10-K 1 linnform10-k2017.htm FORM 10-K 2017 Document



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

linnenergylogoa02.jpg
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.

ii

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.

iii

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


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

1

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

2

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.

3

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.

4

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

5

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.

6

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.

8

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

 
 

 

 


9

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.

10

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.

11

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.

12

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

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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

21

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;

22

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

23

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

25

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


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