rvra-10k_20181231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2018

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

For the transition period from _______________ to _______________

Commission file number:  333-225927

Riviera Resources, Inc.

(Exact name of registrant as specified in its charter)

Delaware

 

82-5121920

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

600 Travis Street, Suite 1700

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      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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes      No 

 


 

Indicate by check mark whether the registrant has submitted electronically 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      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.     

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  

 

Accelerated filer  

 

 

 

Non-accelerated filer  

 

Smaller reporting company  

 

 

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

As of June 30, 2018, the last business day of the registrant’s most recently completed second quarter, the registrant’s common stock was not publicly traded. The registrant’s common stock began trading on the OTCQX Market on August 8, 2018.

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      No

As of January 31, 2019, there were 69,065,373 shares of common stock, par value $0.01 per share, outstanding.

Documents Incorporated By Reference:

Portions of the registrant’s definitive proxy statement relating to its 2019 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2018, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this Annual Report on Form 10‑K.

 

 

 


 

TABLE OF CONTENTS

 

 

 

Page

 

 

 

 

Glossary of Terms

ii

 

 

 

 

Part I

1

Item 1.

Business

1

Item 1A.

Risk Factors

22

Item 1B.

Unresolved Staff Comments

36

Item 2.

Properties

36

Item 3.

Legal Proceedings

36

Item 4.

Mine Safety Disclosures

37

 

Part II

38

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

38

Item 6.

Selected Financial Data

41

Item 7.

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

44

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

72

Item 8.

Financial Statements and Supplementary Data

73

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

128

Item 9A.

Controls and Procedures

128

Item 9B.

Other Information

128

 

Part III

129

Item 10.

Directors, Executive Officers and Corporate Governance

129

Item 11.

Executive Compensation

130

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

130

Item 13.

Certain Relationships and Related Transactions, and Director Independence

130

Item 14.

Principal Accounting Fees and Services

130

 

Part IV

131

Item 15.

Exhibits and Financial Statement Schedules

131

 

 

 

 

Signatures

136

 

 

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Table of Contents

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.

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

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Glossary of Terms – Continued

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 Commission 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.

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.

 

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Part I

Item 1.

Business

This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and assumptions as of the date of this filing.  These statements by their nature are subject to a number of risks and uncertainties.  Actual results may differ materially from those discussed in the forward-looking statements.  For more information, see “Cautionary Statement Regarding Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”

References

Unless otherwise indicated or the context otherwise requires, references herein to the “Company,” “we,” “our,” and “us” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (the “Parent”) and its consolidated subsidiaries, and (ii) after the Spin-off, to Riviera Resources, Inc. (“Riviera”) and its consolidated subsidiaries.  Unless otherwise indicated or the context otherwise requires, references herein to “LINN Energy” refer to Linn Energy, Inc. and its consolidated subsidiaries.  References to “Successor” relate to the financial position and results of operations of the Company subsequent to LINN Energy’s emergence from bankruptcy on February 28, 2017.  References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including February 28, 2018.  Riviera is a successor issuer of the Parent pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

The reference to a “Note” herein refers to the accompanying Notes to Consolidated and Combined Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”

Overview

In April 2018, the Parent announced its intention to separate Riviera from LINN Energy.

To effect the separation, the Parent and certain of its then direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera Resources, LLC from a limited liability company to a corporation named Riviera Resources, Inc.), following which Riviera holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan Resources LLC (“Roan”).  A subsidiary of the Company held the equity interest in Roan until the Parent’s internal reorganization on July 25, 2018 (the “Reorganization Date”).  Following the internal reorganization, the Parent distributed all of the outstanding shares of Riviera common stock to the Parent’s shareholders on a pro rata basis (the “Spin-off”).  The Spin-off was completed on August 7, 2018.

Following the Spin-off, Riviera is an independent reporting company quoted for trading on the OTCQX Market under the ticker “RVRA,” and the Parent did not retain any ownership interest in Riviera.

Prior to the Spin-off, the accompanying consolidated and combined financial statements were prepared on a stand-alone basis and derived from the Parent’s consolidated financial statements and accounting records for the periods presented as the Company was historically managed as a subsidiary of the Parent.  After the Spin-off, Riviera is an independent company.

The Company’s upstream reporting segment properties are currently located in six operating regions in the United States (“U.S.”): the Hugoton Basin, East Texas, Michigan/Illinois, the Mid-Continent, North Louisiana and the Uinta Basin.  Proved reserves at December 31, 2018, were approximately 1,618 Bcfe, of which approximately 78% were natural gas, 21% were natural gas liquids (“NGL”) and 1% were oil.  Approximately 96% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $747 million.  In addition, the Company estimates the total discounted future net cash flows of its helium reserves are approximately $110 million, net of income taxes.  At December 31, 2018, the Company operated 7,078 or approximately 57% of its 12,354 gross productive wells.

The Blue Mountain reporting segment consists of a state of the art cryogenic natural gas processing facility and a network of gathering pipelines and compressors located in the Merge/SCOOP/STACK play, each of which is owned by Blue Mountain Midstream LLC (“Blue Mountain Midstream”), a wholly owned subsidiary of the Company.

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Item 1.Business - Continued

Strategy

Riviera is an independent oil and natural gas company with a strategic focus on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to shareholders.  Blue Mountain Midstream is an emerging midstream company with assets in central Oklahoma focused on providing its customers with comprehensive natural gas, oil, natural gas liquids, and water solutions in a safe and environmentally sound manner, including gas gathering and processing, water gathering and treatment, and delivery of product to lucrative downstream markets.  In the future, Blue Mountain Midstream looks to expand the scale and scope of its service capabilities in the Merge/SCOOP/STACK through organic growth and strategic acquisitions.

Recent Developments

Divestitures

Below are the Company’s completed divestitures in 2018:

On April 10, 2018, the Company completed the sale of its conventional properties located in New Mexico.  Cash proceeds received from the sale of these properties were approximately $14 million and the Company recognized a net gain of approximately $12 million.

On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah.  Cash proceeds received from the sale of these properties were approximately $129 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $83 million.

On March 29, 2018, the Company completed the sale of its interest in conventional properties located in west Texas.  Cash proceeds received from the sale of these properties were approximately $105 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $54 million.

On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties.  Cash proceeds received from the sale of these properties were approximately $108 million (including a deposit of approximately $12 million received in 2017), net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $46 million.

Divestiture – Subsequent Event

On January 17, 2019, the Company completed the sale of its interest in properties located in the Arkoma Basin in Oklahoma and received cash proceeds of approximately $65 million (including a deposit of approximately $5 million received in 2018).

Water Services Agreement

On January 31, 2019, the Company entered into an agreement with Roan to exclusively manage all of Roan’s water needs for its drilling and completion operations in Central Oklahoma.  Blue Mountain Midstream will provide comprehensive water management services including pipeline gathering, disposal, treatment and redelivery of recycled water for re-use.  The agreement is supported by a 10-year acreage dedication in 67 Townships covering portions of seven Oklahoma Counties.

Construction of Cryogenic Plant

In July 2017, the Company’s subsidiary Blue Mountain Midstream entered into a definitive agreement with BCCK Engineering, Inc. to construct a 225 MMcf/d cryogenic natural gas processing facility with a total capacity of 250 MMcf/d (“Cryo 1”).  The facility was successfully commissioned in the second quarter of 2018.

In August 2018, the Company’s Board of Directors (the “Board”) approved Blue Mountain Midstream’s plan to initiate the engineering and design of a second cryogenic natural gas processing plant (“Cryo 2”) servicing the Merge/SCOOP/STACK play in central Oklahoma.  Blue Mountain Midstream has completed the conceptual engineering and design for Cryo 2 and has the ability to execute on Cryo 2 quickly if the election is eventually made to proceed.

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Item 1.Business - Continued

2018 Oil and Natural Gas and Midstream Capital Expenditures

During the year ended December 31, 2018, the Company had total capital expenditures, excluding acquisitions, of approximately $170 million, including approximately $36 million related to its oil and natural gas capital program and approximately $125 million related to Blue Mountain Midstream.

2019 Oil and Natural Gas Capital Budget

For 2019, the Company estimates its total capital expenditures, excluding acquisitions and Blue Mountain, will be approximately $66 million, including approximately $61 million related to its oil and natural gas capital program.  This estimate is under continuous review and subject to ongoing adjustments.

Financing Activities

Blue Mountain Credit Facility

On August 10, 2018, Blue Mountain Midstream entered into a credit agreement with Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured revolving loan facility (the “Blue Mountain Credit Facility” and together with Riviera Credit Facility, the “Credit Facilities”), providing for an initial borrowing commitment of $200 million.

Before Blue Mountain Midstream completes certain operational milestones (such completion of the operational milestones, the “Covenant Changeover Date”), a condition to any borrowing is that Blue Mountain Midstream’s consolidated total indebtedness to capitalization ratio (the “Debt/Cap Ratio”) be not greater than 0.35 to 1.00 upon giving effect to such borrowing.  As such, prior to the Covenant Changeover Date, the available borrowing capacity under the Blue Mountain Credit Facility may be less than the aggregate amount of the lenders’ commitments at such time.  On and after the Covenant Changeover Date, Blue Mountain Midstream will no longer have to comply with the Debt/Cap Ratio as a condition to drawing and may borrow up to the total amount of the lenders’ aggregate commitments.  The Blue Mountain Credit Facility also provides for the ability to increase the aggregate commitments of the lenders to up to $400 million after the Covenant Changeover Date, subject to obtaining commitments for any such increase, which may result in an increase in Blue Mountain Midstream’s available borrowing capacity.  As of December 31, 2018, total borrowings outstanding under the Blue Mountain Credit Facility were $4.5 million and there was approximately $72 million of available borrowing capacity (in addition, there was $12 million of outstanding letters of credit).  The Covenant Changeover Date occurred February 8, 2019, which increased the current borrowing commitment to $200 million.  At February 28, 2019, total borrowings outstanding under the Blue Mountain Credit Facility were approximately $19 million and there was approximately $169 million of available borrowing capacity (which includes a $12 million reduction for outstanding letters of credit).  The Blue Mountain Credit Facility matures on August 10, 2023.

Share Repurchase Program

On August 16, 2018, the Board authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock.  During the period from August 2018 through December 31, 2018, the Company repurchased an aggregate of 945,979 shares of common stock at an average price of $19.21 per share for a total cost of approximately $18 million.  For the period from January 1, 2019 through February 22, 2019, the Company repurchased 221,788 shares of common stock at an average price of $15.27 for a total cost of approximately $3 million.  At February 22, 2019, approximately $78 million was available for share repurchase under the program.

In accordance with the SEC’s regulations regarding issuer tender offers, the Company’s share repurchase program was suspended concurrent with the September 24, 2018, announcement of the intent to commence a tender offer. The program was resumed in November 2018 following the expiration of the tender offer.

Any share repurchases are subject to restrictions in the Company’s senior secured reserve-based revolving loan facility (the “Riviera Credit Facility”).

Tender Offer

On September 24, 2018, the Company announced the intention to commence a tender offer to purchase $100 million of the Company’s common stock.  In October 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated September 25, 2018, as amended, the Company repurchased an aggregate of 6,062,179 shares of common stock at a

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Item 1.Business - Continued

price of $22.00 per share for a total cost of approximately $133 million (excluding expenses of approximately $2 million related to the tender offer).

Upstream Segment Operating Regions

The Company’s upstream segment properties are located in six operating regions in the U.S.:

 

Hugoton Basin, which includes oil and natural gas properties, as well as the Jayhawk natural gas processing plant, located in Kansas;

 

East Texas, which includes oil and natural gas properties producing primarily from the Travis Peak, Cotton Valley and Bossier formations;

 

Michigan/Illinois, which includes properties producing from the Antrim Shale formation located in northern Michigan and oil properties in southern Illinois;

 

Mid-Continent, which includes properties in the Northwest STACK in northwestern Oklahoma and various other oil and natural gas producing properties throughout Oklahoma;

 

North Louisiana, which includes oil and natural gas properties producing primarily from the Hosston, Cotton Valley Bossier and Smackover formations; and

 

Uinta Basin, which includes non-operated properties located in the Dunkards Wash field in Utah (which was included in the Company’s previous Rockies operating region).

Historically, a subsidiary of the Company also owned a 50% equity interest in Roan.  The Company’s equity earnings (losses), consisting of its share of Roan’s earnings or losses, are included in the consolidated financial statements through the Reorganization Date.  However, on the Reorganization Date, the equity interest in Roan was distributed to the Parent and is no longer affiliated with Riviera.  As such, the Company has classified the investment and equity earnings (losses) in Roan as discontinued operations on its consolidated financial statements.  See Note 4 for additional information.

During 2018, the Company divested all of its properties located in the previous Permian Basin operating region.  During 2017, the Company divested all of its properties located in the previous California and South Texas operating regions.  As a result of the Company’s strategic exit from California in 2017 (completed by the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California), the Company classified the results of operations and cash flows of its California properties as discontinued operations on its consolidated and combined financial statements.  See below 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.  The Company’s Hugoton Basin 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 3,120 miles of pipeline and related facilities operated by the Company, of which approximately 1,005 miles of pipeline are owned by the Company.

Hugoton Basin proved reserves represented approximately 50% of total proved reserves at December 31, 2018, all of which were classified as proved developed.  This region produced approximately 138 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $5 million for plant and pipeline construction activities in this region.

East Texas

The East Texas region consists of properties located in east Texas primarily producing natural gas from the Travis Peak, Cotton Valley and Bossier 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 590 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area.

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Item 1.Business - Continued

East Texas proved reserves represented approximately 17% of total proved reserves at December 31, 2018, of which 88% were classified as proved developed.  This region produced approximately 50 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $2 million to develop the properties in this region and approximately $2 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 14% of total proved reserves at December 31, 2018, all of which were classified as proved developed.  This region produced approximately 28 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $1 million to develop the properties in this region.

Mid-Continent

The Mid-Continent region consists of properties located in the Northwest STACK, as well as other Oklahoma properties.  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.

Mid-Continent proved reserves represented approximately 11% of total proved reserves at December 31, 2018, all of which were classified as proved developed.  This region produced approximately 53 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $10 million to develop the properties in this region and approximately $15 million in exploration activity.

North Louisiana

The North Louisiana region consists of properties located in north Louisiana and primarily producing natural gas from the Hosston, Cotton Valley, Bossier and Smackover formations at depths ranging from 7,000 feet to 12,500 feet.

North Louisiana proved reserves represented approximately 5% of total proved reserves at December 31, 2018, of which 64% were classified as proved developed.  This region produced approximately 26 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $2 million to develop the properties in this region.

Uinta Basin

The Uinta Basin region consists of non-operated properties located in the Drunkards Wash field in Utah.  The Uinta Basin properties were included in the Company’s previous Rockies operating region.  During 2017 and 2018, the Company divested its Rockies region properties located in Wyoming (Green River, Washakie and Powder River basins), North Dakota (Williston Basin) and certain Utah properties (Altamont Bluebell Field in the Uinta Basin).

Uinta Basin proved reserves represented approximately 3% of total proved reserves at December 31, 2018, all of which were classified as proved developed.  The Uinta Basin region produced approximately 23 MMcfe/d of the Company’s 2018 average daily production.  During 2018, the Company invested approximately $4 million to develop the properties in the Uinta Basin region.

Blue Mountain Segment

Blue Mountain Midstream currently provides natural gas gathering, compression and processing services to producers in the Merge/SCOOP/Stack play in the Mid-Continent Region of Oklahoma. Blue Mountain Midstream’s assets primarily consist of the state of the art 250 MMcf/d design-capacity Cryo 1 natural gas plant as well as a network of natural gas gathering pipelines and compressors (collectively, the “Blue Mountain System”).  The Cryo 1 natural gas plant was successfully

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commissioned in the second quarter of 2018. As of July 2018, the plant had an initial design capacity of approximately 150 MMcf/d of processing capacity. In the fourth quarter of 2018, Blue Mountain Midstream commissioned 25,000 horsepower compression at its Cryo 1, increasing the processing capacity to the full 250 MMcf/d. Blue Mountain Midstream’s gathering and processing agreements for its gathering and processing system include long-term, fee-based or percent of proceeds contracts. Based on Blue Mountain Midstream’s contracts it gathers natural gas and NGLs from the producers which it then processes and delivers to third party customers.

Blue Mountain Midstream is aggressively pursuing growth to its midstream business primarily in Oklahoma. Additions to the Blue Mountain System are continually underway adding low and high-pressure gathering pipelines and interconnections that will accommodate incremental volume throughput. During 2018, the Blue Mountain Midstream invested approximately $125 million for plant and pipeline construction activities primarily associated with the Blue Mountain System.

Blue Mountain Midstream has completed the conceptual engineering and design for Cryo 2 and has the ability to execute on Cryo 2 quickly if the election is eventually made to proceed.

Drilling and Acreage

The following table sets forth the wells drilled during the years indicated:

 

 

Year Ended December 31,

 

 

 

2018

 

 

2017

 

 

2016

 

Gross wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

52

 

 

 

90

 

 

 

211

 

Dry

 

 

 

 

 

 

 

 

1

 

 

 

 

52

 

 

 

90

 

 

 

212

 

Net development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

1

 

 

 

12

 

 

 

26

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

1

 

 

 

12

 

 

 

26

 

Net exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

2

 

 

 

9

 

 

 

7

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

2

 

 

 

9

 

 

 

7

 

 

There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2018, December 31, 2017, or December 31, 2016.  As of December 31, 2018, the Company had 21 gross (4 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.

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, 2018.  Productive wells consist of producing wells and wells capable of production, including wells

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awaiting pipeline or other connections to commence deliveries.  The number of wells below does not include approximately 2,620 gross productive wells in which the Company owns a royalty interest only.

 

 

Natural Gas Wells

 

 

Oil Wells

 

 

Total Wells (1)

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operated (2)

 

 

6,893

 

 

 

6,077

 

 

 

185

 

 

 

144

 

 

 

7,078

 

 

 

6,221

 

Nonoperated (3)

 

 

5,141

 

 

 

1,838

 

 

 

135

 

 

 

20

 

 

 

5,276

 

 

 

1,858

 

 

 

 

12,034

 

 

 

7,915

 

 

 

320

 

 

 

164

 

 

 

12,354

 

 

 

8,079

 

(1)

Includes 424 gross and 138 net wells divested in 2019.

(2)

The Company had five operated wells with multiple completions at December 31, 2018.

(3)

The Company had one nonoperated wells with multiple completions at December 31, 2018.

Developed and Undeveloped Acreage

The following table sets forth information relating to leasehold acreage as of December 31, 2018:

 

 

Developed Acreage

 

 

Undeveloped Acreage

 

 

Total Acreage (1)

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Leasehold acreage

 

 

3,170

 

 

 

1,912

 

 

 

38

 

 

 

13

 

 

 

3,208

 

 

 

1,925

 

(1)

Includes approximately 81,000 gross and 39,000 net acres divested in 2019.

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 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, 2018, the Company had no natural gas or NGL delivery commitments under a 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.

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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, 2018, 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

 

 

 

Year Ended

December 31,

2018

 

 

Ten Months

Ended

December 31,

2017

 

 

Two Months

Ended

February 28,

2017

 

 

Year Ended

December 31,

2016

 

Total production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

90,091

 

 

 

118,110

 

 

 

29,223

 

 

 

187,068

 

Oil (MBbls)

 

 

1,186

 

 

 

5,442

 

 

 

1,191

 

 

 

8,088

 

NGL (MBbls)

 

 

3,762

 

 

 

6,287

 

 

 

1,263

 

 

 

9,281

 

Total (MMcfe)

 

 

119,781

 

 

 

188,481

 

 

 

43,945

 

 

 

291,285

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf/d)

 

 

247

 

 

 

386

 

 

 

495

 

 

 

511

 

Oil (MBbls/d)

 

 

3.2

 

 

 

17.8

 

 

 

20.2

 

 

 

22.1

 

NGL (MBbls/d)

 

 

10.3

 

 

 

20.5

 

 

 

21.4

 

 

 

25.4

 

Total (MMcfe/d)

 

 

328

 

 

 

616

 

 

 

745

 

 

 

796

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted average prices: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

$

2.78

 

 

$

2.69

 

 

$

3.41

 

 

$

2.28

 

Oil (Bbl)

 

$

62.99

 

 

$

47.42

 

 

$

49.16

 

 

$

39.00

 

NGL (Bbl)

 

$

25.14

 

 

$

21.28

 

 

$

24.37

 

 

$

14.26

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average NYMEX prices:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMBtu)

 

$

3.09

 

 

$

3.00

 

 

$

3.66

 

 

$

2.46

 

Oil (Bbl)

 

$

64.77

 

 

$

50.53

 

 

$

53.04

 

 

$

43.32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs per Mcfe of production:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

1.00

 

 

$

1.11

 

 

$

1.13

 

 

$

1.02

 

Transportation expenses

 

$

0.70

 

 

$

0.60

 

 

$

0.59

 

 

$

0.55

 

General and administrative expenses (2)

 

$

2.05

 

 

$

0.62

 

 

$

1.63

 

 

$

0.82

 

Depreciation, depletion and amortization

 

$

0.79

 

 

$

0.71

 

 

$

1.07

 

 

$

1.18

 

Taxes, other than income taxes

 

$

0.25

 

 

$

0.25

 

 

$

0.34

 

 

$

0.23

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total production – discontinued operations:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity method investment – Total (MMcfe) (3)

 

 

23,355

 

 

 

9,235

 

 

 

 

 

 

 

California – Total (MMcfe) (4)

 

 

 

 

 

4,326

 

 

 

1,755

 

 

 

11,849

 

(1)

Does not include the effect of gains (losses) on derivatives.

(2)

General and administrative expenses for the year ended December 31, 2018, the ten months ended December 31, 2017, the two months ended February 28, 2017, and the year ended December 31, 2016, include approximately $132 million, $41 million, $50 million and $34 million, respectively, of share-based compensation expenses and approximately $27 million, $2 million, $787,000 and $2 million, respectively of severance costs.  General and administrative expenses for the year ended December 31, 2018, include

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approximately $8 million of Spin-off related costs.  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.

(3)

Represents the Company’s historical 50% equity interest in Roan.  Production of Roan for 2018 is for the period from January 1, 2018 through July 25, 2018.  Production of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017.

(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.

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,

 

 

 

2018

 

 

2017

 

 

2016

 

Total production:

 

 

 

 

 

 

 

 

 

 

 

 

Hugoton Basin Field:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

33,510

 

 

 

34,363

 

 

 

38,501

 

Oil (MBbls)

 

 

24

 

 

 

45

 

 

 

27

 

NGL (MBbls)

 

 

2,581

 

 

 

2,968

 

 

 

2,983

 

Total (MMcfe)

 

 

49,137

 

 

 

52,437

 

 

 

56,566

 

East Texas Basin:

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (MMcf)

 

 

17,355

 

 

*

 

 

*

 

Oil (MBbls)

 

 

66

 

 

*

 

 

*

 

NGL (MBbls)

 

 

113

 

 

*

 

 

*

 

Total (MMcfe)

 

 

18,432

 

 

*

 

 

*

 

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, 2018, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton:

 

 

Proved Reserves

 

 

 

Natural Gas

(Bcf)

 

 

Oil

(MMBbls)

 

 

NGL

(MMBbls)

 

 

Total

(Bcfe)

 

Proved reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves

 

 

1,203

 

 

 

4

 

 

 

55

 

 

 

1,553

 

Proved undeveloped reserves

 

 

57

 

 

 

 

 

 

1

 

 

 

65

 

Total proved reserves

 

 

1,260

 

 

 

4

 

 

 

56

 

 

 

1,618

 

 

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Standardized measure of discounted future net cash flows (in millions) (1)

 

$

747

 

 

 

 

 

 

Representative NYMEX prices: (2)

 

 

 

 

Natural gas (MMBtu)

 

$

3.10

 

Oil (Bbl)

 

$

65.66

 

(1)

This measure is not intended to represent the market value of estimated reserves.

(2)

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, 2018, the Company’s PUDs increased to 65 Bcfe from 60 Bcfe at December 31, 2017, representing an increase of approximately 5 Bcfe.  The increase was primarily due to revisions as a result of additional PUD locations being added.  During the year ended December 31, 2018, the Company did not convert any reserves that were classified as PUDs at December 31, 2017, to proved developed reserves.

Based on the December 31, 2018, reserve reports, the amounts of capital expenditures estimated to be incurred in 2019, 2020 and 2021 to develop the Company’s PUDs are approximately $5 million, $5 million and $40 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 65 Bcfe of PUDs at December 31, 2018, 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 Director of Reserves and Business Development who has a Master of Petroleum Engineering degree and 10 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.  For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.”  The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.

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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, 2018, sales to ONEOK Hydrocarbon, L.P. accounted for approximately 22% of the Company’s total revenues.  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 non-operated basis, 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.

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Seasonality and Cyclicality

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, the Company’s 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, 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;

 

National Environmental Policy Act, which governs oil and natural gas production activities on federal lands;

 

Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste;

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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 includes new rules or legislation relating to the items discussed below.

Climate Change

In December 2009, the United States 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 Clean Air Act. 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. However, in September 2018, under a new administration, the EPA proposed amendments that would relax requirements of these rules. In addition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including certain onshore oil and natural gas production facilities, on an annual basis.

On an international level, the U.S. was one of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020 (the “Paris Agreement”). However, on June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, 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 legislation or regulatory programs to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company’s business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas the Company produces. In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities. Finally, most 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

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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.

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, the 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 that rescission has been challenged by several environmental groups and states in ongoing litigation.  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 laws or regulations 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.

The Company disposes of wastewater generated from oil and natural gas production operations, including hydraulic fracturing operations, directly or through the use of third parties.  In some instances, the operation of underground injection or large volume disposal 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 disposal 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.  For example, Oklahoma issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions, required additional seismicity protocols in certain defined areas, and from time to time, directs certain injection wells in proximity to seismic events to restrict or suspend operations.  Future orders or regulations addressing concerns about seismic activity from well injection or water disposal could affect the Company, either directly or indirectly, depending on the wells affected, which materially affect its capital expenditures and operating costs.

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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 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

The New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs under the Clean Air Act impose specific requirements affecting the oil and gas industry under both programs for compressors, controllers, dehydrators, storage tanks, natural gas processing plants, completions, and certain other equipment and processes. Periodic review and revision of these and other rules by federal and state agencies may require changes to the Company’s operations, including possible installation of new equipment to control emissions. For example, as described above, in May 2016, the EPA finalized rules to reduce methane and volatile organic compound emissions from new, modified or reconstructed sources in the oil and natural gas sector; however, in September 2018, under a new administration, the EPA proposed amendments that would relax requirements of the rules. Similarly, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of regulations it previously enacted to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands; California and New Mexico have challenged the rule in ongoing litigation. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force the EPA to establish

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guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. 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. Further, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion in October 2015. 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 United States” (“WOTUS”), a term broadly defined to include, among other things, certain wetlands.  Under the CWA, permits must be obtained for the discharge of pollutants into WOTUS.  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 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 WOTUS.  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 resulted 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 WOTUS.  Subsequent litigation in the federal district courts has resulted in patchwork application of the rule in some states, but not others. In December 2018, EPA released revisions to the definition of WOTUS that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications. Several groups have already announced their intentions to challenge the proposed rule. To the extent the rule is enforced in jurisdictions in which the Company operates or a replacement rule expands the scope of the CWA’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

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 2019.  This pending restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

Economic Regulation

Regulation of pipeline gathering and transportation services, natural gas, NGLs, and crude oil sales, and transportation of natural gas, NGLs, and crude oil may affect certain aspects of the Company’s business and the market for its products and services.

Regulation of Interstate Natural Gas Pipelines

Blue Mountain Midstream owns and operates the Blue Mountain Delivery Line, which is a natural gas pipeline that extends approximately 10 miles from the Blue Mountain Chisholm Trail Cryogenic Gas Complex to delivery points on the interstate pipelines owned and operated by Southern Star Central Gas Pipeline, Inc. and Enable Gas Transmission, LLC.  Blue Mountain Midstream has obtained a limited jurisdiction certificate of public convenience and necessity under the Natural Gas

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Act of 1938 (“NGA”) for the Blue Mountain Delivery Line.  In the certificate order, among other things, the Federal Energy Regulatory Commission (“FERC”) waived requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements.  As such, the Blue Mountain Delivery Line is not currently subject to conventional rate regulation; to requirements FERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certain reports.  If, however, the Company receives a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted the Company and would require the Company to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon the Company.

Gathering Pipeline Regulation

The Company’s natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which it operates.  The common purchaser statutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer.  These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another.  The regulations under these statutes can have the effect of imposing some restrictions on the Company’s ability as an owner of gathering facilities to decide with whom it contracts to gather natural gas.  The states in which the Company operates have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.  The rates the Company charges for gathering are deemed just and reasonable unless challenged in a complaint.  The Company cannot predict whether such a complaint will be filed against it in the future.  Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA.  Although the FERC has not made any formal determinations with respect to any of the Company’s facilities, 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.

Natural Gas Processing

The Company’s natural gas processing operations are not presently subject to FERC regulation.  There can be no assurance that its processing operations will continue to be exempt from other FERC regulation in the future.

Sales of Natural Gas, NGLs and Crude Oil

The price at which the Company buys and sells natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most part, is not subject to state rate regulation.  However, with regard to the Company’s physical purchases and sales of these energy commodities and any related hedging activities that it undertakes, it is required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”).  See “−Other Federal Laws and Regulations Affecting the Company’s Industry−EP Act of 2005” and “−Other Federal Laws and Regulations Affecting the Company’s Industry−Derivatives Regulation.”  Should the Company violate the anti-market manipulation laws and regulations, it could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Other State and Local Regulation of Operations

The Company’s business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

Other Federal Laws and Regulations Affecting the Company’s Industry

The Energy Policy Act of 2005 (the “EP Act 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry.  Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision

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which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority.  The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1 million per day for violations of the NGA and $1 million per violation per day for violations of the Natural Gas Policy Act (“NGPA”).  The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce.  In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005.  Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.  The Company cannot predict the ultimate impact of these or the above regulatory changes to its natural gas operations.  The Company does not believe that it would be affected by any such FERC action materially differently than other upstream and midstream natural gas companies with whom it competes.

Pipeline Safety Regulations

Some of the Company’s pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, (“HLPSA”) with respect to crude oil and NGLs.  Both the NGPSA and the HLPSA have subsequently been amended legislatively and are implemented through regulations promulgated by the PHMSA (collectively, “Pipeline Safety Laws”).  These laws and regulations establish minimum safety requirements in the design, construction, operation and maintenance of certain natural gas, crude oil and NGL pipeline facilities, as well as requirements for inspections and pipeline integrity

For example, pipeline operators must implement integrity management programs, including frequent inspections and other measures to ensure pipeline safety in high-consequence areas (“HCAs”), such as:

 

perform ongoing assessments of pipeline integrity;

 

identify and characterize applicable threats to pipeline segments that could impact a HCA;

 

improve data collection, integration and analysis;

 

repair and remediate pipelines as necessary; and

 

implement preventive and mitigating actions.

The PHMSA has issued rules applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by its regulations.  Further regulatory changes have been directed by Congress in other areas where the PHMSA has yet to take final action, notably requirements for certain shut-off valves on transmission lines, mapping all HCAs, and shortening the deadline for accident and incident notifications.

Violations of the Pipeline Safety Laws are punishable by administrative civil penalties of $209,002 per violation per day, with a maximum of $2,090,022 for a series of violations.  The PHMSA may also issue corrective orders to pipeline operators to enforce compliance with the Pipeline Safety Laws.  In 2016, Congress amended the Pipeline Safety Laws to, among other things, grant the PHMSA authority to issue emergency orders requiring owners and operators of regulated pipeline facilities to address imminent hazards without prior notice or an opportunity for a hearing, as well as enhanced release reporting requirements.  Other changes related to integrity management programs and the creation of a working group to consider information-sharing for integrity risk analyses.  In April 2016, PHMSA published a notice of proposed rulemaking (“NPRM”), addressing natural gas transmission and gathering lines.  The proposed rule would, among other things, change integrity management requirements, expand assessment and repair requirements to pipelines in “moderate-consequence areas,” including areas of medium population density, and increase requirements for monitoring and inspection of pipeline segments not located in HCAs.  The NPRM would also require that records or other data relied on to determine operating pressures must be traceable, verifiable and complete.  Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities, could significantly increase the Company’s costs.  Failure to locate such records or verify maximum pressures could also result in the reduction of allowable operating pressures, which would reduce available capacity on the Company’s pipelines.  PHMSA, however, has yet to finalize this rulemaking, and the contents and timing of any final rule are uncertain.

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The federal Pipeline Safety Laws largely preempt state regulation of pipeline safety for interstate lines but most states are certified by the U.S. Department of Transportation to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines.  States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety.  State standards may include requirements for facility design and management in addition to requirements for pipelines.  The Company does not anticipate any significant difficulty in complying with applicable state laws and regulations.

The Company’s natural gas pipelines have inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.  The Company regularly reviews all existing and proposed pipeline safety requirements and works to incorporate the new requirements into procedures and budgets.  The Company expects to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations.  Costs may also be incurred if there were an accidental release of a commodity transported by the Company’s system, or if a regulatory inspection identified a deficiency in the Company’s required programs.

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.  For example, under a new OSHA standard limiting respirable silica exposure, the oil and gas industry must implement engineering controls and work practices to limit exposures below the new limits by June 2021.  Failure to comply with OSHA requirements can lead to the imposition of penalties.

Derivatives Regulation

Comprehensive financial reform legislation was signed into law by the President on July 21, 2010 (“Dodd-Frank Act”). The legislation called for the CFTC to regulate certain markets for derivative products, including over-the-counter derivatives. The CFTC has issued several new relevant regulations and other rulemakings are pending at the CFTC, the product of which would are rules that implement the mandates in the new legislation to cause significant portions of derivatives markets to clear through clearinghouses. While some of these rules have been finalized, some have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of covered contracts that a trader may own or control separately or in combination, net long or short. The final rules also contained limited exemptions from position limits which would be phased in over time for certain bona fide hedging transactions and positions. The CFTC’s original position limits rule was challenged in court by two industry associations and was vacated and remanded by a federal district court. However, the CFTC proposed and revised new rules in November 2013 and December 2016, respectively, that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC has sought comment on the position limits rule as reproposed, but these new position limit rules are not yet final and the impact of those provisions on the Company is uncertain at this time. The CFTC has withdrawn its appeal of the court order vacating the original position limits rule.

Pursuant to the Dodd-Frank Act, mandatory clearing is now required for all market participants, unless an exception is available.  The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing.  The CFTC has not yet required the clearing of any other classes of swaps, including physical commodity swaps, and the trade execution requirement does not apply to swaps not subject to a clearing mandate.  Although the Company expects to qualify for the end-user exception from the clearing requirement for its swaps entered into to hedge its commercial risks, the application of the mandatory clearing requirements to other market participants, such as swap dealers, along with changes to the markets for swaps as a result of the trade execution requirement, may change the cost and availability of the swaps the Company uses for hedging.  If any of the Company’s swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, the Company may be required to clear such transactions or execute them on a derivatives contract market or swap execution facility.  The ultimate effect of the proposed rules and any additional regulations on the Company’s business is uncertain.

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In December 2015, the CFTC issued final rules establishing minimum margin requirements for uncleared swaps for swap dealers and major swap participants.  The final rules do not impose margin requirements on commercial end users.  Although the Company expects to qualify for the end-user exception from the margin requirements for swaps entered into to hedge its commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps the Company uses for hedging.  If any of the Company’s swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce the Company’s liquidity and cash available for capital expenditures and could reduce its ability to manage commodity price volatility and the volatility in its cash flows.

Other rules, including the restrictions on proprietary trading adopted under Section 619 of the Dodd-Frank Act, also known as the Volcker Rule, may alter the business practices of some of the Company’s counterparties and in some cases may cause them to stop transacting in or making markets in derivatives.  Moreover, federal banking regulators are reevaluating the authorization under which banking entities subject to their authority may engage in physical commodities transactions.

Although the Company cannot predict the ultimate outcome of these rulemakings, new rules and regulations, to the extent applicable to the Company or its derivative counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments the Company uses to manage its financial and commercial risks related to fluctuations in commodity prices.  Additional effects of the new regulations, including increased regulatory reporting and recordkeeping costs, increased regulatory capital requirements for the Company’s counterparties, and market dislocations or disruptions, among other consequences, could have an adverse effect on the Company’s ability to hedge risks associated with its business.

The Company’s sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (“CEA”), as amended by the Dodd-Frank Act, and regulations promulgated thereunder by the CFTC and (ii) the Energy Independence and Security Act of 2007 (“EISA”) and regulations promulgated thereunder by the FTC.  The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract of sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations.  The CEA, as amended by the Dodd-Frank Act, also prohibits knowingly delivering or causing to be delivered false or misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity.  The FTC issued its Petroleum Market Manipulation Rule pursuant to EISA, which became effective in November 2009, which also prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products.  Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation and certain knowing or willful violations may also lead to a felony conviction.

Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, the FERC and the courts.  The Company cannot predict the ultimate impact these or the above laws and regulations may have on its crude oil and natural gas operations.  The Company does not believe it will be affected by any such action in a materially different way than its similarly situated competitors.

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, 2018, 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 2019 or that will otherwise have a material impact on its financial position, results of operations or cash flows.

Employees

As of December 31, 2018, the Company employed approximately 487 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, Suite 1700, Houston, Texas 77002.  The main telephone number is (281) 840-4000.

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Available Information

The Company’s internet website is www.rivieraresourcesinc.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 and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, 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.

The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding the Company at www.sec.gov.

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;

 

ability to comply with the covenants under the Credit Facilities;

 

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

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;

 

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;

 

activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas; 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,

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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 Credit Facilities 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 Parent entered into the Riviera 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, 2018.  As of December 31, 2018, total borrowings outstanding under the Riviera Credit Facility were $20 million and there was approximately $371 million of available borrowing capacity (which includes a $34 million reduction for outstanding letters of credit).  In connection with the Spin-off, Riviera assumed the obligations of the Parent under the Riviera Credit Facility on August 7. 2018.

Redeterminations of the borrowing base under the Riviera Credit Facility are based primarily on reserve reports using lender commodity price expectations at such time.  The borrowing base will be redetermined semi-annually, on April 1 and October 1.  There was no change to the borrowing base as a result of the October 2018 redetermination.  The next scheduled borrowing base redetermination will take place on April 1, 2019.  Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the Riviera Credit Facility exceeding the borrowing base, we will be required to prepay an amount equal to the excess.  We may not have the financial resources in the future to make such mandatory prepayments required under the Riviera Credit Facility, which could result in an event of default.

In addition, on August 10, 2018, Blue Mountain Midstream entered into the Blue Mountain Credit Facility with an initial borrowing commitment of $200 million.  The maximum commitment amount is $400 million after the Covenant Changeover Date, subject to obtaining commitments for any such increase.  The Covenant Changeover Date occurred February 8, 2019, increasing the current borrowing commitment of $200 million.  At February 28, 2019, total borrowings outstanding under the Blue Mountain Credit Facility were approximately $19 million and there was approximately $169 million of available borrowing capacity (which includes a $12 million reduction for outstanding letters of credit).  The Blue Mountain Credit Facility matures on August 10, 2023.

In the future, we may not be able to access adequate funding under our Credit Facilities 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 Riviera 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 the time of the next scheduled redetermination.  In such case, we would be required to repay any indebtedness in excess of the borrowing base.

The Credit Facilities also restrict 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 Credit Facilities 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 Credit Facilities, which could result in an event of default under the Credit Facilities that, if not cured or waived, would have a material adverse effect on our business and financial condition.

Under the Riviera Credit Facility, we are 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.  In addition, under the Blue Mountain Credit Facility, Blue Mountain Midstream is required to maintain (i) for certain periods, a ratio of consolidated total debt (subject to certain carve-outs) to the sum of (a) total debt (subject to certain carve-outs) and (b) consolidated owners’ equity interest in Blue Mountain Midstream and its subsidiaries of no greater than 0.35 to 1.00, and (ii) subject to satisfaction of certain conditions and for certain periods, (a) a ratio of consolidated EBITDA to consolidated interest expense no less than 2.50 to 1.00, (b) a ratio of consolidated net debt to consolidated EBITDA (the

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“consolidated total leverage ratio”) no greater than 4.50 to 1.00 or 5.00 to 1.00, as applicable, and (c) in case certain other kinds of debt are outstanding, a ratio of consolidated net debt secured by a lien on property of Blue Mountain Midstream to consolidated EBITDA no greater than 3.00 to 1.00.  If we were to violate any of the covenants under the Riviera Credit Facility or the Blue Mountain 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 Riviera Credit Facility or the Blue Mountain 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 Credit Facilities 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 Credit Facilities 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 Credit Facilities also require us to comply with certain financial maintenance covenants as discussed above.  A breach of any of these covenants could result in a default under the Credit Facilities.  If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under the Credit Facilities 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 Credit Facilities 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 applicable administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under the applicable 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 Credit Facilities.  The restrictions contained in the Credit Facilities 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.

We may be subject to risks in connection with divestitures.

In 2017 and 2018, we completed divestitures of a significant portion of our assets, as discussed in Item 1. “Business‒Recent Developments.”  In future transactions we may sell our core or non-core assets in order to increase capital resources available for other core assets, create organizational or other operational efficiencies or for other purposes.  Though we continue to evaluate various options for the divestiture of such assets, there is 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.

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Our financial information after the impact of fresh start accounting and numerous divestitures may not be meaningful to investors.

Upon LINN Energy’s emergence from bankruptcy in February 2017, the Company 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 and combined balance sheets.  As a result of the adoption of fresh start accounting, along with the numerous divestitures of properties in 2017 and 2018, our 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.

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, natural gas and NGLs, we have entered into commodity derivative contracts for a portion of our production and costs.  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 and purchased 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 and purchases for 2019 and 2020, our anticipated production and purchase 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 could 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 the Riviera 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.

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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 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 and midstream 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 and affect our future growth.

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 and to expand our midstream operations and activities.  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;

 

our ability to acquire, locate and produce new reserves;

 

the costs of constructing, operating and maintaining our midstream facilities; and

 

our ability to attract third-party customers for our midstream services.

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.

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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.

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.

Our business depends on gathering and transportation facilities, including our midstream facilities constructed and operated by Blue Mountain Midstream, and other market factors that we do not control.  Limitations on the availability to those facilities or adverse pricing differentials could adversely affect our business, results of operations and cash flows by interfering with our ability to consistently market oil, natural gas and NGL.

The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering systems and pipelines, including our midstream facilities constructed and operated by our wholly owned subsidiary, Blue Mountain Midstream.  Our development and maintenance of our midstream infrastructure can involve significant risks, including those relating to timing, cost overruns and operational efficiency that could, in turn, materially impact our production, cash flow and results of operation.  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

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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.

Additionally, certain of our contracts may provide for pricing at a market hub that is different than the delivery market hub where our oil, natural gas or NGL production is delivered and sold.  If the differential between the two pricing is hubs is unfavorable, it could adversely affect our business, results of operations or cash flows.

Our construction of Blue Mountain Midstream’s new natural gas gathering, processing and compression and water treatment or other assets, may not be completed on schedule, at the budgeted cost or at all, and they may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

The construction of additions or modifications to our existing systems and the construction or purchase of new assets, involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital.  Financing may not be available on economically acceptable terms or at all.  If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all.  Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project.

Moreover, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize.  As a result, new natural gas gathering, processing and compression and water treatment or other assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.  In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way prior to constructing new pipelines or facilities.  We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities.  Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way.  If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Blue Mountain Midstream’s natural gas gathering, processing and compression and water management services agreements are not supported by minimum volume commitments.

Blue Mountain Midstream’s natural gas gathering, processing and compression and water management services agreements with Roan are not supported by minimum volume commitments from Roan.  Any decrease in the current levels of throughput on Blue Mountain Midstream’s gathering, processing and compression or water management systems could adversely affect Blue Mountain Midstream’s business, results of operations and cash flows.

Because substantially all revenue in the Blue Mountain segment is derived from selling volumes purchased from Roan, any development that materially and adversely affects Roan’s operations, financial condition or market reputation could have a material and adverse impact on us.

Roan is the most significant counterparty for our wholly owned subsidiary, Blue Mountain Midstream, and selling volumes purchased from Roan accounted for substantially all the revenues for the Blue Mountain segment in 2018.  We expect Blue Mountain Midstream to derive a material portion of its revenues from selling volumes purchased from Roan for the foreseeable future.  As a result, any event, whether in our area of operations or otherwise, that adversely affects Roan’s production, drilling and completion schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect Blue Mountain Midstream’s business, results of operations and cash flows.

For example, Blue Mountain Midstream’s acreage dedication and commitments from Roan cover midstream and water management services in a number of areas that are at the early stages of development and in areas that Roan is still determining whether to develop.  In addition, Roan owns acreage in areas that are not dedicated to Blue Mountain Midstream.  We cannot predict which of these areas Roan will determine to develop and at what time.  Roan may decide to explore and develop areas in which Blue Mountain Midstream has a smaller operating interest in the midstream or water treatment assets that service that area, or where the acreage is not dedicated to Blue Mountain Midstream, rather than areas in which Blue Mountain Midstream has a larger operating interest in the midstream or water management assets that service that area.  Roan’s decision to develop acreage that is not dedicated to Blue Mountain Midstream or in which Blue Mountain

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Midstream has a smaller operating interest in may adversely affect our business, financial condition, results of operations and cash flows.

Further, Blue Mountain Midstream is subject to the risk of non-performance by Roan, with respect to our natural gas gathering, processing and compression and water management services agreements.  We cannot predict the extent to which Roan’s business would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on Roan’s ability to execute its drilling and development program or perform under our natural gas gathering, processing and compression and water management services agreements.  Any material non-performance by Roan could adversely affect the Blue Mountain segment’s business, results of operations and cash flows.

If Roan sells any of the dedicated acreage to a third party, the third party’s financial condition could be materially worse than Roan’s, and thus we could be subject to the non-payment or non-performance by the third party.

Under Blue Mountain Midstream’s natural gas dedication agreement with Roan, Roan is required to deliver its natural gas production from the specified contract area (the “dedicated acreage”) to Blue Mountain Midstream through November 2030.  If Roan sells any of the dedicated acreage to a third party, the third party’s financial condition could be materially worse than Roan’s.  In such a case, we may be subject to risks of loss resulting from non-payment or non-performance by the third party, which risks may increase during periods of economic uncertainty.  Furthermore, the third party may be subject to their own operating and regulatory risks, which could increase the risk that that third party may default on its obligations to Blue Mountain Midstream.  Any material non-payment or non-performance by the third party could adversely affect Blue Mountain Midstream’s business, results of operations and cash flows.

Blue Mountain Midstream may not be successful in balancing our purchases and sales and may be subject to adverse pricing differentials.

Blue Mountain Midstream is party to certain long-term gas, NGL and condensate sales commitments that it satisfies through supplies purchased under long-term gas and NGL purchase agreements.  Over time, the supplies that it has under contract may decline due to reduced drilling or other causes, and it risks losing offtake capacity.  In addition, a producer could fail to deliver expected volumes or deliver in excess of expected volumes.  Any of these actions could cause our purchases and sales not to be balanced.  Over time, the costs of covering those imbalances could affect Blue Mountain’s competitive position and its financial results.  If Blue Mountain Midstream’s purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

In addition, Blue Mountain Midstream has in the past experienced a negative impact on its financial results from the spread between the index price at which it is committed to purchase natural gas and associated natural gas liquids in production areas and the index price at which it can sell natural gas liquids into market areas.  Changes in this basis spread could significantly affect our margins or even result in losses.

We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.

We are subject to regulation by multiple federal, state and local governmental agencies.  Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts.  We cannot predict when or whether any such proposals or proceedings may become effective or the magnitude of the impact changes in laws and regulations may have on our business.  However, additions to the regulatory burden on our industry can increase our cost of doing business and affect our profitability.

If third party pipelines or other midstream facilities interconnected to our gathering and compression systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations and cash flows could be adversely affected.

Our gathering and compression assets connect to other pipelines or facilities owned and operated by unaffiliated third parties.  The continuing operation of third-party pipelines, compressor stations and other midstream facilities is not within our control.  These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.  In

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addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced.  If any such increase in costs occurs or if any of these pipelines or other midstream facilities become unable to receive or transport natural gas, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or midstream facilities, our business, financial condition, results of operations and cash flows could be adversely affected.

Our business relies on certain key personnel.

Our management believes that our continued success will depend to a significant extent upon the efforts and abilities of certain of our key personnel.  The loss of the services of any of these key personnel could have a material adverse effect on our business.  We do not maintain “key man” life insurance on any of our officers or other employees.

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, 2018, non-operated wells represented approximately 43% of our owned gross wells, or approximately 23% of our owned net wells.  We have limited ability to influence or control the operation or future development of these non-operated 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.

Our business could be adversely affected by security threats, including cyber-security threats, and related disruptions.

We face from time to time various security threats, including cyber-security threats, to gain unauthorized access to our sensitive information or to render our information or systems unusable, and threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as gathering and processing and other facilities, refineries and pipelines. These security threats subject our operations to increased risks that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our implementation of various procedures and controls to monitor and mitigate such security threats and to increase security for our information, systems, facilities and infrastructure may result in increased costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. We rely heavily on our information systems, and the availability and integrity of these systems are essential for us to conduct our business and operations. If any security breaches were to occur, they could lead to losses of, or damage to, sensitive information or facilities, infrastructure and systems essential to our business and operations, as well as data corruption, communication interruptions or other disruptions to our operations, which, in turn, could have a material adverse effect on our business, financial position, results of operations and cash flows.

Damage to our reputation could damage our business.

Our reputation is a critical factor in our relationships with employees, investors, customers, suppliers and joint venture partners.  If we fail to address, or appear to fail to address, issues that give rise to reputational risk, including those described throughout this “Risk Factors” section, we could significantly harm our reputation.  Our reputation may also be damaged by how we respond to corporate crises.  Corporate crises can arise from catastrophic events as well as from incidents involving unethical behavior or misconduct; allegations of legal noncompliance; internal control failures; corporate governance issues; data breaches; workplace safety incidents; environmental incidents; media statements; the conduct of our suppliers or representatives; and other issues or incidents that, whether actual or perceived, result in adverse publicity.  If we fail to respond quickly and effectively to address such crises, the ensuing negative public reaction could significantly harm our reputation and could lead to increases in litigation claims and asserted damages or subject us to regulatory actions or restrictions.

Damage to our reputation could negatively affect the demand for our services and consequently, have a material adverse effect on our business, financial condition, and results of operations.  It could also reduce investor confidence in us, adversely affecting our stock price.  Moreover, repairing our reputation may be difficult, time-consuming and expensive.

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Item 1A.Risk Factors - Continued

Risks Relating to Regulation of Our Business

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 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 fiscal year 2017-2019 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.

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Legislation and regulation of hydraulic fracturing, including with respect to seismic activity allegedly related to hydraulic fracturing and underground water injection or disposal wells, 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 . “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.

We dispose of wastewater generated from oil and natural gas production operations, including hydraulic fracturing operations, directly or through the use of third parties.  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 disposal 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.  For example, Oklahoma issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions, required additional seismicity protocols in certain defined areas, and from time to time, directs certain injection wells in proximity to seismic events to restrict or suspend operations.  Future orders or regulations addressing concerns about seismic activity from well injection could affect us, either directly or indirectly, depending on the wells affected, which materially affect our capital expenditures and operating costs.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of cash we have available for distribution.

With the exception of the Blue Mountain Delivery Line, which is subject to limited FERC regulation, our natural gas pipeline operations are generally exempt from FERC regulation under the NGA, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction.  However, the distinction between FERC-regulated interstate transportation services and federally unregulated gathering services has been the subject of litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress.  If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the NGPA.  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flow.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.  Under the EP Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

Even though we consider our natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services.  FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect gathering services.  In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines on which we ship

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natural gas.  However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level, therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services.  Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.  We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased operating costs depending on future legislative and regulatory changes.

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

Our assets and operations are subject to regulation and oversight by federal, state, provincial and local regulatory authorities.  Legislative changes, as well as regulatory actions taken by these agencies, have the potential to adversely affect our profitability.  In addition, a certain degree of regulatory uncertainty is created by the current U.S. presidential administration because it remains unclear specifically what the current administration may do with respect to future policies and regulations that may affect us.  Regulation affects almost every part of our business and extends to such matters as (i) federal, state, provincial and local taxation; (ii) rates (which include tax, reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the costs of raw materials, such as steel; (vii) the integrity, safety and security of facilities and operations; (viii) the acquisition of other businesses; (ix) the acquisition, extension, disposition or abandonment of services or facilities; (x) reporting and information posting requirements; (xi) the maintenance of accounts and records; and (xii) relationships with affiliated companies involved in various aspects of the energy businesses.  Should we fail to comply with any applicable statutes, rules, regulations, and orders of regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts.  Furthermore, new laws, regulations or policy changes sometimes arise from unexpected sources.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

The U.S. Department of Transportation, through the PHMSA and state agencies, enforces safety regulations with respect to the design, construction, operation, maintenance, inspection and management of certain of our pipeline facilities.  The PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas, or HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density.  The regulations require operators to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions.  These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies.  The PHMSA’s regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

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 Clean Air Act.  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.  

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However, in September 2018, under a new administration, the EPA proposed amendments that would relax requirements of these rules.  In addition, in April 2018, a coalition of states filed a lawsuit in federal district court aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending.  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.

On an international level, the U.S. was one of 175 countries to sign an international climate change agreement in Paris, France that requires member countries to set their own GHG emission reduction goals beginning in 2020 (the “Paris Agreement”).  However, on June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement.  It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement.  Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.  In addition, 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.

Any legislation or regulatory programs to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.  Moreover, incentives to conserve energy or use alternative energy sources as a means of addressing climate change could reduce demand for the oil and natural gas we produce.  In addition, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities.  Finally, most 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.  Even though monitored by management, our hedging activities may fail to protect us and could reduce our earnings and cash flow. Our hedging activity may be ineffective or adversely affect cash flow and earnings because, among other factors, hedging can be expensive, particularly during periods of volatile prices;  our counterparty in the hedging transaction may default on its obligation to pay or otherwise fail to perform; and  available hedges may not correspond directly with the risks against which we seek protection.

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.

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Item 1A.Risk Factors - Continued

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, 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, 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.

Risks Relating to Our Common Stock

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 Elliott Associates, L.P., Fir Tree Capital Management LP, York Capital Management, L.P. and P. Schoenfeld Asset Management LP collectively owned approximately 60% of our common stock as of December 31, 2018.  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 common stock.

Our significant concentration of share ownership may adversely affect the trading price of our common stock.

As of December 31, 2018, approximately 60% of our common stock was beneficially owned by four holders each of which has a representative on the Board.  Our significant concentration of share ownership may adversely affect the trading price of our common stock because of the lack of trading volume in our common 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 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 Riviera 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 common stock.

Certain provisions in our certificate of incorporation, bylaws and Delaware law may make it difficult for stockholders to change the composition of our Board of Directors and may prevent or delay an acquisition of Riviera, which could decrease the trading price of our common stock.

Our certificate of incorporation, bylaws and Delaware corporate law contain provisions that may have the effect of deterring or delaying coercive takeover practices and inadequate takeover bids.  For example, our certificate of incorporation and

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Item 2.

Properties - Continued

bylaws require advance notice for stockholder proposals to nominate directors or present matters at stockholder meetings, place limitations on convening stockholder meetings and authorize our board of directors to issue one or more series of preferred stock.  These provisions could enable our board of directors to delay or prevent a transaction that some, or a majority, of our 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

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 Credit Facilities are secured by mortgages on substantially all of the Company’s oil and natural gas properties.  See Note 6 for additional details about the Credit Facilities.

Offices

The Company’s principal corporate office is located at 600 Travis, Suite 1700, Houston, Texas 77002.  The Company maintains additional offices in Illinois, Kansas, Louisiana, Michigan, Oklahoma and Texas.

Item 3.

Legal Proceedings

As discussed further in Note 2, on May 11, 2016, Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo, LLC (collectively, the “LINN Debtors”) and Berry Petroleum Company, LLC (“Berry” and collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of the U.S. 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.

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 and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.

On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plan (the “Confirmation Order”).  Consummation of the Plan was subject to certain conditions set forth in the Plan.  On February 28, 2017, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms.  On September 27, 2018, the Bankruptcy Court closed the LINN Debtors’ Chapter 11 cases, but retained jurisdiction as provided in the Confirmation Order, including to potentially reopen the Chapter 11 cases if certain matters currently on appeal in the U.S. Court of Appeals for the Fifth Circuit are overturned, including the Default Interest Appeal as defined below.

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, which are not affected by the closure of the LINN Debtors’ Chapter 11 cases.

On March 17, 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor’s 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.  On November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest.  That ruling was appealed by Wells Fargo and on March 29, 2018, the U.S. District Court for the Southern District of Texas affirmed the Bankruptcy Court’s ruling.  On April 30, 2018, the Bankruptcy Court approved the substitution of UMB Bank, National Association (“UMB Bank”) as successor to Wells Fargo as

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administrative agent under the Predecessor’s credit facility.  UMB Bank then immediately filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit from the decision by the U.S. District Court for the Southern District of Texas, which affirmed the decision of the Bankruptcy Court.  The Fifth Circuit heard oral arguments on February 6, 2019.  That appeal (“the Default Interest Appeal”) remains 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

 

 

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Part II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Riviera’s common stock is quoted on the OTCQX Market under the trading symbol “RVRA” and has been trading since August 8, 2018. No established public trading market existed for the Company’s common stock prior to August 8, 2018. Over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

At the close of business on January 31, 2019, there were approximately 9 stockholders of record based on information provided by the Company’s transfer agent.

Dividends

The Company 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 Riviera Credit Facility.

The performance graph below compares the total stockholder return on Riviera’s common stock, with the total return of the Standard & Poor’s Oil & Gas Exploration & Production Index (“S&P Oil & Gas Index”), the Dow Jones U.S. Oil & Gas Index (“Dow Oil & Gas Index”), the Dow Jones U.S. Oil & Gas Producers Index (“Dow Oil & Gas Producers Index”) and the Standard & Poor’s 500 Index (the “S&P 500 Index”).  Total return includes the change in the market price, adjusted for reinvested dividends, for the period shown on the performance graph and assumes that $100 was invested in the Company on August 8, 2018, the date Riviera’s common stock began trading, and each comparative index on the same date.  The results shown in the graph below are not necessarily indicative of future performance.

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August 8,

2018

 

 

December 31, 2018

 

 

 

 

 

 

 

 

 

 

Riviera (RVRA)

 

$

100

 

 

$

68

 

S&P Oil & Gas Index (SPSIOP)

 

$

100

 

 

$

64

 

Dow Oil & Gas Index (DJUSEN)

 

$

100

 

 

$

75

 

Dow Oil & Gas Producers Index (DJUSOG)

 

$

100

 

 

$

78

 

S&P 500 Index (SPX)

 

$

100

 

 

$

88

 

 

Notwithstanding anything to the contrary set forth in any of the Company’s previous or future filings under the Securities Act of 1933, as amended or the Securities Exchange Act of 1934, as amended that might incorporate this Annual Report on Form 10-K or future filings with the SEC, in whole or in part, the preceding performance information shall be deemed furnished and shall neither be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

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

Issuer Purchases of Equity Securities

The Board has authorized the repurchase of up to $100 million of the Company’s outstanding shares of 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 shares of its common stock during the fourth quarter of 2018.

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

 

 

6,062,179

 

 

$

22.00

 

 

 

 

 

$

92,459

 

November 1– 30

 

 

233,450

 

 

$

20.28

 

 

 

233,450

 

 

$

87,725

 

December 1 – 31

 

 

357,873

 

 

$

16.47