noncurrent assets of discontinued operations | — | 740,326 | ||||||
670,787 | 754,310 | |||||||
Total noncurrent assets | 2,023,322 | 3,660,057 | ||||||
Total assets | $ | 2,881,123 | $ | 4,660,591 | ||||
LIABILITIES AND EQUITY (DEFICIT) | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued expenses | $ | 253,975 | $ | 295,081 | ||||
Derivative instruments | 10,103 | 82,508 | ||||||
Current portion of long-term debt, net | — | 1,937,729 | ||||||
Other accrued liabilities | 58,617 | 25,979 | ||||||
Liabilities held for sale | 43,302 | — | ||||||
Current liabilities of discontinued operations | — | 321 | ||||||
Total current liabilities | 365,997 | 2,341,618 | ||||||
Derivative instruments | 2,849 | 11,349 | ||||||
Other noncurrent liabilities | 160,720 | 360,405 | ||||||
Noncurrent liabilities of discontinued operations | — | 39,202 | ||||||
Liabilities subject to compromise | — | 4,305,005 | ||||||
Commitments and contingencies (Note 11) | ||||||||
71
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands, except share and unit amounts) | ||||||||
Equity (deficit): | ||||||||
Predecessor units issued and outstanding (no units issued or outstanding at December 31, 2017; 352,792,474 units issued and outstanding at December 31, 2016) | — | 5,386,885 | ||||||
Predecessor accumulated deficit | — | (7,783,873 | ) | |||||
Successor preferred stock ($0.001 par value, 30,000,000 shares authorized and no shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016) | — | — | ||||||
Successor Class A common stock ($0.001 par value, 270,000,000 shares authorized and 83,582,176 shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016) | 84 | — | ||||||
Successor additional paid-in capital | 1,899,642 | — | ||||||
Successor retained earnings | 432,860 | — | ||||||
Total common stockholders’/unitholders’ equity (deficit) | 2,332,586 | (2,396,988 | ) | |||||
Noncontrolling interests | 18,971 | — | ||||||
Total equity (deficit) | 2,351,557 | (2,396,988 | ) | |||||
Total liabilities and equity (deficit) | $ | 2,881,123 | $ | 4,660,591 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
72
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands, except per share and per unit amounts) | ||||||||||||||||
Revenues and other: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 709,363 | $ | 188,885 | $ | 874,161 | $ | 1,065,795 | ||||||||
Gains (losses) on oil and natural gas derivatives | 13,533 | 92,691 | (164,330 | ) | 1,027,014 | |||||||||||
Marketing revenues | 82,943 | 6,636 | 36,505 | 43,876 | ||||||||||||
Other revenues | 20,839 | 9,915 | 93,308 | 97,771 | ||||||||||||
826,678 | 298,127 | 839,644 | 2,234,456 | |||||||||||||
Expenses: | ||||||||||||||||
Lease operating expenses | 208,446 | 49,665 | 296,891 | 352,077 | ||||||||||||
Transportation expenses | 113,128 | 25,972 | 161,574 | 167,023 | ||||||||||||
Marketing expenses | 69,008 | 4,820 | 29,736 | 35,278 | ||||||||||||
General and administrative expenses | 117,548 | 71,745 | 237,841 | 285,996 | ||||||||||||
Exploration costs | 3,137 | 93 | 4,080 | 9,473 | ||||||||||||
Depreciation, depletion and amortization | 133,711 | 47,155 | 342,614 | 520,219 | ||||||||||||
Impairment of long-lived assets | — | — | 165,044 | 4,960,144 | ||||||||||||
Taxes, other than income taxes | 47,553 | 14,877 | 67,648 | 97,685 | ||||||||||||
(Gains) losses on sale of assets and other, net | (623,072 | ) | 829 | 16,257 | (194,805 | ) | ||||||||||
69,459 | 215,156 | 1,321,685 | 6,233,090 | |||||||||||||
Other income and (expenses): | ||||||||||||||||
Interest expense, net of amounts capitalized | (12,361 | ) | (16,725 | ) | (184,870 | ) | (456,749 | ) | ||||||||
Gain on extinguishment of debt | — | — | — | 708,050 | ||||||||||||
Earnings from equity method investments | 11,840 | 157 | 699 | 685 | ||||||||||||
Other, net | (6,233 | ) | (149 | ) | (1,536 | ) | (13,965 | ) | ||||||||
(6,754 | ) | (16,717 | ) | (185,707 | ) | 238,021 | ||||||||||
Reorganization items, net | (8,851 | ) | 2,331,189 | 311,599 | — | |||||||||||
Income (loss) from continuing operations before income taxes | 741,614 | 2,397,443 | (356,149 | ) | (3,760,613 | ) | ||||||||||
Income tax expense (benefit) | 388,942 | (166 | ) | 11,194 | (6,393 | ) | ||||||||||
Income (loss) from continuing operations | 352,672 | 2,397,609 | (367,343 | ) | (3,754,220 | ) | ||||||||||
Income (loss) from discontinued operations, net of income taxes | 82,995 | (548 | ) | (1,804,513 | ) | (1,005,591 | ) | |||||||||
Net income (loss) | 435,667 | 2,397,061 | (2,171,856 | ) | (4,759,811 | ) | ||||||||||
Net income attributable to noncontrolling interests | 2,807 | — | — | — | ||||||||||||
Net income (loss) attributable to common stockholders/unitholders | $ | 432,860 | $ | 2,397,061 | $ | (2,171,856 | ) | $ | (4,759,811 | ) | ||||||
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Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands, except per share and per unit amounts) | ||||||||||||||||
Income (loss) per share/unit attributable to common stockholders/unitholders: | ||||||||||||||||
Income (loss) from continuing operations per share/unit – Basic | $ | 3.99 | $ | 6.80 | $ | (1.04 | ) | $ | (10.94 | ) | ||||||
Income (loss) from continuing operations per share/unit – Diluted | $ | 3.92 | $ | 6.80 | $ | (1.04 | ) | $ | (10.94 | ) | ||||||
Income (loss) from discontinued operations per share/unit – Basic | $ | 0.95 | $ | (0.01 | ) | $ | (5.12 | ) | $ | (2.93 | ) | |||||
Income (loss) from discontinued operations per share/unit – Diluted | $ | 0.93 | $ | (0.01 | ) | $ | (5.12 | ) | $ | (2.93 | ) | |||||
Net income (loss) per share/unit – Basic | $ | 4.94 | $ | 6.79 | $ | (6.16 | ) | $ | (13.87 | ) | ||||||
Net income (loss) per share/unit – Diluted | $ | 4.85 | $ | 6.79 | $ | (6.16 | ) | $ | (13.87 | ) | ||||||
Weighted average shares/units outstanding – Basic | 87,646 | 352,792 | 352,653 | 343,323 | ||||||||||||
Weighted average shares/units outstanding – Diluted | 88,719 | 352,792 | 352,653 | 343,323 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
74
LINN ENERGY, INC.
CONSOLIDATED STATEMENTS OF EQUITY (PREDECESSOR)
Units | Unitholders’ Capital | Accumulated Deficit | Treasury Units (at Cost) | Total Unitholders’ Capital (Deficit) | ||||||||||||||
(in thousands) | ||||||||||||||||||
December 31, 2014 (Predecessor) | 331,975 | $ | 5,395,811 | $ | (852,206 | ) | $ | — | $ | 4,543,605 | ||||||||
Sale of units, net of offering costs of $8,762 | 19,622 | 224,665 | — | — | 224,665 | |||||||||||||
Issuance of units | 3,611 | — | — | — | — | |||||||||||||
Cancellation of units | (191 | ) | (672 | ) | — | 672 | — | |||||||||||
Purchase of units | — | — | (672 | ) | (672 | ) | ||||||||||||
Distributions to unitholders | (323,878 | ) | — | — | (323,878 | ) | ||||||||||||
Unit-based compensation expenses | 56,136 | — | — | 56,136 | ||||||||||||||
Reclassification of distributions paid on forfeited restricted units | 865 | — | — | 865 | ||||||||||||||
Excess tax benefit from unit-based compensation and other | (9,811 | ) | — | — | (9,811 | ) | ||||||||||||
Net loss | — | (4,759,811 | ) | — | (4,759,811 | ) | ||||||||||||
December 31, 2015 (Predecessor) | 355,017 | 5,343,116 | (5,612,017 | ) | — | (268,901 | ) | |||||||||||
Issuance of units | 5 | — | — | — | — | |||||||||||||
Cancellation of units | (2,230 | ) | — | — | — | — | ||||||||||||
Unit-based compensation expenses | 44,218 | — | — | 44,218 | ||||||||||||||
Other | (449 | ) | — | — | (449 | ) | ||||||||||||
Net loss | — | (2,171,856 | ) | — | (2,171,856 | ) | ||||||||||||
December 31, 2016 (Predecessor) | 352,792 | 5,386,885 | (7,783,873 | ) | — | (2,396,988 | ) | |||||||||||
Net income | — | 2,397,061 | — | 2,397,061 | ||||||||||||||
Other | (73 | ) | — | — | (73 | ) | ||||||||||||
February 28, 2017 (Predecessor) | 352,792 | 5,386,812 | (5,386,812 | ) | — | — | ||||||||||||
Cancellation of predecessor equity | (352,792 | ) | (5,386,812 | ) | 5,386,812 | — | — | |||||||||||
February 28, 2017 (Predecessor) | — | $ | — | $ | — | $ | — | $ | — | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
75
LINN ENERGY, INC.
CONSOLIDATED STATEMENT OF EQUITY (SUCCESSOR)
Class A Common Stock | Additional Paid-in Capital | Retained Earnings | Total Common Stockholders’ Equity | Noncontrolling Interests | Total Equity | |||||||||||||||||||||
Shares | Amount | |||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Issuances of successor Class A common stock | 89,230 | $ | 89 | $ | 2,021,142 | $ | — | $ | 2,021,231 | $ | — | $ | 2,021,231 | |||||||||||||
Share-based compensation expenses | — | 13,750 | — | 13,750 | — | 13,750 | ||||||||||||||||||||
February 28, 2017 (Successor) | 89,230 | 89 | 2,034,892 | — | 2,034,981 | — | 2,034,981 | |||||||||||||||||||
Net income | — | — | 432,860 | 432,860 | 2,807 | 435,667 | ||||||||||||||||||||
Issuances of successor Class A common stock | 42 | — | — | — | — | — | — | |||||||||||||||||||
Repurchases of successor Class A common stock | (5,690 | ) | (5 | ) | (198,283 | ) | — | (198,288 | ) | — | (198,288 | ) | ||||||||||||||
Share-based compensation expenses | — | 77,790 | — | 77,790 | — | 77,790 | ||||||||||||||||||||
Initial allocation of noncontrolling interests upon conversion of subsidiary units | — | (17,605 | ) | — | (17,605 | ) | 17,605 | — | ||||||||||||||||||
Distributions to noncontrolling interests | — | — | — | — | (1,596 | ) | (1,596 | ) | ||||||||||||||||||
Subsidiary equity transactions | — | (155 | ) | — | (155 | ) | 155 | — | ||||||||||||||||||
Other | — | 3,003 | — | 3,003 | — | 3,003 | ||||||||||||||||||||
December 31, 2017 (Successor) | 83,582 | $ | 84 | $ | 1,899,642 | $ | 432,860 | $ | 2,332,586 | $ | 18,971 | $ | 2,351,557 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Cash flow from operating activities: | ||||||||||||||||
Net income (loss) | $ | 435,667 | $ | 2,397,061 | $ | (2,171,856 | ) | $ | (4,759,811 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||||||
(Income) loss from discontinued operations | (82,995 | ) | 548 | 1,804,513 | 1,005,591 | |||||||||||
Depreciation, depletion and amortization | 133,711 | 47,155 | 342,614 | 520,219 | ||||||||||||
Impairment of long-lived assets | — | — | 165,044 | 4,960,144 | ||||||||||||
Deferred income taxes | 381,313 | (166 | ) | 11,367 | 4,606 | |||||||||||
Total (gains) losses on derivatives, net | (13,533 | ) | (92,691 | ) | 164,330 | (1,027,014 | ) | |||||||||
Cash settlements on derivatives | 26,793 | (11,572 | ) | 860,778 | 1,135,319 | |||||||||||
Share-based compensation expenses | 41,285 | 50,255 | 44,218 | 56,136 | ||||||||||||
Gain on extinguishment of debt | — | — | — | (708,050 | ) | |||||||||||
Amortization and write-off of deferred financing fees | 3,711 | 1,338 | 13,356 | 30,993 | ||||||||||||
(Gains) losses on sale of assets and other, net | (667,549 | ) | 1,069 | 13,007 | (188,200 | ) | ||||||||||
Reorganization items, net | — | (2,359,364 | ) | (365,367 | ) | — | ||||||||||
Changes in assets and liabilities: | ||||||||||||||||
(Increase) decrease in accounts receivable – trade, net | 41,094 | (7,216 | ) | (71,059 | ) | 211,884 | ||||||||||
(Increase) decrease in other assets | 4,548 | 402 | (17,733 | ) | (9,142 | ) | ||||||||||
(Increase) decrease in restricted cash | 2,151 | (80,164 | ) | — | — | |||||||||||
Increase (decrease) in accounts payable and accrued expenses | (48,963 | ) | 20,949 | 38,468 | (98,223 | ) | ||||||||||
Increase (decrease) in other liabilities | 7,740 | 2,801 | (515 | ) | (51,266 | ) | ||||||||||
Net cash provided by (used in) operating activities – continuing operations | 264,973 | (29,595 | ) | 831,165 | 1,083,186 | |||||||||||
Net cash provided by operating activities – discontinued operations | 16,191 | 8,781 | 49,349 | 166,271 | ||||||||||||
Net cash provided by (used in) operating activities | 281,164 | (20,814 | ) | 880,514 | 1,249,457 | |||||||||||
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Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Cash flow from investing activities: | ||||||||||||||||
Development of oil and natural gas properties | (171,721 | ) | (50,597 | ) | (172,298 | ) | (550,083 | ) | ||||||||
Purchases of other property and equipment | (88,595 | ) | (7,409 | ) | (43,559 | ) | (48,967 | ) | ||||||||
Deconsolidation of Berry Petroleum Company, LLC cash | — | — | (28,549 | ) | — | |||||||||||
Investment in discontinued operations | — | — | — | (132,332 | ) | |||||||||||
Proceeds from sale of properties and equipment and other | 1,156,691 | (166 | ) | (4,690 | ) | 345,770 | ||||||||||
Net cash provided by (used in) investing activities – continuing operations | 896,375 | (58,172 | ) | (249,096 | ) | (385,612 | ) | |||||||||
Net cash provided by (used in) investing activities – discontinued operations | 345,643 | (584 | ) | 13,256 | 75,195 | |||||||||||
Net cash provided by (used in) investing activities | 1,242,018 | (58,756 | ) | (235,840 | ) | (310,417 | ) | |||||||||
Cash flow from financing activities: | ||||||||||||||||
Proceeds from rights offerings, net | — | 514,069 | — | — | ||||||||||||
Proceeds from sale of units | — | — | — | 224,665 | ||||||||||||
Repurchases of shares | (198,288 | ) | — | — | — | |||||||||||
Proceeds from borrowings | 190,000 | — | 978,500 | 1,445,000 | ||||||||||||
Repayments of debt | (1,090,000 | ) | (1,038,986 | ) | (913,209 | ) | (1,828,461 | ) | ||||||||
Payment to holders of claims under the second lien notes | — | (30,000 | ) | — | — | |||||||||||
Distributions to unitholders | — | — | — | (323,878 | ) | |||||||||||
Debt issuance costs paid | (7,729 | ) | — | (752 | ) | (17,916 | ) | |||||||||
Settlement of advance from discontinued operations | — | — | — | (129,217 | ) | |||||||||||
Excess tax benefit from unit-based compensation | — | — | — | (9,467 | ) | |||||||||||
Other | (7,012 | ) | (6,015 | ) | (14,823 | ) | (74,958 | ) | ||||||||
Net cash provided by (used in) financing activities – continuing operations | (1,113,029 | ) | (560,932 | ) | 49,716 | (714,232 | ) | |||||||||
Net cash used in financing activities – discontinued operations | — | — | (1,701 | ) | (224,449 | ) | ||||||||||
Net cash provided by (used in) financing activities | (1,113,029 | ) | (560,932 | ) | 48,015 | (938,681 | ) | |||||||||
Net increase (decrease) in cash and cash equivalents | 410,153 | (640,502 | ) | 692,689 | 359 | |||||||||||
Cash and cash equivalents: | ||||||||||||||||
Beginning | 54,355 | 694,857 | 2,168 | 1,809 | ||||||||||||
Ending | 464,508 | 54,355 | 694,857 | 2,168 | ||||||||||||
Less cash and cash equivalents of discontinued operations at end of year | — | — | — | (1,023 | ) | |||||||||||
Ending – continuing operations | $ | 464,508 | $ | 54,355 | $ | 694,857 | $ | 1,145 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Note 1 – Basis of Presentation and Significant Accounting Policies
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. is not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 4). The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor.
Nature of Business
LINN Energy is an independent oil and natural gas company that was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
The Company’s properties are currently located in six operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; Mid-Continent, which includes Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and Rockies, which includes Utah properties located in Uinta Basin. The Company also owns a 50% equity interest in Roan Resources LLC (“Roan”), which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma. During 2017, the Company divested of its properties located in previous operating regions California and South Texas.
Principles of Consolidation and Reporting
The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and are presented as a component of equity. Changes in the Company’s ownership interests in Holdco that do not result in deconsolidation are recognized in equity. See Note 14 for additional information about noncontrolling interests. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. See Note 5 for additional information about equity method investments.
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The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. The Company has also classified the assets and liabilities of its California properties, as well as the results of operations and cash flows of its California properties and Berry, as discontinued operations on its consolidated financial statements. Such reclassifications have no impact on previously reported net income (loss), stockholders’/unitholders’ equity (deficit) or cash flows. See Note 4 for additional information.
Bankruptcy Accounting
The consolidated financial statements have been prepared as if the Company will continue as a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.
Upon emergence from bankruptcy on February 28, 2017, the Company adopted fresh start accounting which resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the consolidated financial statements on or after February 28, 2017, are not comparable with the consolidated financial statements prior to that date. See Note 3 for additional information.
Use of Estimates
The preparation of the accompanying consolidated 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, and fair values of commodity derivatives. In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes.
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 Adopted Accounting Standards
In March 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted this ASU on January 1, 2017. The adoption of this ASU had no impact on the Company’s historical financial statements or related disclosures. Upon adoption and subsequently this ASU will result in excess tax benefits, which were previously recorded in equity on the balance sheets and classified as financing activities on the statements of cash flows, being recorded in the statements of operations and classified as operating activities on the statements of cash flows. Additionally, the Company elected to begin accounting for forfeitures as they occur.
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New Accounting Standards Issued But Not Yet Adopted
In November 2016, the FASB issued an ASU that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statements of cash flows.
In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact its balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities.
In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect its net income to be materially impacted, the Company’s gross revenues and expenses are expected to be impacted based on a determination of when control of the commodity is transferred and whether it is acting as a principal or agent in certain transactions. In addition, the Company expects to recognize revenue for commodities received as noncash consideration in exchange for services provided by its midstream business and revenue and associated cost of product for the subsequent sale of those same commodities. This recognition will result in an increase to revenues and expenses with no impact on net income. The Company continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls and financial statements. The Company will adopt this new standard as of January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.
Cash Equivalents
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
Accounts Receivable – Trade, Net
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million and $8 million at December 31, 2017, and December 31, 2016, respectively.
Inventories
Materials, supplies and commodity inventories are valued at the lower of average cost and net realizable value.
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Oil and Natural Gas Properties
As a result of the application of fresh start accounting, the Company recorded its oil and natural gas properties at fair value as of the Effective Date. See Note 3 for additional information.
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $158,000 for the ten months ended December 31, 2017, and approximately $257,000 and $3 million for the years ended December 31, 2016, and December 31, 2015, respectively. The Company did not capitalize any interest costs during the two months ended February 28, 2017.
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) 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. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.
Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties:
Predecessor | |||||||
Year Ended December 31, 2016 | Year Ended December 31, 2015 | ||||||
(in thousands) | |||||||
Mid-Continent region | $ | 141,902 | $ | 405,370 | |||
Rockies region | 23,142 | 1,592,256 | |||||
Hugoton Basin region | — | 1,667,768 | |||||
TexLa region | — | 352,422 | |||||
Permian Basin region | — | 71,990 | |||||
South Texas region | — | 42,433 | |||||
$ | 165,044 | $ | 4,132,239 | ||||
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The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. The Company recorded no impairment charges associated with proved properties during the ten months ended December 31, 2017, or the two months ended February 28, 2017.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.
Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties:
Predecessor | |||
Year Ended December 31, 2015 | |||
(in thousands) | |||
TexLa region | $ | 416,846 | |
Permian Basin region | 226,922 | ||
Rockies region | 184,137 | ||
$ | 827,905 | ||
The Company recorded no impairment charges associated with unproved properties for the ten months ended December 31, 2017, the two months ended February 28, 2017, or the year ended December 31, 2016.
The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Exploration Costs
Exploratory geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
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Other Property and Equipment
Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from one to 39 years for the individual asset or group of assets.
Accounting for Investment in Roan Resources LLC
The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. See Note 5 for additional details about the Company’s investment in Roan.
Derivative Instruments
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices 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. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that 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 or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes.
A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.
Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. 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 and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
Revenue Recognition
Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass
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to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable.
Upon the adoption of fresh start accounting on February 28, 2017, the Company has elected the sales method to account for natural gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. The Predecessor had applied the entitlements method to account for natural gas production imbalances in previous periods.
The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.
Share-Based Compensation
The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur. See Note 15 for additional details about the Company’s accounting for share-based compensation.
Deferred Financing Fees
The Company has incurred legal and bank fees related to the issuance of debt. At December 31, 2017, net deferred financing fees of approximately $4 million are included in “other noncurrent assets” on the consolidated balance sheet. At December 31, 2016, net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense.
For the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended December 31, 2016, and December 31, 2015, amortization expense of approximately $1 million, $1 million, $10 million and $20 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the ten months ended December 31, 2017, and the years ended December 31, 2016, and December 31, 2015, approximately $3 million, $1 million and $7 million, respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Company’s credit facilities. In addition, for the year ended December 31, 2016, approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. No fees were written off to expense for the two months ended February 28, 2017.
Fair Value of Financial Instruments
The carrying values of the Company’s receivables, payables and credit facilities are estimated to be substantially the same as their fair values at December 31, 2017, and December 31, 2016. See Note 6 for fair value disclosures related to the Company’s other debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
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Income Taxes
The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 17 for additional details of the Company’s accounting for income taxes.
Note 2 – Emergence From Voluntary Reorganization Under Chapter 11
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.
On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC (“LAC”) and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Plan of Reorganization
In accordance with the Plan, on the Effective Date:
• | The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed wholly owned subsidiary of the Predecessor and the borrower under the Credit Agreement (as amended, the “Successor Credit Facility”) entered into in connection with the reorganization, in exchange for equity interests in Holdco II and the issuance of interests in the Successor Credit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash, an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor, which the Predecessor distributed to certain of its creditors in satisfaction of their claims, and the Successor’s agreement to honor certain obligations of the Predecessor under the Plan. In connection with this transfer, certain entities composing the Successor guaranteed the Successor Credit Facility. Contemporaneously with the reorganization transactions and pursuant to the Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims. |
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• | The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“Predecessor Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Successor Credit Facility. As a result, all outstanding obligations under the Predecessor Credit Facility were canceled. |
• | Holdco II, as borrower, entered into the Successor Credit Facility with the holders of claims under the Predecessor Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million. For additional information about the Successor Credit Facility, see Note 6. |
• | The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below. As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. |
• | The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. |
• | All units of the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Successor issued in the aggregate 89,229,892 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. |
• | The Successor entered into a registration rights agreement with certain parties, pursuant to which the Company agreed to, among other things, file a registration statement with the SEC within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). |
• | By operation of the Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Successor formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Successor and five directors selected by a six-person selection committee. |
Rights Offerings
On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”). In accordance with the Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the eligible creditors were offered the right to purchase Class A common stock from the Successor in connection with the consummation of the Plan for an aggregate purchase price of $530 million.
Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the shares that were not duly subscribed to pursuant to the offerings at the discounted per share price set forth in the Backstop Commitment Agreement by parties other than Backstop Parties. Pursuant to the Backstop Commitment Agreement, the Backstop Parties were entitled to receive, on the Effective Date, a commitment premium equal to 4.0% of the $530 million committed amount, of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement.
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On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the rights offerings and the related issuances of Class A common stock were completed.
Liabilities Subject to Compromise
The Predecessor’s consolidated balance sheet as of December 31, 2016, includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that were allowed, or that the Company estimated would be allowed, as claims in its Chapter 11 cases. The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet:
Predecessor | |||
December 31, 2016 | |||
(in thousands) | |||
Accounts payable and accrued expenses | $ | 137,692 | |
Accrued interest payable | 144,184 | ||
Debt | 4,023,129 | ||
Liabilities subject to compromise | $ | 4,305,005 | |
Reorganization Items, Net
The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following tables summarize the components of reorganization items included on the consolidated statements of operations:
Successor | Predecessor | ||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | |||||||||||
(in thousands) | |||||||||||||
Gain on settlement of liabilities subject to compromise | $ | — | $ | 3,724,750 | $ | — | |||||||
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | — | (1,000,000 | ) | — | |||||||||
Fresh start valuation adjustments | — | (591,525 | ) | — | |||||||||
Income tax benefit related to implementation of the Plan | — | 264,889 | — | ||||||||||
Legal and other professional advisory fees | (8,902 | ) | (46,961 | ) | (56,656 | ) | |||||||
Unamortized deferred financing fees, discounts and premiums | — | — | (52,045 | ) | |||||||||
Gain related to interest payable on Predecessor’s Second Lien Notes | — | — | 551,000 | ||||||||||
Terminated contracts | — | (6,915 | ) | (66,052 | ) | ||||||||
Other | 51 | (13,049 | ) | (64,648 | ) | ||||||||
Reorganization items, net | $ | (8,851 | ) | $ | 2,331,189 | $ | 311,599 | ||||||
Note 3 – Fresh Start Accounting
Upon the Company’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of ASC 852 which resulted in the Company becoming a new entity for financial reporting purposes. In accordance with ASC 852, the Company was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the Predecessor received less than 50% of the voting shares
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of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.
Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations” (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes” (“ASC 740”). The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh start accounting were reflected on the consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the consolidated statement of operations for the two months ended February 28, 2017.
As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s consolidated financial statements subsequent to February 28, 2017, are not comparable to its consolidated financial statements prior to February 28, 2017. References to “Successor” relate to the financial position and results of operations of the reorganized Company as of and subsequent to February 28, 2017. References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, February 28, 2017.
The Company’s consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017. The Company’s financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.
Reorganization Value
Under ASC 852, the Successor determined a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh start accounting. The Plan confirmed by the Bankruptcy Court estimated an enterprise value of $2.35 billion. The Plan enterprise value was prepared using an asset based methodology, as discussed further below. The enterprise value was then adjusted to determine the equity value of the Successor of approximately $2.03 billion. Adjustments to determine the equity value are presented below (in thousands):
Plan confirmed enterprise value | $ | 2,350,000 | |
Fair value of debt | (900,000 | ) | |
Fair value of subsequently determined tax attributes | 621,486 | ||
Fair value of vested Class B units | (36,505 | ) | |
Value of Successor’s stockholders’ equity | $ | 2,034,981 | |
The subsequently determined tax attributes were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. The Class B units are incentive interest awards that were granted on the Effective Date by Holdco to certain members of its management (see Note 15), and the associated fair value was recorded as a liability of approximately $7 million in “other accrued liabilities” and temporary equity of approximately $29 million in “redeemable noncontrolling interests” on the consolidated balance sheet at February 28, 2017.
The Company’s principal assets are its oil and natural gas properties. The fair values of oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) 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. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward
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curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.
See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities.
Consolidated Balance Sheet
The adjustments included in the following fresh start consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and executed by the Company on the Effective Date (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.
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As of February 28, 2017 | |||||||||||||||||
Predecessor | Reorganization Adjustments (1) | Fresh Start Adjustments | Successor | ||||||||||||||
(in thousands) | |||||||||||||||||
ASSETS | |||||||||||||||||
Current assets: | |||||||||||||||||
Cash and cash equivalents | $ | 734,166 | $ | (679,811 | ) | (2) | $ | — | $ | 54,355 | |||||||
Accounts receivable – trade, net | 212,099 | — | (7,808 | ) | (16) | 204,291 | |||||||||||
Derivative instruments | 15,391 | — | — | 15,391 | |||||||||||||
Restricted cash | 1,602 | 80,164 | (3) | — | 81,766 | ||||||||||||
Other current assets | 106,426 | (15,983 | ) | (4) | 1,780 | (17) | 92,223 | ||||||||||
Total current assets | 1,069,684 | (615,630 | ) | (6,028 | ) | 448,026 | |||||||||||
Noncurrent assets: | |||||||||||||||||
Oil and natural gas properties (successful efforts method) | 13,269,035 | — | (11,082,258 | ) | (18) | 2,186,777 | |||||||||||
Less accumulated depletion and amortization | (10,044,240 | ) | — | 10,044,240 | (18) | — | |||||||||||
3,224,795 | — | (1,038,018 | ) | 2,186,777 | |||||||||||||
Other property and equipment | 641,586 | — | (197,653 | ) | (19) | 443,933 | |||||||||||
Less accumulated depreciation | (230,952 | ) | — | 230,952 | (19) | — | |||||||||||
410,634 | — | 33,299 | 443,933 | ||||||||||||||
Derivative instruments | 4,492 | — | — | 4,492 | |||||||||||||
Deferred income taxes | — | 264,889 | (5) | 356,597 | (5) | 621,486 | |||||||||||
Other noncurrent assets | 15,003 | 151 | (6) | 8,139 | (20) | 23,293 | |||||||||||
19,495 | 265,040 | 364,736 | 649,271 | ||||||||||||||
Total noncurrent assets | 3,654,924 | 265,040 | (639,983 | ) | 3,279,981 | ||||||||||||
Total assets | $ | 4,724,608 | $ | (350,590 | ) | $ | (646,011 | ) | $ | 3,728,007 | |||||||
LIABILITIES AND EQUITY (DEFICIT) | |||||||||||||||||
Current liabilities: | |||||||||||||||||
Accounts payable and accrued expenses | $ | 324,585 | $ | 41,266 | (7) | $ | (2,351 | ) | (21) | $ | 363,500 | ||||||
Derivative instruments | 7,361 | — | — | 7,361 | |||||||||||||
Current portion of long-term debt, net | 1,937,822 | (1,912,822 | ) | (8) | — | 25,000 | |||||||||||
Other accrued liabilities | 41,251 | (1,026 | ) | (9) | 1,104 | (22) | 41,329 | ||||||||||
Total current liabilities | 2,311,019 | (1,872,582 | ) | (1,247 | ) | 437,190 | |||||||||||
Derivative instruments | 2,116 | — | — | 2,116 | |||||||||||||
Long-term debt | — | 875,000 | (10) | — | 875,000 | ||||||||||||
Other noncurrent liabilities | 402,776 | (167 | ) | (11) | (53,239 | ) | (23) | 349,370 | |||||||||
Liabilities subject to compromise | 4,301,912 | (4,301,912 | ) | (12) | — | — | |||||||||||
Temporary equity: | |||||||||||||||||
Redeemable noncontrolling interests | — | 29,350 | (13) | — | 29,350 | ||||||||||||
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As of February 28, 2017 | |||||||||||||||||
Predecessor | Reorganization Adjustments (1) | Fresh Start Adjustments | Successor | ||||||||||||||
Stockholders’/unitholders’ equity (deficit): | |||||||||||||||||
Predecessor units issued and outstanding | 5,386,812 | (5,386,812 | ) | (14) | — | — | |||||||||||
Predecessor accumulated deficit | (7,680,027 | ) | 2,884,740 | (15) | 4,795,287 | (24) | — | ||||||||||
Successor Class A common stock | — | 89 | (14) | — | 89 | ||||||||||||
Successor additional paid-in capital | — | 7,421,704 | (14) | (5,386,812 | ) | (24) | 2,034,892 | ||||||||||
Successor retained earnings | — | — | — | — | |||||||||||||
Total stockholders’/unitholders’ equity (deficit) | (2,293,215 | ) | 4,919,721 | (591,525 | ) | 2,034,981 | |||||||||||
Total liabilities and equity (deficit) | $ | 4,724,608 | $ | (350,590 | ) | $ | (646,011 | ) | $ | 3,728,007 | |||||||
Reorganization Adjustments:
1) | Represent amounts recorded as of the Effective Date for the implementation of the Plan, including, among other items, settlement of the Predecessor’s liabilities subject to compromise, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s Class A common stock, proceeds received from the Successor’s rights offerings and issuance of the Successor’s debt. |
2) | Changes in cash and cash equivalents included the following: |
(in thousands) | |||
Borrowings under the Successor’s revolving loan | $ | 600,000 | |
Borrowings under the Successor’s term loan | 300,000 | ||
Proceeds from rights offerings | 530,019 | ||
Removal of restriction on cash balance | 1,602 | ||
Payment to holders of claims under the Predecessor Credit Facility | (1,947,357 | ) | |
Payment to holders of claims under the Second Lien Notes | (30,000 | ) | |
Payment of Berry’s ad valorem taxes | (23,366 | ) | |
Payment of the rights offerings backstop commitment premium | (15,900 | ) | |
Payment of professional fees | (13,043 | ) | |
Funding of the professional fees escrow account | (41,766 | ) | |
Funding of the general unsecured claims cash distribution pool | (40,000 | ) | |
Changes in cash and cash equivalents | $ | (679,811 | ) |
3) | Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims cash distribution pool. |
4) | Primarily reflects the write-off of the Predecessor’s deferred financing fees. |
5) | Reflects deferred tax assets recorded as of the Effective Date as determined in accordance with ASC 740. The deferred tax assets were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. |
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6) | Reflects the capitalization of deferred financing fees related to the Successor’s revolving loan. |
7) | Net increase in accounts payable and accrued expenses reflects: |
(in thousands) | |||
Recognition of payables for the professional fees escrow account | $ | 41,766 | |
Recognition of payables for the general unsecured claims cash distribution pool | 40,000 | ||
Payment of professional fees | (17,130 | ) | |
Payment of Berry’s ad valorem taxes | (23,366 | ) | |
Other | (4 | ) | |
Net increase in accounts payable and accrued expenses | $ | 41,266 | |
8) | Reflects the settlement of the Predecessor Credit Facility through repayment of approximately $1.9 billion, net of the write-off of deferred financing fees and an increase of $25 million for the current portion of the Successor’s term loan. |
9) | Reflects a decrease of approximately $8 million for the payment of accrued interest on the Predecessor Credit Facility partially offset by an increase of approximately $7 million related to noncash share-based compensation classified as a liability related to the incentive interest awards issued by Holdco to certain members of its management (see Note 15). |
10) | Reflects borrowings of $900 million under the Successor Credit Facility, which includes a $600 million revolving loan and a $300 million term loan, net of $25 million for the current portion of the Successor’s term loan. |
11) | Reflects a reduction in deferred tax liabilities as determined in accordance with ASC 740. |
12) | Settlement of liabilities subject to compromise and the resulting net gain were determined as follows: |
(in thousands) | |||
Accounts payable and accrued expenses | $ | 134,599 | |
Accrued interest payable | 144,184 | ||
Debt | 4,023,129 | ||
Total liabilities subject to compromise | 4,301,912 | ||
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | 1,000,000 | ||
Funding of the general unsecured claims cash distribution pool | (40,000 | ) | |
Payment to holders of claims under the Second Lien Notes | (30,000 | ) | |
Issuance of Class A common stock to creditors | (1,507,162 | ) | |
Gain on settlement of liabilities subject to compromise | $ | 3,724,750 | |
13) | Reflects redeemable noncontrolling interests classified as temporary equity related to the incentive interest awards issued by Holdco to certain members of its management. See Note 15 for additional information. |
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14) | Net increase in capital accounts reflects: |
(in thousands) | |||
Issuance of Class A common stock to creditors | $ | 1,507,162 | |
Issuance of Class A common stock pursuant to the rights offerings | 530,019 | ||
Payment of the rights offerings backstop commitment premium | (15,900 | ) | |
Payment of issuance costs | (50 | ) | |
Share-based compensation expenses | 13,750 | ||
Cancellation of the Predecessor’s units issued and outstanding | 5,386,812 | ||
Par value of Class A common stock | (89 | ) | |
Change in additional paid-in capital | 7,421,704 | ||
Par value of Class A common stock | 89 | ||
Predecessor’s units issued and outstanding | (5,386,812 | ) | |
Net increase in capital accounts | $ | 2,034,981 | |
See Note 13 for additional information on the issuances of the Successor’s equity.
15) | Net decrease in accumulated deficit reflects: |
(in thousands) | |||
Recognition of gain on settlement of liabilities subject to compromise | $ | 3,724,750 | |
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement | (1,000,000 | ) | |
Recognition of professional fees | (37,680 | ) | |
Write-off of deferred financing fees | (16,728 | ) | |
Recognition of deferred income taxes | 264,889 | ||
Total reorganization items, net | 2,935,231 | ||
Share-based compensation expenses | (50,255 | ) | |
Other | (236 | ) | |
Net decrease in accumulated deficit | $ | 2,884,740 | |
Fresh Start Adjustments:
16) | Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances. |
17) | Reflects the recognition of intangible assets for the current portion of favorable leases, partially offset by decreases for well equipment inventory and the write-off of historical intangible assets. |
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18) | Reflects a decrease of oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: |
Successor | Predecessor | |||||||
Fair Value | Historical Book Value | |||||||
(in thousands) | ||||||||
Proved properties | $ | 1,727,834 | $ | 12,258,835 | ||||
Unproved properties | 458,943 | 1,010,200 | ||||||
2,186,777 | 13,269,035 | |||||||
Less accumulated depletion and amortization | — | (10,044,240 | ) | |||||
$ | 2,186,777 | $ | 3,224,795 | |||||
19) | Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date: |
Successor | Predecessor | |||||||
Fair Value | Historical Book Value | |||||||
(in thousands) | ||||||||
Natural gas plants and pipelines | $ | 342,924 | $ | 426,914 | ||||
Office equipment and furniture | 39,211 | 106,059 | ||||||
Buildings and leasehold improvements | 32,817 | 66,023 | ||||||
Vehicles | 16,980 | 30,760 | ||||||
Land | 7,747 | 3,727 | ||||||
Drilling and other equipment | 4,254 | 8,103 | ||||||
443,933 | 641,586 | |||||||
Less accumulated depreciation | — | (230,952 | ) | |||||
$ | 443,933 | $ | 410,634 | |||||
In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to value the Company’s natural gas plants and pipelines and other operating assets, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. A market approach was used to value the Company’s vehicles and land, using recent transactions of similar assets to determine the fair value from a market participant perspective.
20) | Reflects the recognition of intangible assets for the noncurrent portion of favorable leases, as well as increases in equity method investments and carbon credit allowances. Assets and liabilities for out-of-market contracts were valued based on market terms as of February 28, 2017, and will be amortized over the remaining life of the respective lease. The Company’s equity method investments were valued based on a market approach using a market EBITDA multiple. Carbon credit allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. |
21) | Primarily reflects the write-off of deferred rent partially offset by an increase in carbon emissions liabilities. |
22) | Reflects an increase of the current portion of asset retirement obligations. |
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23) | Primarily reflects a decrease of approximately $49 million for asset retirement obligations and approximately $5 million for deferred rent, partially offset by an increase of approximately $1 million for carbon emissions liabilities. The fair value of asset retirement obligations were 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; and (iv) a credit-adjusted risk-free interest rate. Carbon emissions liabilities were valued using a market approach based on trading prices for carbon credits on February 28, 2017. |
24) | Reflects the cumulative impact of the fresh start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated deficit. |
Note 4 – Discontinued Operations, Other Divestitures and Roan Contribution
Discontinued Operations
On July 31, 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin in California (the “San Joaquin Basin Sale”). Cash proceeds received from the sale of these properties were approximately $253 million, net of costs to sell of approximately $4 million, and the Company recognized a net gain of approximately $120 million. The gain is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statements of operations.
On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $2 million. The gain is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statements of operations. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year from the date of sale.
As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its consolidated financial statements.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry (see Note 2). As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date and classified it as discontinued operations.
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The following table presents carrying amounts of the assets and liabilities of the Company’s California properties classified as discontinued operations on the consolidated balance sheet:
Predecessor | |||
December 31, 2016 | |||
(in thousands) | |||
Assets: | |||
Oil and natural gas properties | $ | 728,190 | |
Other property and equipment | 11,402 | ||
Other | 1,435 | ||
Total assets of discontinued operations | $ | 741,027 | |
Liabilities: | |||
Asset retirement obligations | $ | 38,042 | |
Other | 1,481 | ||
Total liabilities of discontinued operations | $ | 39,523 | |
All balances of discontinued operations on the consolidated balance sheet relate to the Company’s California properties, as Berry was deconsolidated effective December 3, 2016.
The following tables present summarized financial results of the Company’s California properties and Berry classified as discontinued operations on the consolidated statements of operations:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Revenues and other | $ | 34,096 | $ | 14,891 | $ | 465,775 | $ | 727,211 | ||||||||
Expenses | 19,479 | 13,758 | 1,612,727 | 1,651,114 | ||||||||||||
Other income and (expenses) | (3,541 | ) | (1,681 | ) | (65,022 | ) | (81,756 | ) | ||||||||
Reorganization items, net | — | — | (46,127 | ) | — | |||||||||||
Income (loss) from discontinued operations before income taxes | 11,076 | (548 | ) | (1,258,101 | ) | (1,005,659 | ) | |||||||||
Income tax expense (benefit) | 4,165 | — | 196 | (68 | ) | |||||||||||
Income (loss) from discontinued operations, net of income taxes | $ | 6,911 | $ | (548 | ) | $ | (1,258,297 | ) | $ | (1,005,591 | ) | |||||
In addition, for the ten months ended December 31, 2017, the Successor recognized a net gain on the sale of the California properties of approximately $76 million (net of income tax expense of approximately $46 million), and for the year ended December 31, 2016, the Predecessor recognized a net loss on the deconsolidation of Berry of approximately $546 million.
Results of operations of Berry are only included for the period from January 1, 2016 through December 3, 2016, and the year ended December 31, 2015, as Berry was deconsolidated effective December 3, 2016. Other income and (expenses) include an allocation of interest expense for the California properties of approximately $4 million, $2 million, $8 million and $4 million for the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended
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December 31, 2016, and December 31, 2015, respectively, which represents interest on debt that was required to be repaid as a result of the sales.
Berry Transition Services and Separation Agreement
On the Effective Date, Berry entered into a Transition Services and Separation Agreement (the “TSSA”) with LINN Energy and certain of its subsidiaries to facilitate the separation of Berry’s operations from LINN Energy’s operations. Pursuant to the TSSA, LINN Energy continued to provide, or caused to be provided, certain administrative, management, operating, and other services and support to Berry during a transitional period following the Effective Date (the “Transition Services”).
Under the TSSA, Berry reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, Berry paid to LINN Energy a management fee of $6 million per month, prorated for partial months, during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) and paid $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the Transition Services was reduced to specified accounting and administrative functions. The Transition Period ended April 30, 2017, and the Accounting Period ended June 30, 2017.
Other Divestitures
On November 30, 2017, the Company completed the sale of its interest in properties located in the Williston Basin (the “Williston Assets Sale”). Cash proceeds received from the sale of these properties were approximately $255 million, net of costs to sell of approximately $3 million, and the Company recognized a net gain of approximately $116 million.
On November 30, 2017, the Company completed the sale of its interest in properties located in Wyoming (the “Washakie Assets Sale”). Cash proceeds received from the sale of these properties were approximately $193 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $175 million.
On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certain properties located in south Texas (the “South Texas Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $48 million, net of costs to sell of approximately $1 million, and the Company recognized a combined net gain of approximately $14 million.
On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million.
On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $73 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $30 million.
On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $559 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $277 million.
The divestitures discussed above are not presented as discontinued operations because they do not represent a strategic shift that will have a major effect on the Company’s operations and financial results. The gains on these divestitures are included in “gains (losses) on sale of assets and other, net” on the consolidated statements of operations.
Divestitures – Pending
On February 13, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in conventional properties located in west Texas for a contract price of $119.5 million, subject to closing
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adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On January 15, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Altamont Bluebell Field in Utah for a contract price of $132 million, subject to closing adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
On December 18, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its Oklahoma waterflood and Texas Panhandle properties for a contract price of $122 million, subject to closing adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.
The assets and liabilities associated with the pending divestiture of Oklahoma waterflood and Texas Panhandle properties are classified as “held for sale” on the consolidated balance sheet. At December 31, 2017, the Company’s consolidated balance sheet included current assets of approximately $107 million included in “assets held for sale” and current liabilities of approximately $43 million included in “liabilities held for sale” related to this transaction.
The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the consolidated balance sheet:
Successor | |||
December 31, 2017 | |||
(in thousands) | |||
Assets: | |||
Oil and natural gas properties | $ | 92,245 | |
Other property and equipment | 12,983 | ||
Other | 1,735 | ||
Total assets held for sale | $ | 106,963 | |
Liabilities: | |||
Asset retirement obligations | $ | 42,001 | |
Other | 1,301 | ||
Total liabilities held for sale | $ | 43,302 | |
Other assets primarily include inventories and other liabilities primarily include accounts payable.
Roan Contribution
On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan Resources LLC (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. As of August 31, 2017, the date of the Roan Contribution, the Company recognized its equity investment at carryover basis of approximately $452 million. In connection with the Roan Contribution, the Company paid approximately $17 million in advisory fees, which are included in “gains (losses) on sale of assets and other, net” on the consolidated statements of operations.
See Note 5 for additional information about the Company’s equity method investment in Roan.
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Divestiture – 2015
On August 31, 2015, the Company completed the sale of its remaining position in Howard County in the Permian Basin (the “Howard County Assets Sale”). Cash proceeds received from the sale of these properties were approximately $276 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $177 million. The gain is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations.
Note 5 – Equity Method Investments
On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan, focused on the accelerated development of the Merge/SCOOP/STACK play. See Note 4 for additional information.
The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. At both December 31, 2017, and August 31, 2017 (the date of the Roan Contribution), the Company owned 50% of Roan’s outstanding units. The percentage ownership in Roan is subject to customary post-closing adjustments.
At December 31, 2017, the carrying amount of the Company’s investment in Roan of approximately $458 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $346 million. The difference is attributable to proved and unproved oil and natural gas properties and is amortized over the lives of the related assets. Such amortization is included in the equity earnings (losses) from the Company’s investment in Roan.
Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. No impairments occurred with respect to the Company’s investment in Roan for the four months ended December 31, 2017.
Following are summarized statement of operations and balance sheet information for Roan.
Summarized Roan Resources LLC Statement of Operations Information
Four Months Ended December 31, 2017 | |||
(in thousands) | |||
Revenues and other | $ | 75,461 | |
Expenses | 61,790 | ||
Other income and (expenses) | (1,180 | ) | |
Net income | $ | 12,491 | |
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Summarized Roan Resources LLC Balance Sheet Information
December 31, 2017 | |||
(in thousands) | |||
Current assets | $ | 27,465 | |
Noncurrent assets | 1,826,741 | ||
1,854,206 | |||
Current liabilities | 149,409 | ||
Noncurrent liabilities | 97,480 | ||
Members’ equity | $ | 1,607,317 | |
Note 6 – Debt
The following summarizes the Company’s outstanding debt:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands, except percentages) | ||||||||
Revolving credit facility | $ | — | $ | — | ||||
Predecessor credit facility (1) | — | 1,654,745 | ||||||
Predecessor term loan (1) | — | 284,241 | ||||||
6.50% senior notes due May 2019 | — | 562,234 | ||||||
6.25% senior notes due November 2019 | — | 581,402 | ||||||
8.625% senior notes due April 2020 | — | 718,596 | ||||||
12.00% senior secured second lien notes due December 2020 | — | 1,000,000 | ||||||
7.75% senior notes due February 2021 | — | 779,474 | ||||||
6.50% senior notes due September 2021 | — | 381,423 | ||||||
Net unamortized deferred financing fees | — | (1,257 | ) | |||||
Total debt, net | — | 5,960,858 | ||||||
Less current portion, net (2) | — | (1,937,729 | ) | |||||
Less liabilities subject to compromise (3) | — | (4,023,129 | ) | |||||
Long-term debt | $ | — | $ | — | ||||
(1) | Variable interest rate of 5.50% at December 31, 2016. |
(2) | Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016. |
(3) | The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled. |
Fair Value
The Company’s debt is recorded at the carrying amount on the consolidated balance sheets. The carrying amounts of the credit facilities and term loans approximate fair value because the interest rates are variable and reflective of market rates. The Company used a market approach to determine the fair value of the Predecessor’s Second Lien Notes and senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.
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Predecessor | |||||||
December 31, 2016 | |||||||
Carrying Value | Fair Value | ||||||
(in thousands) | |||||||
Senior secured second lien notes | $ | 1,000,000 | $ | 863,750 | |||
Senior notes, net | 3,023,129 | 1,179,224 | |||||
Revolving Credit Facility
On August 4, 2017, the Company entered into a credit agreement with Holdco II, as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million. The maximum commitment amount was $425 million at December 31, 2017.
As of December 31, 2017, there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $381 million of available borrowing capacity (which includes a $44 million reduction for outstanding letters of credit). The maturity date is August 4, 2020.
Redetermination of the borrowing base under the Revolving Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October, with the first scheduled borrowing base redetermination to occur on March 15, 2018. At the Company’s election, interest on borrowings under the Revolving Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base. Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period. The Company is required to pay a commitment fee to the lenders under the Revolving Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders.
The obligations under the Revolving Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of the oil and natural gas properties of the Company and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, Holdco and certain of Holdco II’s subsidiaries, subject to customary exceptions. Under the Revolving Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0.
The Revolving Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates.
The Revolving Credit Facility contains events of default and remedies customary for credit facilities of this nature. Failure to comply with the financial and other covenants in the Revolving Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Revolving Credit Facility.
In September 2017, the Company entered into an amendment to the Revolving Credit Facility to provide for, among other things, an increase in the size of the letter of credit subfacility from $25 million to $50 million.
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Successor Credit Facility
On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Successor Credit Facility with Holdco II as borrower and Wells Fargo Bank, National Association, as administrative agent, providing for: 1) a reserve-based revolving loan with an initial borrowing base of $1.4 billion and 2) a term loan in an original principal amount of $300 million. On May 31, 2017, the Company entered into the First Amendment and Consent to Credit Agreement, pursuant to which among other modifications: 1) the term loan was paid in full and terminated using cash proceeds from the Jonah Assets Sale, and 2) the borrowing base for the revolving loan was reduced to $1 billion with additional agreed upon reductions for the Company’s other announced sales. In connection with the entry into the Revolving Credit Facility, the Successor Credit Facility was terminated and repaid in full.
Predecessor’s Credit Facility, Second Lien Notes and Senior Notes
On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes were canceled. See Note 2 for additional information.
Predecessor Covenant Violations
The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes. For the two months ended February 28, 2017, contractual interest, which was not recorded, on the Second Lien Notes and senior notes was approximately $57 million. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.
Predecessor’s Senior Secured Second Lien Notes Due December 2020
On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows:
Par Value of Senior Notes Exchanged | |||
(in thousands) | |||
6.50% senior notes due May 2019 | $ | 584,422 | |
6.25% senior notes due November 2019 | 824,348 | ||
8.625% senior notes due April 2020 | 286,344 | ||
7.75% senior notes due February 2021 | 184,300 | ||
6.50% senior notes due September 2021 | 120,586 | ||
$ | 2,000,000 | ||
The exchanges were accounted for as a troubled debt restructuring (“TDR”). Since the total future cash payments of the new debt were less than the carrying amount of the previous debt, a gain of approximately $352 million, or $1.03 per unit, was recognized for the year ended December 31, 2015, and included in “gain on extinguishment of debt” on the consolidated statement of operations. TDR accounting requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized.
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Predecessor Repurchases of Senior Notes
During the year ended December 31, 2015, the Predecessor repurchased, through privately negotiated transactions and on the open market, approximately $927 million of its outstanding senior notes as follows:
• | 6.50% senior notes due May 2019 – $53 million; |
• | 6.25% senior notes due November 2019 – $395 million; |
• | 8.625% senior notes due April 2020 – $295 million; |
• | 7.75% senior notes due February 2021 – $36 million; and |
• | 6.50% senior notes due September 2021 – $148 million. |
In connection with the repurchases, the Predecessor paid approximately $553 million in cash and recorded a gain on extinguishment of debt of approximately $356 million for the year ended December 31, 2015.
Note 7 – Derivatives
Commodity Derivatives
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
The following table presents derivative positions for the periods indicated as of December 31, 2017:
2018 | 2019 | ||||||
Natural gas positions: | |||||||
Fixed price swaps (NYMEX Henry Hub): | |||||||
Hedged volume (MMMBtu) | 69,715 | 11,315 | |||||
Average price ($/MMBtu) | $ | 3.02 | $ | 2.97 | |||
Oil positions: | |||||||
Fixed price swaps (NYMEX WTI): | |||||||
Hedged volume (MBbls) | 548 | — | |||||
Average price ($/Bbl) | $ | 54.07 | $ | — | |||
Collars (NYMEX WTI): | |||||||
Hedged volume (MBbls) | 1,825 | 1,825 | |||||
Average floor price ($/Bbl) | $ | 50.00 | $ | 50.00 | |||
Average ceiling price ($/Bbl) | $ | 55.50 | $ | 55.50 | |||
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During the ten months ended December 31, 2017, the Company entered into commodity derivative contracts consisting of oil swaps for January 2018 through December 2018 and natural gas swaps for January 2018 through December 2019. The Company did not enter into any commodity derivative contracts during the two months ended February 28, 2017.
In accordance with a Bankruptcy Court order dated August 16, 2016, the Company was authorized to enter into postpetition hedging arrangements. During the year ended December 31, 2016, LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019. In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion. The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility.
The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Assets: | ||||||||
Commodity derivatives | $ | 22,589 | $ | 19,369 | ||||
Liabilities: | ||||||||
Commodity derivatives | $ | 25,443 | $ | 113,226 | ||||
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 participants in the Revolving Credit Facility. The Revolving Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; 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 $23 million at December 31, 2017. 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 and Losses on Derivatives
Gains and losses on derivatives were net gains of approximately $14 million and $93 million for the ten months ended December 31, 2017, and the two months ended February 28, 2017, respectively. Gains and losses on derivatives were net
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losses of approximately $164 million for the year ended December 31, 2016, and net gains of approximately $1.0 billion for the year ended December 31, 2015. Gains and losses on derivatives are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”
The Company received net cash settlements of approximately $27 million for the ten months ended December 31, 2017, and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017. The Company received net cash settlements of approximately $861 million and $1.1 billion for the years ended December 31, 2016, and December 31, 2015, respectively. In addition, during the year ended December 31, 2016, approximately $841 million in settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the Predecessor Credit Facility as repayments of a portion of the borrowings outstanding.
Note 8 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 7) 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 and public bond yield 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 into a three-level fair value hierarchy based on the priority of inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
Level 1 | Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. |
Level 2 | Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives). |
Level 3 | Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. |
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.
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The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
Successor | |||||||||||
December 31, 2017 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 22,589 | $ | (12,491 | ) | $ | 10,098 | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 25,443 | $ | (12,491 | ) | $ | 12,952 | ||||
Predecessor | |||||||||||
December 31, 2016 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 19,369 | $ | (19,369 | ) | $ | — | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 113,226 | $ | (19,369 | ) | $ | 93,857 | ||||
(1) | Represents counterparty netting under agreements governing such derivatives. |
Note 9 – Other Property and Equipment
Other property and equipment consists of the following:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Natural gas plant and pipeline | $ | 392,999 | $ | 421,806 | ||||
Furniture and office equipment | 39,551 | 105,353 | ||||||
Buildings and leasehold improvements | 27,301 | 66,014 | ||||||
Vehicles | 10,811 | 31,496 | ||||||
Land | 6,776 | 3,736 | ||||||
Drilling and other equipment | 3,291 | 8,082 | ||||||
480,729 | 636,487 | |||||||
Less accumulated depreciation | (28,658 | ) | (224,547 | ) | ||||
Less other property and equipment, net – discontinued operations | — | (11,402 | ) | |||||
$ | 452,071 | $ | 400,538 | |||||
Note 10 – Asset Retirement Obligations
The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other
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noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated 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; and (iv) a credit-adjusted risk-free interest 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.
The following table presents a reconciliation of the Company’s asset retirement obligations:
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | ||||||||||
(in thousands) | ||||||||||||
Asset retirement obligations at beginning of period | $ | 357,397 | $ | 402,162 | $ | 523,541 | ||||||
Liabilities added from drilling | 551 | 146 | 546 | |||||||||
Liabilities added from acquisitions | — | — | 1,416 | |||||||||
Liabilities associated with assets divested | (158,228 | ) | — | — | ||||||||
Liabilities associated with assets held for sale | (42,001 | ) | — | — | ||||||||
Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations | — | — | (141,612 | ) | ||||||||
Current year accretion expense | 14,995 | 4,024 | 30,498 | |||||||||
Settlements | (8,189 | ) | (618 | ) | (12,823 | ) | ||||||
Revision of estimates | 28 | — | 596 | |||||||||
Fresh start adjustment (1) | — | (48,317 | ) | — | ||||||||
164,553 | 357,397 | 402,162 | ||||||||||
Less asset retirement obligations – discontinued operations | — | (26,978 | ) | (38,042 | ) | |||||||
Asset retirement obligations at end of period | $ | 164,553 | $ | 330,419 | $ | 364,120 | ||||||
(1) | As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date. |
Note 11 – Commitments and Contingencies
On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the Plan was subject to certain conditions set forth in the Plan. On the Effective Date, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.
The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest of approximately $31
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million. The Company has vigorously disputed that Wells Fargo is entitled to any default interest based on the plain language of the Plan and Confirmation Order. A hearing was held on April 27, 2017, and on November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest. The ruling has been appealed by Wells Fargo and that appeal is pending.
The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Except for in connection with its Chapter 11 proceedings, the Company made no significant payments to settle any legal, environmental or tax proceedings during the years ended December 31, 2017, December 31, 2016, and December 31, 2015. See Note 3 for additional information about payments made upon the Company’s emergence from Chapter 11 bankruptcy. 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 12 – Operating Leases
The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2021. The Company recognized expense under operating leases of approximately $6 million, $1 million, $9 million and $15 million for the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended December 31, 2016, and December 31, 2015, respectively.
As of December 31, 2017, future minimum lease payments were as follows (in thousands):
2018 | $ | 2,812 | |
2019 | 2,005 | ||
2020 | 463 | ||
2021 | 12 | ||
2022 | — | ||
Thereafter | — | ||
$ | 5,292 | ||
Note 13 – Equity (Deficit)
Successor Equity
Shares Issued and Outstanding
As of December 31, 2017, there were 83,582,176 shares of Class A common stock issued and outstanding. An additional 609,905 vested but not issued restricted stock units and 2,960,304 unvested restricted stock units were outstanding under the Company’s Omnibus Incentive Plan. As of December 31, 2017, the Company’s consolidated subsidiary, Holdco, had 768,787 vested Class A-2 units and 2,306,361 unvested Class A-2 units, which may be converted into shares of Class A common stock pursuant to the terms of the Limited Liability Company Operating Agreement of Holdco (the “Holdco LLC Agreement”). See Note 15 for additional information related to the restricted stock units and Class A-2 units.
As of January 31, 2018, there were 77,229,257 shares of Class A common stock issued and outstanding, an additional 2,953,294 unvested restricted stock units (of which 1,165,134 are scheduled to vest on or before March 1, 2018) were outstanding under the Company’s Omnibus Incentive Plan and 2,820,804 Class A‑2 units of Holdco (of which 1,410,402 are vested or will be vested by March 1, 2018) were outstanding.
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Cancellation of Units and Issuance of Class A Common Stock
In accordance with the Plan, on the Effective Date:
• | All units in the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery; |
• | 17,678,889 shares of Class A common stock were issued pro rata to holders of the Second Lien Notes with claims allowed under the Plan; |
• | 26,724,396 shares of Class A common stock were issued pro rata to holders of Unsecured Notes with claims allowed under the Plan; |
• | 471,110 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in respect of the premium due thereunder; |
• | 2,995,691 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder; and |
• | 41,359,806 shares of Class A common stock were issued to participants in the rights offerings extended by the Company to certain holders of claims arising under the Second Lien Notes and the Unsecured Notes (including, in each case, certain of the commitment parties party to the Backstop Commitment Agreement). |
With the exception of shares of Class A common stock issued to commitment parties pursuant to their obligations under the Backstop Commitment Agreement, shares of Class A common stock were issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), under Section 1145 of the Bankruptcy Code. Shares of Class A common stock issued to commitment parties pursuant to their obligations under the Backstop Commitment Agreement were issued pursuant to an exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof.
As of the Effective Date, there were 89,229,892 shares of Class A common stock, par value $0.001 per share, issued and outstanding.
Share Repurchase Program
On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 through December 2017, the Company repurchased an aggregate of 5,690,192 shares of Class A common stock at an average price of $34.85 per share for a total cost of approximately $198 million.
Tender Offer – Subsequent Event
On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of the tender offer).
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Dividends
The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility.
Predecessor Equity
Cancellation of Awards
In December 2016, the Predecessor canceled all of its then-outstanding nonvested restricted units without consideration given to the employees, decreasing the Predecessor’s units issued and outstanding by 2,230,182.
At-the-Market Offering Program
The Predecessor’s Board of Directors had authorized the sale of up to $500 million of units under an at-the-market offering program, with sales of units, if any, to be made under an equity distribution agreement. No sales were made under the equity distribution agreement during the year ended December 31, 2016. During the year ended December 31, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average price of $12.37 per unit for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6).
Public Offering of Units
In May 2015, the Predecessor sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Predecessor used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the Predecessor Credit Facility.
Forfeiture of Units in Exchange for Cash
In August 2015, in accordance with terms of the separation agreement between the Company and Kolja Rockov, former Chief Financial Officer, dated August 31, 2015, Mr. Rockov agreed to forfeit 191,446 units issued to him under the Company’s equity compensation plan in exchange for a cash payment of approximately $672,000.
Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. Monthly distributions were paid by the Company through September 2015. Distributions paid by the Company during 2015 are presented on the consolidated statements of unitholders’ capital (deficit) and the consolidated statements of cash flows. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution.
Note 14 – Noncontrolling Interests
Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Holdco, not attributable to LINN Energy. On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of Class B units (see Note 15). In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. At both December 31, 2017, and
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July 31, 2017 (the date of the conversion), the noncontrolling Class A-2 units represented approximately 0.88% of Holdco’s total outstanding units.
Note 15 – Share-Based Compensation and Other Benefits
The Company had no equity awards outstanding as of December 31, 2016. In accordance with the Plan, in February 2017, the Company implemented the Linn Energy, Inc. 2017 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) pursuant to which employees and consultants of the Company and its affiliates are eligible to receive stock options, restricted stock, performance awards, other stock-based awards and other cash-based awards.
The Committee (as defined in the Omnibus Incentive Plan) has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award. As of the Effective Date, an aggregate of 6,444,381 shares of Class A common stock were reserved for issuance under the Omnibus Incentive Plan (the “Share Reserve”). Additional shares of Class A common stock may be issued in excess of the Share Reserve for the sole purpose of satisfying any conversion of Class A‑2 units of Holdco into shares of Class A common stock pursuant to the Holdco LLC Agreement, and the conversion procedures set forth therein. If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Class A common stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Class A common stock awarded under the Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for the purpose of awards under the Omnibus Incentive Plan. Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s stockholders.
Securities Authorized for Issuance Under the Omnibus Incentive Plan
As of December 31, 2017, approximately 6.6 million shares were issuable under the Omnibus Incentive Plan pursuant to outstanding award or other agreements, including approximately 3.5 million shares related to restricted stock units and approximately 3.1 million shares related to Class A‑2 units of Holdco. As of December 31, 2017, approximately 2.8 million additional shares were reserved for future issuance under the Plan.
The Compensation Committee of the Board of Directors of the Company (the “Compensation Committee”) generally has discretion regarding the timing, size and terms of future awards; however, the Omnibus Incentive Plan requires that 1) the portion of the Share Reserve that does not constitute the Emergence Awards, plus any subsequent awards forfeited before vesting (the “Remaining Share Reserve”), will be fully granted within the 36-month period immediately following the Effective Date (with such 36-month anniversary, the “Final Allocation Date”) and 2) if a Change in Control (as defined in the Omnibus Incentive Plan) occurs before the Final Allocation Date, the entire Remaining Share Reserve will be allocated on a fully-vested basis to actively employed employees (pro-rata based upon each such employee’s relative awards) upon the consummation of the Change in Control. In January and February 2018, certain participants in the Omnibus Incentive Plan agreed to waive any rights they may have to future awards under this provision in consideration for the ability to participate in the Liquidity Program described below.
Accounting for Share-Based Compensation
The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the
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date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company had no outstanding liability awards as of December 31, 2017. The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur.
The Company’s restricted stock units are equity-classified on the consolidated balance sheet. The Company’s incentive interest awards in the form of Class B units were liability-classified on the consolidated balance sheet through July 31, 2017 (the date of the conversion to Class A-2 units) and are subsequently equity-classified. The fair value of the Company’s restricted stock units was determined based on the fair value of the Company’s shares on the date of grant and the fair value of the incentive interest awards in the form of Class B units (Class A-2 units upon conversion) was initially determined based on the estimated amount to settle the awards and the fair value of the awards at the date of the conversion became the measurement basis from that point forward.
A summary of share-based compensation expenses included on the consolidated statements of operations is presented below:
Successor | Predecessor | ||||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | ||||||||||||||
(in thousands) | |||||||||||||||||
General and administrative expenses | $ | 41,285 | $ | 50,255 | $ | 34,268 | $ | 47,312 | |||||||||
Lease operating expenses | — | — | 9,950 | 8,824 | |||||||||||||
Total share-based compensation expenses | $ | 41,285 | $ | 50,255 | $ | 44,218 | $ | 56,136 | |||||||||
Income tax benefit | $ | 9,861 | $ | 5,170 | $ | 16,339 | $ | 20,742 | |||||||||
Restricted Stock Units
On the Effective Date, the Company granted to certain employees 2,478,606 restricted stock units (the “Emergence Awards”). During the ten months ended December 31, 2017, the Company granted to certain employees 1,340,350 restricted stock units from the Remaining Share Reserve. The restricted stock units vest over three years.
Upon a participant’s termination of employment and/or service (as applicable), the Company has the right (but not the obligation) to repurchase all or any portion of the shares of Class A common stock acquired pursuant to an award at a price equal to the fair market value (as determined under the Omnibus Incentive Plan) of the shares of Class A common stock to be repurchased, measured as of the date of the Company’s repurchase notice. In addition, in January 2018, the Compensation Committee approved a one-time liquidity program under which the Company has agreed to 1) settle all or a portion of an eligible participant’s restricted stock units vesting on or before March 1, 2018 in cash and/or 2) repurchase all or a portion of any shares of Class A common stock held by an eligible participant as a result of a prior vesting of restricted stock units, in each case at an agreed upon price (the “Liquidity Program”). Only those participants that executed the waiver of certain rights under the Omnibus Incentive Plan described above are eligible to participate in the Liquidity Program.
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The following summarizes the Company’s restricted stock units activity:
Number of Nonvested Units | Weighted Average Grant-Date Fair Value Per Unit | |||||
Nonvested units at February 28, 2017 (Predecessor) | — | $ | — | |||
Granted | 2,478,606 | $ | 22.19 | |||
Vested | (619,665 | ) | $ | 22.19 | ||
Nonvested units at February 28, 2017 (Successor) | 1,858,941 | $ | 22.19 | |||
Granted | 1,340,350 | $ | 29.29 | |||
Vested | (51,839 | ) | $ | 27.86 | ||
Forfeited | (187,148 | ) | $ | 28.38 | ||
Nonvested units at December 31, 2017 (Successor) | 2,960,304 | $ | 24.92 | |||
The total fair value of restricted stock units that vested was approximately $2 million and $14 million for the ten months ended December 31, 2017, and on February 28, 2017, respectively. As of December 31, 2017, there was approximately $49 million of unrecognized compensation cost related to nonvested restricted stock units. The cost is expected to be recognized over a weighted average period of approximately 2.16 years.
Holdco Incentive Interest Plan
On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of 3,470,051 Class B units, which are intended to qualify as “profits interests” for U.S. income tax purposes. The Class B units vested 25% on the Effective Date and the remaining amount vest ratably over the following three years. In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. The Class A-2 units will continue to vest over three years. The total fair value of Class B units that vested was approximately $28 million on February 28, 2017. As of December 31, 2017, there was approximately $61 million of unrecognized compensation cost related to nonvested Class A-2 units of Holdco. The cost is expected to be recognized over a weighted average period of approximately 2.16 years.
Predecessor’s Incentive Plan Summary
The Predecessor’s Amended and Restated Long-Term Incentive Plan, as amended (the “LTIP”), was effective from December 2005 through February 28, 2017. The LTIP permitted grants of unrestricted units, restricted units, stock options and performance awards to employees, consultants and nonemployee directors. In December 2016, the Company canceled all of its then-outstanding nonvested restricted units, phantom units and performance unit awards, as well as its then-outstanding unit options, without consideration given to the employees. As a result, the Company recognized unit-based compensation expenses of approximately $14 million for the year ended December 31, 2016, associated with previously unrecognized compensation costs for awards that were canceled before the completion of the requisite service period.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for eligible employees. For 2017, Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 4% of eligible compensation contributed by the employee on a before-tax basis. For the years 2016 and 2015, Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $3 million, $812,000, $9 million and $11 million during the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended
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December 31, 2016, and December 31, 2015, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.
Note 16 – Earnings Per Share/Unit
Basic earnings per share/unit is computed by dividing net earnings attributable to common stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units.
The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share/unit computations for net income (loss):
Successor | ||||||||||
Ten Months Ended December 31, 2017 | ||||||||||
Income | Shares | Per Share | ||||||||
(in thousands, except per share data) | ||||||||||
Basic: | ||||||||||
Income from continuing operations | $ | 349,865 | 87,646 | $ | 3.99 | |||||
Income from discontinued operations, net of income taxes | 82,995 | 87,646 | 0.95 | |||||||
Net income attributable to common stockholders | $ | 432,860 | 87,646 | $ | 4.94 | |||||
Effect of Dilutive Securities: | ||||||||||
Dilutive effect of restricted stock units | $ | — | 1,073 | |||||||
Dilutive effect of unvested Class A-2 units of Holdco | $ | (2,180 | ) | — | ||||||
Diluted: | ||||||||||
Income from continuing operations | $ | 347,685 | 88,719 | $ | 3.92 | |||||
Income from discontinued operations | 82,995 | 88,719 | 0.93 | |||||||
Net income attributable to common stockholders | $ | 430,680 | 88,719 | $ | 4.85 | |||||
Predecessor | ||||||||||
Two Months Ended February 28, 2017 | ||||||||||
Income (Loss) | Units | Per Unit | ||||||||
(in thousands, except per unit data) | ||||||||||
Basic and Diluted: | ||||||||||
Income from continuing operations | $ | 2,397,609 | 352,792 | $ | 6.80 | |||||
Loss from discontinued operations, net of income taxes | (548 | ) | 352,792 | (0.01 | ) | |||||
Net income attributable to common unitholders | $ | 2,397,061 | 352,792 | $ | 6.79 | |||||
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Predecessor | ||||||||||
Year Ended December 31, 2016 | ||||||||||
Loss | Units | Per Unit | ||||||||
(in thousands, except per unit data) | ||||||||||
Basic and Diluted: | ||||||||||
Loss from continuing operations | $ | (367,343 | ) | 352,653 | $ | (1.04 | ) | |||
Loss from discontinued operations, net of income taxes | (1,804,513 | ) | 352,653 | (5.12 | ) | |||||
Net loss attributable to common unitholders | $ | (2,171,856 | ) | 352,653 | $ | (6.16 | ) | |||
Predecessor | ||||||||||
Year Ended December 31, 2015 | ||||||||||
Loss | Units | Per Unit | ||||||||
(in thousands, except per unit data) | ||||||||||
Basic and Diluted: | ||||||||||
Loss from continuing operations | $ | (3,754,220 | ) | |||||||
Allocated to participating securities | (3,039 | ) | ||||||||
(3,757,259 | ) | 343,323 | $ | (10.94 | ) | |||||
Loss from discontinued operations, net of income taxes | (1,005,591 | ) | 343,323 | (2.93 | ) | |||||
Net loss attributable to common unitholders | $ | (4,762,850 | ) | 343,323 | $ | (13.87 | ) | |||
There were no anti-dilutive restrictive stock units for the ten months ended December 31, 2017. The diluted earnings per unit calculation excludes approximately 1 million and 4 million unit options and warrants that were anti-dilutive for the years ended December 31, 2016, and December 31, 2015, respectively. There were no potential common units outstanding during the two months ended February 28, 2017.
Note 17 – Income Taxes
The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.
The deferred tax effects of the Company’s change to a C corporation are included in income from continuing operations for the two months ended February 28, 2017. Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations.
On December 22, 2017, H.R. 1 (the “Tax Cuts and Jobs Act”) was signed into law. The Company conducted an assessment of the impact of the Tax Cuts and Jobs Act and concluded that a noncash charge of approximately $106 million for the ten months ended December 31, 2017, against net deferred income taxes was necessary due to the decrease in the statutory federal income tax rate from 35% to 21%. This charge is included in “income tax expense (benefit)” on the consolidated statement of operations and resulted in a 14.3% increase in the Company’s effective tax rate for the ten months ended December 31, 2017.
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Income tax expense (benefit) consisted of the following:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Current taxes: | ||||||||||||||||
Federal | $ | 7,140 | $ | — | $ | (494 | ) | $ | (12,021 | ) | ||||||
State | 489 | — | 321 | 1,022 | ||||||||||||
Deferred taxes: | ||||||||||||||||
Federal | 366,243 | — | 11,582 | 8,237 | ||||||||||||
State | 15,070 | (166 | ) | (215 | ) | (3,631 | ) | |||||||||
$ | 388,942 | $ | (166 | ) | $ | 11,194 | $ | (6,393 | ) | |||||||
As of December 31, 2017, the Company had approximately $60 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2038.
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Successor | Predecessor | |||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||
Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||
Federal statutory rate change | 14.3 | — | — | — | ||||||||
State, net of federal tax benefit | 2.6 | — | 0.7 | 0.1 | ||||||||
Loss excluded from nontaxable entities | — | (35.0 | ) | (24.7 | ) | (34.7 | ) | |||||
Other | 0.5 | — | (14.1 | ) | (0.2 | ) | ||||||
Effective rate | 52.4 | % | — | % | (3.1 | )% | 0.2 | % | ||||
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Significant components of the deferred tax assets and liabilities were as follows:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Deferred tax assets: | ||||||||
Net operating loss carryforwards | $ | 14,615 | $ | 1,730 | ||||
Reorganization items | — | 14,932 | ||||||
Investment in Linn Energy Holdco LLC | 176,662 | — | ||||||
Valuation allowance | — | (19,558 | ) | |||||
Other | 7,140 | 10,030 | ||||||
Total deferred tax assets | 198,417 | 7,134 | ||||||
Deferred tax liabilities: | ||||||||
Property and equipment principally due to differences in depreciation | — | (7,021 | ) | |||||
Other | — | (279 | ) | |||||
Total deferred tax liabilities | — | (7,300 | ) | |||||
Net deferred tax assets (liabilities) | $ | 198,417 | $ | (166 | ) | |||
The net deferred tax assets are recorded in “deferred income taxes” and the net deferred tax liabilities are recorded in “other noncurrent liabilities” on the consolidated balance sheets at December 31, 2017, and December 31, 2016, respectively.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2017, based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences.
In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2017, or December 31, 2016. The tax years 2016 and 2017 remain open to examination for federal and state income tax purposes.
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Note 18 – Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows
“Other current assets” reported on the consolidated balance sheets include the following:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Prepaids | $ | 46,238 | $ | 70,116 | ||||
Receivable from related party | 23,163 | — | ||||||
Inventories | 7,667 | 15,097 | ||||||
Deferred financing fees | — | 16,809 | ||||||
Other | 2,703 | 3,288 | ||||||
Other current assets | $ | 79,771 | $ | 105,310 | ||||
“Other accrued liabilities” reported on the consolidated balance sheets include the following:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
Accrued compensation | $ | 29,089 | $ | 16,443 | ||||
Asset retirement obligations (current portion) | 3,926 | 9,361 | ||||||
Deposits | 15,349 | — | ||||||
Income taxes payable | 7,496 | — | ||||||
Other | 2,757 | 175 | ||||||
Other accrued liabilities | $ | 58,617 | $ | 25,979 | ||||
Supplemental disclosures to the consolidated statements of cash flows are presented below:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
Cash payments for interest, net of amounts capitalized | $ | 15,165 | $ | 17,651 | $ | 143,305 | $ | 476,077 | ||||||||
Cash payments for income taxes | $ | 275 | $ | — | $ | 4,427 | $ | 643 | ||||||||
Cash payments for reorganization items, net | $ | 11,889 | $ | 21,571 | $ | 37,748 | $ | — | ||||||||
Noncash investing activities: | ||||||||||||||||
Accrued capital expenditures | $ | 31,447 | $ | 22,191 | $ | 31,128 | $ | 71,105 | ||||||||
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2017, “restricted cash” on the consolidated balance sheet consists of approximately $36 million that will be used to settle certain claims in accordance with the Plan (which is the remainder of approximately $80 million transferred to restricted cash in February 2017 to fund such
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items), approximately $15 million related to deposits and approximately $5 million for other items. At December 31, 2016, “restricted cash” on the consolidated balance sheet represents amounts restricted related to utility services providers. In addition, restricted cash of approximately $8 million is included in “other noncurrent assets” on the consolidated balance sheet at December 31, 2016, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
At December 31, 2016, net outstanding checks of approximately $6 million were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheet. The change in net outstanding checks is presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows.
In November 2015, the Company issued $1.0 billion in aggregate principal amount of Second Lien Notes in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes (see Note 6). In addition, during the year ended December 31, 2016, approximately $841 million in commodity derivative settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the Predecessor Credit Facility as repayments of a portion of the borrowings outstanding, and are reflected as noncash transactions by the Company.
Note 19 – Significant Customers
The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).
For the ten months ended December 31, 2017, the two months ended February 28, 2017, and the years ended December 31, 2016, and December 31, 2015, no individual customer exceeded 10% of the Company’s sales.
At December 31, 2017, and December 31, 2016, no individual customer exceeded 10% of the Company’s receivables.
Note 20 – Related Party Transactions
Roan Resources LLC
On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. See Note 4 for additional information. Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Linn Operating, LLC (“Linn Operating”), a subsidiary of LINN Energy, pursuant to which Linn Operating will provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period.
Under the MSA, Roan will reimburse Linn Operating for certain costs and expenses incurred by Linn Operating in connection with providing the services, and Roan will pay to Linn Operating a service fee of $1.25 million per month, prorated for partial months. The termination of the MSA will be the earliest of: (a) mutual agreement of the parties; (b) upon 30 days’ prior written notice from Roan to Linn Operating; (c) upon five days’ prior written notice from Linn Operating to Roan of a material default by Roan under the MSA, provided Linn Operating must have provided prior written notice to Roan of such material default providing Roan 10 days to cure such material default and such material default has not been cured by the end of the 10 day time period; and (d) eight months from the date of the MSA.
In addition, the Company’s subsidiary, Blue Mountain Midstream LLC, has an agreement in place with Roan for the processing of natural gas from certain of Roan’s properties.
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For the four months ended December 31, 2017, the Company recognized service fees of approximately $5 million as a reduction to general and administrative expenses. The Company had approximately $23 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $18 million due to Roan, primarily associated with joint interest billings and natural gas purchases, included in “accounts payable and accrued expenses” on the consolidated balance sheet at December 31, 2017.
Berry Petroleum Company, LLC
Berry, a former subsidiary of the Predecessor, was deconsolidated effective December 31, 2016 (see Note 4). The employees of Linn Operating, Inc. (“LOI”), a subsidiary of the Predecessor, provided services and support to Berry in accordance with an agency agreement and power of attorney between Berry and LOI. Upon deconsolidation, transactions between the Predecessor and Berry were no longer eliminated in consolidation and were treated as related party transactions. These transactions include, but are not limited to, management fees paid to the Company by Berry. On the Effective Date, Berry emerged from bankruptcy as a stand-alone, unaffiliated entity.
For the two months ended February 28, 2017, and years ended December 31, 2016, and December 31, 2015, Berry incurred management fees of approximately $6 million, $69 million and $78 million, respectively, for services provided by LOI. The Predecessor also had accounts payable due to Berry of approximately $3 million included in “accounts payable and accrued expenses” on the consolidated balance sheet at December 31, 2016. In addition, $25 million due to Berry was included in “liabilities subject to compromise” on the Predecessor’s consolidated balance sheet at December 31, 2016.
The Company made no capital contributions to Berry during the year ended December 31, 2016. During the year ended December 31, 2015, the Company made capital contributions of approximately $471 million to Berry, including $250 million which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction of its borrowing base in May 2015.
The Company received no cash distributions from Berry during the year ended December 31, 2016. During the year ended December 31, 2015, the Company received cash distributions of approximately $89 million from Berry. In addition, in 2014, Berry advanced approximately $352 million to the Company. The Company was required to use the cash from the advance on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and credit facility. During the twelve months ended September 30, 2015, the Company spent approximately $223 million, including approximately $58 million in 2014, on capital expenditures in respect of Berry’s operations. On September 30, 2015, the Company repaid in full the remaining advance of approximately $129 million to Berry.
LinnCo, LLC
LinnCo, an affiliate of the Predecessor, was formed on April 30, 2012. All of LinnCo’s common shares were held by the public. As of December 31, 2016, LinnCo had no significant assets or operations other than those related to its interest in the Predecessor and owned approximately 71% of the Predecessor’s then outstanding units. In accordance with the Plan, LinnCo will be dissolved following the resolution of all outstanding claims.
The Predecessor had agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Predecessor had agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by the Predecessor on LinnCo’s behalf were expensed by the Predecessor.
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For the two months ended February 28, 2017, LinnCo incurred total general and administrative expenses of approximately $287,000, including approximately $240,000 related to services provided by the Predecessor. All of the expenses incurred during the two months ended February 28, 2017, had been paid by the Predecessor on LinnCo’s behalf as of February 28, 2017.
For the year ended December 31, 2016, LinnCo incurred total general and administrative expenses, reorganization expenses and offering costs of approximately $6.1 million, including approximately $2.4 million related to services provided by LINN Energy. Of the expenses and costs incurred during 2016, approximately $5.9 million had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2016.
For the year ended December 31, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3.4 million, including approximately $2.0 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2015 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2015.
The Company did not pay any distributions to LinnCo during the year ended December 31, 2016. During the year ended December 31, 2015, the Company paid approximately $121 million in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.
Other
One of the Predecessor’s former directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2016, and December 31, 2015, the Company incurred expenditures of approximately $5 million and $8 million, respectively, related to services rendered by Superior and its subsidiaries.
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The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
LINN Energy: | ||||||||||||||||
Property acquisition costs: | ||||||||||||||||
Proved | $ | — | $ | — | $ | — | $ | — | ||||||||
Unproved | — | — | — | — | ||||||||||||
Exploration costs | 103,689 | 15,153 | 40,074 | 19,929 | ||||||||||||
Development costs | 96,178 | 24,256 | 86,053 | 264,227 | ||||||||||||
Asset retirement costs | 376 | 312 | 112 | 3,331 | ||||||||||||
Total costs incurred – continuing operations | $ | 200,243 | $ | 39,721 | $ | 126,239 | $ | 287,487 | ||||||||
Total costs incurred – discontinued operations | $ | 1,313 | $ | 269 | $ | 11,453 | $ | 167,049 | ||||||||
Four Months Ended December 31, 2017 | |||
(in thousands) | |||
Equity method investments (1) | |||
Property acquisition costs: | |||
Proved | $ | — | |
Unproved | 6,851 | ||
Exploration costs | 3,626 | ||
Development costs | 89,585 | ||
Total costs incurred | $ | 100,062 | |
(1) | Represents the Company’s 50% equity interest in Roan. Costs incurred of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017. |
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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:
Successor | Predecessor | |||||||
December 31, 2017 | December 31, 2016 | |||||||
(in thousands) | ||||||||
LINN Energy: | ||||||||
Proved properties | $ | 904,390 | $ | 12,234,099 | ||||
Unproved properties | 45,693 | 998,860 | ||||||
950,083 | 13,232,959 | |||||||
Less accumulated depletion and amortization | (49,619 | ) | (9,999,560 | ) | ||||
900,464 | 3,233,399 | |||||||
Less oil and natural gas capitalized costs, net – discontinued operations | — | (728,190 | ) | |||||
$ | 900,464 | $ | 2,505,209 | |||||
December 31, 2017 | |||
(in thousands) | |||
Equity Method Investments: (1) | |||
Proved properties | $ | 400,682 | |
Unproved properties | 538,703 | ||
939,385 | |||
Less accumulated depletion and amortization | (28,441 | ) | |
$ | 910,944 | ||
(1) | Represents the Company’s 50% equity interest in Roan. |
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Results of Oil and Natural Gas Producing Activities
The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs):
Successor | Predecessor | |||||||||||||||
Ten Months Ended December 31, 2017 | Two Months Ended February 28, 2017 | Year Ended December 31, 2016 | Year Ended December 31, 2015 | |||||||||||||
(in thousands) | ||||||||||||||||
LINN Energy: | ||||||||||||||||
Revenues and other: | ||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 709,363 | $ | 188,885 | $ | 874,161 | $ | 1,065,795 | ||||||||
Gains (losses) on oil and natural gas derivatives | 13,533 | 92,691 | (164,330 | ) | 1,027,014 | |||||||||||
722,896 | 281,576 | 709,831 | 2,092,809 | |||||||||||||
Production costs: | ||||||||||||||||
Lease operating expenses | 208,446 | 49,665 | 296,891 | 352,077 | ||||||||||||
Transportation expenses | 113,128 | 25,972 | 161,574 | 167,023 | ||||||||||||
Severance taxes, ad valorem taxes and California carbon allowances | 47,411 | 14,851 | 66,616 | 97,732 | ||||||||||||
368,985 | 90,488 | 525,081 | 616,832 | |||||||||||||
Other costs: | ||||||||||||||||
Exploration costs | 3,137 | 93 | 4,080 | 9,473 | ||||||||||||
Depletion and amortization | 101,360 | 39,689 | 295,889 | 471,046 | ||||||||||||
Impairment of long-lived assets | — | — | 165,044 | 4,960,144 | ||||||||||||
(Gains) losses on sale of assets and other, net | (678,200 | ) | 18 | 417 | (199,296 | ) | ||||||||||
Income tax benefit | (4,640 | ) | (166 | ) | (649 | ) | (2,721 | ) | ||||||||
(578,343 | ) | 39,634 | 464,781 | 5,238,646 | ||||||||||||
Results of operations – continuing operations | $ | 932,254 | $ | 151,454 | $ | (280,031 | ) | $ | (3,762,669 | ) | ||||||
Results of operations – discontinued operations | $ | 142,175 | $ | 1,246 | $ | (1,076,407 | ) | $ | (844,754 | ) | ||||||
There is no federal tax provision included in the Predecessor’s results above because the Predecessor’s subsidiaries subject to federal income taxes did not own any of the Predecessor’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 17 for additional information about income taxes.
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Four Months Ended December 31, 2017 | |||
(in thousands) | |||
Equity Method Investments: (1) | |||
Revenues and other: | |||
Oil, natural gas and natural gas liquids sales | $ | 42,322 | |
Losses on oil and natural gas derivatives | (4,591 | ) | |
37,731 | |||
Production costs: | |||
Lease operating expenses | 4,102 | ||
Transportation expenses | 4,576 | ||
Severance taxes and ad valorem taxes | 1,026 | ||
9,704 | |||
Other costs: | |||
Exploration costs | 3,626 | ||
Depletion and amortization | 11,371 | ||
14,997 | |||
Results of operations | $ | 13,030 | |
(1) | Represents the Company’s 50% equity interest in Roan. Results of oil and natural gas producing activities of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017. |
There is no tax provision included in Roan’s results above because Roan is not subject to federal income taxes.
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Proved Oil, Natural Gas and NGL Reserves
The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2017, December 31, 2016, and December 31, 2015, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:
Successor | |||||||||||||||||
Year Ended December 31, 2017 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
LINN Energy: | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 2,290 | 72.6 | 104.1 | 3,350 | 170 | 3,520 | |||||||||||
Revisions of previous estimates | (102 | ) | (5.6 | ) | 9.7 | (78 | ) | — | (78 | ) | |||||||
Sales of minerals in place | (754 | ) | (37.0 | ) | (39.6 | ) | (1,213 | ) | (164 | ) | (1,377 | ) | |||||
Extensions and discoveries | 90 | 3.7 | 4.9 | 142 | — | 142 | |||||||||||
Production | (147 | ) | (6.6 | ) | (7.6 | ) | (233 | ) | (6 | ) | (239 | ) | |||||
End of year | 1,377 | 27.1 | 71.5 | 1,968 | — | 1,968 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,118 | 66.7 | 94.4 | 3,084 | 170 | 3,254 | |||||||||||
End of year | 1,323 | 27.0 | 70.5 | 1,908 | — | 1,908 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 172 | 5.9 | 9.7 | 266 | — | 266 | |||||||||||
End of year | 54 | 0.1 | 1.0 | 60 | — | 60 | |||||||||||
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Four Months Ended December 31, 2017 | |||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total (Bcfe) | ||||||||
Equity Method Investments: (1) | |||||||||||
Proved developed and undeveloped reserves: | |||||||||||
Beginning of period | 173 | 10.3 | 17.8 | 342 | |||||||
Revisions of previous estimates | (14 | ) | (2.6 | ) | (1.9 | ) | (42 | ) | |||
Extensions and discoveries | 189 | 11.4 | 24.3 | 403 | |||||||
Production | (5 | ) | (0.4 | ) | (0.4 | ) | (9 | ) | |||
End of year | 343 | 18.7 | 39.8 | 694 | |||||||
Proved developed reserves: | |||||||||||
Beginning of year | 95 | 4.5 | 7.9 | 169 | |||||||
End of year | 130 | 6.2 | 12.0 | 239 | |||||||
Proved undeveloped reserves: | |||||||||||
Beginning of year | 78 | 5.8 | 9.9 | 173 | |||||||
End of year | 213 | 12.5 | 27.8 | 455 | |||||||
(1) | Represents the Company’s 50% equity interest in Roan. |
Predecessor | |||||||||||||||||
Year Ended December 31, 2016 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
LINN Energy: | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 2,212 | 74.3 | 97.0 | 3,240 | 1,248 | 4,488 | |||||||||||
Revisions of previous estimates | — | (3.8 | ) | 1.2 | (16 | ) | (192 | ) | (208 | ) | |||||||
Extensions and discoveries | 265 | 10.1 | 15.2 | 417 | 11 | 428 | |||||||||||
Production | (187 | ) | (8.0 | ) | (9.3 | ) | (291 | ) | (93 | ) | (384 | ) | |||||
Deconsolidation of Berry Petroleum, LLC proved reserves | — | — | — | — | (804 | ) | (804 | ) | |||||||||
End of year | 2,290 | 72.6 | 104.1 | 3,350 | 170 | 3,520 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,212 | 74.3 | 97.0 | 3,240 | 1,248 | 4,488 | |||||||||||
End of year | 2,118 | 66.7 | 94.4 | 3,084 | 170 | 3,254 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | — | — | — | — | — | — | |||||||||||
End of year | 172 | 5.9 | 9.7 | 266 | — | 266 | |||||||||||
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Predecessor | |||||||||||||||||
Year Ended December 31, 2015 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
LINN Energy: | |||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 3,552 | 147.8 | 146.3 | 5,318 | 1,986 | 7,304 | |||||||||||
Revisions of previous estimates | (1,137 | ) | (62.4 | ) | (38.7 | ) | (1,743 | ) | (636 | ) | (2,379 | ) | |||||
Sales of minerals in place | (13 | ) | (4.1 | ) | (2.0 | ) | (50 | ) | — | (50 | ) | ||||||
Extensions and discoveries | 10 | 3.0 | 0.8 | 32 | 15 | 47 | |||||||||||
Production | (200 | ) | (10.0 | ) | (9.4 | ) | (317 | ) | (117 | ) | (434 | ) | |||||
End of year | 2,212 | 74.3 | 97.0 | 3,240 | 1,248 | 4,488 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,981 | 104.2 | 117.5 | 4,312 | 1,506 | 5,818 | |||||||||||
End of year | 2,212 | 74.3 | 97.0 | 3,240 | 1,248 | 4,488 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 571 | 43.6 | 28.8 | 1,006 | 480 | 1,486 | |||||||||||
End of year | — | — | — | — | — | — | |||||||||||
The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf. Reserves for the Company’s California properties and Berry are reported as discontinued operations for all periods presented.
Proved reserves from continuing operations decreased by approximately 1,382 Bcfe to approximately 1,968 Bcfe for the year ended December 31, 2017, from 3,350 Bcfe for the year ended December 31, 2016. The year ended December 31, 2017, includes approximately 78 Bcfe of negative revisions of previous estimates (264 Bcfe of negative revisions due to asset performance partially offset by 186 Bcfe of positive revisions due to higher commodity prices). During the year ended December 31, 2017, several divestitures decreased reserves by approximately 1,213 Bcfe (see Note 4 for additional information of divestitures). In addition, extensions and discoveries, primarily from 90 productive wells drilled during the year, contributed approximately 142 Bcfe to the increase in proved reserves.
Proved reserves from continuing operations increased by approximately 110 Bcfe to approximately 3,350 Bcfe for the year ended December 31, 2016, from 3,240 Bcfe for the year ended December 31, 2015. The year ended December 31, 2016, includes approximately 16 Bcfe of negative revisions of previous estimates (97 Bcfe of negative revisions due to lower commodity prices partially offset by 81 Bcfe of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 211 productive wells drilled during the year, contributed approximately 417 Bcfe to the increase in proved reserves.
Proved reserves from continuing operations decreased by approximately 2,078 Bcfe to approximately 3,240 Bcfe for the year ended December 31, 2015, from 5,318 Bcfe for the year ended December 31, 2014. The year ended December 31, 2015, includes approximately 1,743 Bcfe of negative revisions of previous estimates (1,332 Bcfe due to lower commodity prices, 197 Bcfe due to uncertainty regarding the Company’s future commitment to capital and 237 Bcfe due to the SEC five-year development limitation on PUDs, partially offset by 23 Bcfe of positive revisions due to asset performance). During the year ended December 31, 2015, divestitures including the Howard County Assets Sale decreased proved reserves by approximately 50 Bcfe. In addition, extensions and discoveries, primarily from 388 productive wells drilled during the year,
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contributed approximately 32 Bcfe to the increase in proved reserves. As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved at December 31, 2015.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves
Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the year-end statutory tax rates (with consideration of any known future changes) to the pretax net cash flows, reduced by the applicable tax basis and giving effect to any tax deductions, tax credits and allowances relating to the proved oil and natural gas reserves. There are no future income tax expenses at December 31, 2016, or December 31, 2015, because the Predecessor was not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts were not material. See Note 17 for additional information about income taxes.
December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
LINN Energy: | |||||||||||
Future cash inflows | $ | 6,730,186 | $ | 9,856,698 | $ | 10,396,598 | |||||
Future production costs | (3,810,932 | ) | (5,755,460 | ) | (6,576,424 | ) | |||||
Future development costs | (486,989 | ) | (917,262 | ) | (722,685 | ) | |||||
Future income tax expenses | (303,803 | ) | — | — | |||||||
Future net cash flows | 2,128,462 | 3,183,976 | 3,097,489 | ||||||||
10% annual discount for estimated timing of cash flows | (1,083,331 | ) | (1,488,219 | ) | (1,404,304 | ) | |||||
Standardized measure of discounted future net cash flows – continuing operations | $ | 1,045,131 | $ | 1,695,757 | $ | 1,693,185 | |||||
Standardized measure of discounted future net cash flows – discontinued operations | $ | — | $ | 232,941 | $ | 1,340,360 | |||||
Representative NYMEX prices: (1) | |||||||||||
Natural gas (MMBtu) | $ | 2.98 | $ | 2.48 | $ | 2.59 | |||||
Oil (Bbl) | $ | 51.34 | $ | 42.64 | $ | 50.16 | |||||
(1) | In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
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December 31, 2017 | |||
(in thousands) | |||
Equity Method Investments: (1) | |||
Future cash inflows | $ | 2,635,233 | |
Future production costs | (832,362 | ) | |
Future development costs | (372,884 | ) | |
Future net cash flows | 1,429,987 | ||
10% annual discount for estimated timing of cash flows | (832,152 | ) | |
Standardized measure of discounted future net cash flows | $ | 597,835 | |
Representative NYMEX prices: (2) | |||
Natural gas (MMBtu) | $ | 2.98 | |
Oil (Bbl) | $ | 51.34 | |
(1) | Represents the Company’s 50% equity interest in Roan. |
(2) | In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
There are no future income tax expenses at December 31, 2017, because Roan is not subject to federal income taxes.
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in thousands) | |||||||||||
LINN Energy: | |||||||||||
Sales and transfers of oil, natural gas and NGL produced during the period | $ | (438,775 | ) | $ | (349,080 | ) | $ | (448,963 | ) | ||
Changes in estimated future development costs | (5,276 | ) | 19,460 | 953,393 | |||||||
Net change in sales and transfer prices and production costs related to future production | 400,411 | (92,236 | ) | (5,313,449 | ) | ||||||
Sales of minerals in place | (685,050 | ) | — | (97,785 | ) | ||||||
Extensions, discoveries and improved recovery | 187,223 | 221,765 | 46,487 | ||||||||
Previously estimated development costs incurred during the period | 9,704 | — | 84,329 | ||||||||
Net change due to revisions in quantity estimates | (65,935 | ) | 10,387 | (939,030 | ) | ||||||
Net change in income taxes | (155,257 | ) | — | — | |||||||
Accretion of discount | 169,576 | 169,318 | 707,085 | ||||||||
Changes in production rates and other | (67,247 | ) | 22,958 | (369,736 | ) | ||||||
Change – continuing operations | $ | (650,626 | ) | $ | 2,572 | $ | (5,377,669 | ) | |||
Change – discontinued operations | $ | (232,941 | ) | $ | (1,107,419 | ) | $ | (4,101,077 | ) | ||
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Four Months Ended December 31, 2017 | |||
(in thousands) | |||
Equity Method Investments (1) | |||
Standardized measure – Beginning of period | $ | 304,900 | |
Sales and transfers of oil, natural gas and NGL produced during the period | (32,618 | ) | |
Changes in estimated future development costs | (14,617 | ) | |
Net change in sales and transfer prices and production costs related to future production | 33,912 | ||
Extensions, discoveries and improved recovery | 270,737 | ||
Previously estimated development costs incurred during the period | 89,457 | ||
Net change due to revisions in quantity estimates | (47,222 | ) | |
Accretion of discount | 10,163 | ||
Changes in production rates and other | (16,877 | ) | |
Net increase | 292,935 | ||
Standardized measure – End of year | $ | 597,835 | |
(1) | Represents the Company’s 50% equity interest in Roan. Changes in the standardized measure of discounted future net cash flows of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017. |
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
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The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
Quarterly Financial Data
Predecessor | Successor | |||||||||||||||||||
January 1, 2017 to February 28, 2017 | March 1, 2017 to March 31, 2017 | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||
(in thousands, except per share and per unit amounts) | ||||||||||||||||||||
2017: | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 188,885 | $ | 80,325 | $ | 243,167 | $ | 206,318 | $ | 179,553 | ||||||||||
Gains (losses) on oil and natural gas derivatives | 92,691 | (11,959 | ) | 45,714 | (14,497 | ) | (5,725 | ) | ||||||||||||
Total revenues and other | 298,127 | 73,308 | 307,819 | 236,682 | 208,869 | |||||||||||||||
Total expenses (1) | 214,327 | 78,349 | 220,548 | 202,143 | 191,491 | |||||||||||||||
(Gains) losses on sale of assets and other, net | 829 | 484 | (306,878 | ) | (26,977 | ) | (289,701 | ) | ||||||||||||
Reorganization items, net | 2,331,189 | (2,565 | ) | (3,377 | ) | (2,605 | ) | (304 | ) | |||||||||||
Income (loss) from continuing operations | 2,397,609 | (7,324 | ) | 223,379 | 51,030 | 85,587 | ||||||||||||||
Income (loss) from discontinued operations, net of income taxes | (548 | ) | 68 | (3,322 | ) | 86,099 | 150 | |||||||||||||
Net income (loss) | 2,397,061 | (7,256 | ) | 220,057 | 137,129 | 85,737 | ||||||||||||||
Net income attributable to noncontrolling interests | — | — | — | 66 | 2,741 | |||||||||||||||
Net income attributable to stockholders/unitholders | 2,397,061 | (7,256 | ) | 220,057 | 137,063 | 82,996 | ||||||||||||||
Income (loss) per share/unit – continuing operations: | ||||||||||||||||||||
Basic | $ | 6.80 | $ | (0.08 | ) | $ | 2.49 | $ | 0.58 | $ | 0.98 | |||||||||
Diluted | $ | 6.80 | $ | (0.08 | ) | $ | 2.47 | $ | 0.57 | $ | 0.94 | |||||||||
Income (loss) per share/unit – discontinued operations: | ||||||||||||||||||||
Basic | $ | (0.01 | ) | $ | — | $ | (0.04 | ) | $ | 0.98 | $ | — | ||||||||
Diluted | $ | (0.01 | ) | $ | — | $ | (0.04 | ) | $ | 0.97 | $ | — | ||||||||
Net income (loss) per share/unit: | ||||||||||||||||||||
Basic | $ | 6.79 | $ | (0.08 | ) | $ | 2.45 | $ | 1.56 | $ | 0.98 | |||||||||
Diluted | $ | 6.79 | $ | (0.08 | ) | $ | 2.43 | $ | 1.54 | $ | 0.94 | |||||||||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
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During the third quarter of 2017, the Company corrected its allocation of value between proved and unproved oil and natural gas properties initially recorded as part of fresh start accounting (see Note 3) resulting in a reclassification of approximately $459 million from proved properties to unproved properties as of February 28, 2017. As a result, during the third quarter of 2017, the Company also recorded pretax out-of-period corrections of approximately $8 million to reduce depletion expense and approximately $1 million to increase net gains on sale of assets (combined $5 million after tax), as well as approximately $8 million to increase income from discontinued operations, net of income taxes, related to errors in the first and second quarters of 2017. The Company concluded that the correction of the errors was not material to these or any previously issued financial statements.
Predecessor | |||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||
2016: | |||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 184,441 | $ | 195,847 | $ | 237,986 | $ | 255,887 | |||||||
Gains (losses) on oil and natural gas derivatives | 109,453 | (183,794 | ) | 166 | (90,155 | ) | |||||||||
Total revenues and other | 331,261 | 44,245 | 266,975 | 197,163 | |||||||||||
Total expenses (1) | 449,809 | 274,941 | 310,772 | 269,906 | |||||||||||
Losses on sale of assets and other, net | 1,468 | 2,607 | 2,532 | 9,650 | |||||||||||
Reorganization items, net | — | 485,798 | (28,361 | ) | (145,838 | ) | |||||||||
Income (loss) from continuing operations | (213,868 | ) | 204,691 | (96,301 | ) | (261,865 | ) | ||||||||
Income (loss) from discontinued operations, net of income taxes | (1,133,878 | ) | 3,801 | (102,064 | ) | (572,372 | ) | ||||||||
Net income (loss) | (1,347,746 | ) | 208,492 | (198,365 | ) | (834,237 | ) | ||||||||
Income (loss) per unit – continuing operations: | |||||||||||||||
Basic | $ | (0.61 | ) | $ | 0.58 | $ | (0.27 | ) | $ | (0.74 | ) | ||||
Diluted | $ | (0.61 | ) | $ | 0.58 | $ | (0.27 | ) | $ | (0.74 | ) | ||||
Income (loss) per unit – discontinued operations: | |||||||||||||||
Basic | $ | (3.22 | ) | $ | 0.01 | $ | (0.29 | ) | $ | (1.62 | ) | ||||
Diluted | $ | (3.22 | ) | $ | 0.01 | $ | (0.29 | ) | $ | (1.62 | ) | ||||
Net income (loss) per unit: | |||||||||||||||
Basic | $ | (3.83 | ) | $ | 0.59 | $ | (0.56 | ) | $ | (2.36 | ) | ||||
Diluted | $ | (3.83 | ) | $ | 0.59 | $ | (0.56 | ) | $ | (2.36 | ) | ||||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A. 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 the Company’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 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 December 31, 2017.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Report on Internal Control Over Financial Reporting” in Item 8. “Financial Statements and Supplementary Data.”
Remediation of Previously Identified Material Weakness in Internal Control Over Financial Reporting
As previously disclosed in the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, filed with the SEC on November 14, 2017, during the third quarter of 2017, the Company’s management determined that a material weakness existed in the Company’s internal control over financial reporting, specifically related to the Company’s adoption of fresh start accounting upon emergence from bankruptcy on February 28, 2017. The Company did not have adequately designed controls over the application of GAAP used to measure the carrying value of the underlying assets and liabilities in fresh start accounting, the involvement of individuals with the requisite knowledge, expertise and industry-specific experience to account for and disclose complex non-routine transactions, and the review and supervision of such accounting.
During the third and fourth quarters of 2017, the Company took actions to remediate the material weakness, including performing additional reviews of the allocation of proved and unproved properties on a field-by-field basis, and revised its policy to engage parties with the requisite knowledge, expertise and industry-specific experience as needed to assist in the accounting and disclosure of complex non-routine transactions. Management considered the qualifications of team members reviewing non-routine complex transactions to ensure they meet the qualifications required for the proposed and actual scope of work, as well as assignment of roles and responsibilities to third party service providers.
The Company completed the testing and evaluation of the operating effectiveness of the controls, and based on the results of the testing, the controls were determined to be designed and operating effectively as of December 31, 2017. Accordingly, the Company’s management concluded the previously reported material weakness was remediated as of December 31, 2017.
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal control 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
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consolidated 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.
Other than the additional controls related to the remediation of the material weakness, there were no changes in the Company’s internal control over financial reporting during the fourth quarter of 2017 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
None
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Part III
Item 10. Directors, Executive Officers and Corporate Governance
A list of the Company’s executive officers and biographical information appears below under the caption “Executive Officers of the Company.” Additional information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Executive Officers of the Company
Name | Age | Position with the Company | ||
Mark E. Ellis | 61 | President and Chief Executive Officer | ||
David B. Rottino | 51 | Executive Vice President and Chief Financial Officer | ||
Arden L. Walker, Jr. | 58 | Executive Vice President and Chief Operating Officer | ||
Thomas E. Emmons | 49 | Senior Vice President – Corporate Services | ||
Jamin B. McNeil | 52 | Senior Vice President – Houston Division Operations | ||
Candice J. Wells | 43 | Senior Vice President, General Counsel and Corporate Secretary | ||
Mark E. Ellis is the President and Chief Executive Officer in addition to serving on the Company’s board of directors and has served in such capacity since February 2017. He previously served as Chairman, President and Chief Executive Officer from December 2011 to February 2017, as President, Chief Executive Officer and Director from January 2010 to December 2011 and as President and Chief Operating Officer from December 2007 to January 2010. Mr. Ellis serves on the boards of PDC Energy, Inc., the Independent Petroleum Association of America, American Exploration & Production Council and the Houston Museum of Natural Science. Mr. Ellis is a member of the Society of Petroleum Engineers.
David B. Rottino is the Executive Vice President and Chief Financial Officer in addition to serving on the Company’s board of directors and has served in such capacity since February 2017. He previously served as Executive Vice President and Chief Financial Officer from August 2015 to February 2017 and as Executive Vice President, Business Development and Chief Accounting Officer from January 2014 to August 2015. From July 2010 to January 2014, he served as Senior Vice President of Finance, Business Development and Chief Accounting Officer and from June 2008 to July 2010, Mr. Rottino served as Senior Vice President and Chief Accounting Officer.
Arden L. Walker, Jr. is the Executive Vice President and Chief Operating Officer and has served in such capacity since January 2011. From January 2010 to January 2011, he served as Senior Vice President and Chief Operating Officer. Mr. Walker joined the Company in February 2007 as Senior Vice President, Operations and Chief Engineer. Mr. Walker is a member of the Society of Petroleum Engineers and Independent Petroleum Association of America.
Thomas E. Emmons is the Senior Vice President – Corporate Services and has served in such capacity since January 2014. He previously served as Vice President – Corporate Services from September 2012 to January 2014 and from August 2008 to September 2012, Mr. Emmons served as Vice President, Human Resources and Environmental, Health and Safety.
Jamin B. McNeil is the Senior Vice President – Houston Division Operations and has served in such capacity since January 2014. From June 2007 to January 2014, Mr. McNeil served as Vice President – Houston Division Operations. Mr. McNeil is a member of the Society of Petroleum Engineers.
Candice J. Wells is the Senior Vice President, General Counsel and Corporate Secretary and has served in such capacity since January 2016. From October 2013 to January 2016, Ms. Wells served as Vice President, General Counsel and Corporate Secretary. From March 2013 to October 2013, Ms. Wells served as Vice President, acting General Counsel and Corporate Secretary and from September 2011 to March 2013, she served as Vice President, Assistant General Counsel and Corporate Secretary.
Item 11. Executive Compensation
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Securities Authorized for Issuance Under Equity Compensation Plans
The following summarizes information regarding the number of shares of Class A common stock that are available for issuance under all of the Company’s equity compensation plans as of December 31, 2017:
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Unit Options, Warrants and Rights | Weighted Average Exercise Price of Outstanding Unit Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | |||||||
(a) | (b) | (c) | ||||||||
Equity compensation plans approved by security holders | — | $ | — | 2,831,696 | ||||||
Equity compensation plans not approved by security holders | — | — | — | |||||||
— | $ | — | 2,831,696 | |||||||
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Item 14. Principal Accounting Fees and Services
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
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Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) - 1. Financial Statements:
All financial statements are omitted for the reason that they are not required or the information is otherwise supplied in Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
(a) - 2. Financial Statement Schedules:
All schedules are omitted for the reason that they are not required or the information is otherwise supplied in Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
(a) - 3. Exhibits:
The exhibits required to be filed by this Item 15 are set forth in the “Index to Exhibits” accompanying this report.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
LINN ENERGY, INC. | ||
Date: February 27, 2018 | By: | /s/ Mark E. Ellis |
Mark E. Ellis President and Chief Executive Officer | ||
Date: February 27, 2018 | By: | /s/ David B. Rottino |
David B. Rottino Executive Vice President and Chief Financial Officer | ||
Date: February 27, 2018 | By: | /s/ Darren R. Schluter |
Darren R. Schluter Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Mark E. Ellis | President, Chief Executive Officer and Director (Principal Executive Officer) | February 27, 2018 | ||
Mark E. Ellis | ||||
/s/ David B. Rottino | Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) | February 27, 2018 | ||
David B. Rottino | ||||
/s/ Darren R. Schluter | Vice President and Controller (Principal Accounting Officer) | February 27, 2018 | ||
Darren R. Schluter | ||||
/s/ Matthew Bonanno | Director | February 27, 2018 | ||
Matthew Bonanno | ||||
/s/ Philip Brown | Director | February 27, 2018 | ||
Philip Brown | ||||
/s/ Evan Lederman | Chairman and Director | February 27, 2018 | ||
Evan Lederman | ||||
/s/ Andrew Taylor | Director | February 27, 2018 | ||
Andrew Taylor | ||||
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Index to Exhibits
Exhibit Number | Description | |
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
141
Index to Exhibits - Continued
Exhibit Number | Description | |
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
142
Index to Exhibits - Continued
Exhibit Number | Description | |
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
— | ||
101.INS† | — | XBRL Instance Document |
101.SCH† | — | XBRL Taxonomy Extension Schema Document |
143
Index to Exhibits - Continued
Exhibit Number | Description | |
101.CAL† | — | XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF† | — | XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB† | — | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE† | — | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Management Contract or Compensatory Plan or Arrangement required to be filed as an Exhibit hereto pursuant to Item 601 of Regulation S-K. |
** | Filed herewith. |
† | Furnished herewith. |
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