10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the Quarterly Period Ended June 30, 2018

OR

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

For the transition period from _______________ to _______________

Commission File Number: 333-225927

Riviera Resources, Inc.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	82-5121920 (I.R.S. Employer Identification No.)
600 Travis Street Houston, Texas (Address of principal executive offices)	77002 (Zip Code)

(281) 840-4000

(Registrant’s telephone number, including area code)

Riviera Resources, LLC

(Former name, former address and former fiscal year, if changed since last report)

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 and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an 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	☐  (Do not check if a smaller reporting company)	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 Exchange Act).    Yes  ☐    No  ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 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 August 7, 2018, there were 76,190,908 shares of common stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS

		Page
	Glossary of Terms	1
	Part I – Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated and Combined Statements of Operations	3
	Condensed Consolidated Statement of Equity	5
	Condensed Consolidated and Combined Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	60
	Part II – Other Information
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	62
Item 6.	Exhibits	63
	Signatures	64

GLOSSARY OF TERMS

As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:

Bbl.  One stock tank barrel or 42 United States gallons liquid volume.

Btu.  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.

MBbls.  One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. MBbls per day.

Mcf.  One thousand cubic feet.

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.

NGL.  Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

1

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2018			December 31, 2017
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	301,365		$	464,477
Accounts receivable – trade, net		64,686			140,485
Derivative instruments		3,934			9,629
Restricted cash		43,387			56,445
Other current assets		45,760			76,683
Assets held for sale		22			106,963
Total current assets		459,154			854,682
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		785,815			950,083
Less accumulated depletion and amortization		(59,870	)		(49,619	)
		725,945			900,464
Other property and equipment		566,861			480,729
Less accumulated depreciation		(44,412	)		(28,658	)
		522,449			452,071
Derivative instruments		1,254			469
Deferred income taxes		169,645			188,538
Equity method investments		473,269			464,926
Other noncurrent assets		5,264			6,975
		649,432			660,908
Total noncurrent assets		1,897,826			2,013,443
Total assets	$	2,356,980		$	2,868,125
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	179,119		$	253,975
Share-based payment liability		111,792			—
Derivative instruments		5,536			10,103
Other accrued liabilities		19,807			58,130
Liabilities held for sale		—			43,302
Total current liabilities		316,254			365,510
Noncurrent liabilities:
Derivative instruments		24			2,849
Asset retirement obligations and other noncurrent liabilities		105,531			160,720
Total noncurrent liabilities		105,555			163,569
Commitments and contingencies (Note 11)
Equity:
Net parent company investment		1,935,171			2,339,046
Total equity		1,935,171			2,339,046
Total liabilities and equity	$	2,356,980		$	2,868,125

The accompanying notes are an integral part of these condensed consolidated and combined financial statements.

2

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Successor
	Three Months Ended June 30,
	2018			2017
	(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	87,004		$	243,167
Gains (losses) on oil and natural gas derivatives		(7,525	)		45,714
Marketing revenues		42,967			12,547
Other revenues		6,387			6,391
		128,833			307,819
Expenses:
Lease operating expenses		24,088			71,057
Transportation expenses		21,213			37,388
Marketing expenses		40,327			6,976
General and administrative expenses		92,395			34,260
Exploration costs		53			811
Depreciation, depletion and amortization		21,980			45,945
Taxes, other than income taxes		7,115			17,871
Gains on sale of assets and other, net		(101,777	)		(308,178	)
		105,394			(93,870	)
Other income and (expenses):
Interest expense, net of amounts capitalized		(584	)		(7,551	)
Earnings (losses) from equity method investments		(9,327	)		91
Other, net		538			(1,166	)
		(9,373	)		(8,626	)
Reorganization items, net		(1,259	)		(3,059	)
Income from continuing operations before income taxes		12,807			390,004
Income tax expense		5,610			161,544
Income from continuing operations		7,197			228,460
Income from discontinued operations, net of income taxes		—			5,302
Net income	$	7,197		$	233,762
Income per share:
Basic and diluted income from continuing operations per share	$	0.09		$	3.00
Basic and diluted income from discontinued operations per share	$	—		$	0.07
Basic and diluted net income per share	$	0.09		$	3.07
Basic and diluted weighted average shares outstanding		76,191			76,191

The accompanying notes are an integral part of these condensed consolidated and combined financial statements.

3

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(Unaudited)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands, except per share amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	223,880		$	323,492		$	188,885
Gains (losses) on oil and natural gas derivatives		(22,555	)		33,755			92,691
Marketing revenues		89,234			15,461			6,636
Other revenues		12,281			8,419			9,915
		302,840			381,127			298,127
Expenses:
Lease operating expenses		71,972			95,687			49,665
Transportation expenses		40,307			51,111			25,972
Marketing expenses		82,082			9,515			4,820
General and administrative expenses		137,174			44,668			71,745
Exploration costs		1,255			866			93
Depreciation, depletion and amortization		50,445			63,792			47,155
Taxes, other than income taxes		15,567			24,948			14,877
(Gains) losses on sale of assets and other, net		(207,852	)		(307,694	)		829
		190,950			(17,107	)		215,156
Other income and (expenses):
Interest expense, net of amounts capitalized		(988	)		(11,751	)		(16,725	)
Earnings from equity method investments		16,018			130			157
Other, net		368			(1,554	)		(149	)
		15,398			(13,175	)		(16,717	)
Reorganization items, net		(3,210	)		(5,624	)		2,521,137
Income from continuing operations before income taxes		124,078			379,435			2,587,391
Income tax expense (benefit)		45,942			157,098			(166	)
Income from continuing operations		78,136			222,337			2,587,557
Income (loss) from discontinued operations, net of income taxes		—			5,759			(548	)
Net income	$	78,136		$	228,096		$	2,587,009
Income (loss) per share:
Basic and diluted income from continuing operations     per share	$	1.03		$	2.91		$	33.96
Basic and diluted income (loss) from discontinued operations     per share	$	—		$	0.08		$	(0.01	)
Basic and diluted net income per share	$	1.03		$	2.99		$	33.95
Basic and diluted weighted average shares outstanding		76,191			76,191			76,191

The accompanying notes are an integral part of these condensed consolidated and combined financial statements.

4

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)

	Total Equity
	(in thousands)
December 31, 2017	$	2,339,046
Net income		78,136
Net transfers to parent		(482,011	)
June 30, 2018	$	1,935,171

The accompanying notes are an integral part of these condensed consolidated and combined financial statements.

5

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(Unaudited)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Cash flow from operating activities:
Net income	$	78,136		$	228,096		$	2,587,009
Adjustments to reconcile net income to net cash provided by    operating activities:
Loss from discontinued operations		—			(5,759	)		548
Depreciation, depletion and amortization		50,445			63,792			47,155
Deferred income taxes		46,077			134,698			(166	)
Total (gains) losses on derivatives, net		22,555			(33,755	)		(92,691	)
Cash settlements on derivatives		(25,037	)		7,929			(11,572	)
Share-based compensation expenses		66,374			19,599			50,255
Amortization and write-off of deferred financing fees		824			82			1,338
(Gains) losses on sale of assets and other, net		(224,091	)		(295,100	)		1,069
Reorganization items, net		—			—			(2,456,074	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		76,465			27,212			(7,216	)
(Increase) decrease in other assets		33,654			(3,642	)		528
Increase (decrease) in accounts payable and accrued expenses		(52,538	)		(95,320	)		20,949
Increase (decrease) in other liabilities		(15,815	)		22,421			2,801
Net cash provided by operating activities – continuing operations		57,049			70,253			143,933
Net cash provided by operating activities – discontinued operations		—			13,966			8,781
Net cash provided by operating activities		57,049			84,219			152,714
Cash flow from investing activities:
Development of oil and natural gas properties		(45,938	)		(61,534	)		(50,597	)
Purchases of other property and equipment		(87,377	)		(27,287	)		(7,409	)
Proceeds from sale of properties and equipment and other		369,489			697,829			(166	)
Net cash provided by (used in) investing activities – continuing    operations		236,174			609,008			(58,172	)
Net cash used in investing activities – discontinued operations		—			(1,645	)		(584	)
Net cash provided by (used in) investing activities		236,174			607,363			(58,756	)

6

RIVIERA RESOURCES, INC.

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS - Continued

(Unaudited)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Cash flow from financing activities:
Net transfers (to) from parent		(456,925	)		(458	)		636,000
Proceeds from borrowings		—			160,000			—
Repayments of debt		—			(876,570	)		(1,038,986	)
Payment to holders of claims under the Predecessor’s second lien notes		—			—			(30,000	)
Distributions to unitholders		(12,174	)		—			—
Other		(294	)		(3,060	)		(4,744	)
Net cash used in financing activities – continuing operations		(469,393	)		(720,088	)		(437,730	)
Net cash used in financing activities – discontinued operations		—			—			—
Net cash used in financing activities		(469,393	)		(720,088	)		(437,730	)
Net decrease in cash, cash equivalents and restricted cash		(176,170	)		(28,506	)		(343,772	)
Cash, cash equivalents and restricted cash:
Beginning		520,922			144,022			487,794
Ending	$	344,752		$	115,516		$	144,022

The accompanying notes are an integral part of these condensed consolidated and combined financial statements.

7

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Unless otherwise indicated or the context otherwise requires, references herein to the “Company” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (“Parent”) and its consolidated subsidiaries, and (ii) after 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.

In April 2018, the Parent announced its intention to separate Riviera from LINN Energy.  Following the Spin-off, Riviera is a new 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.

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 LINN Energy shareholders on a pro rata basis (the “Spin-off”).  Prior to the completion of the Spin-off, a then subsidiary of the Parent distributed $40 million to the Parent.  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 LINN Energy does not retain any ownership interest in Riviera. 

On August 7, 2018, Riviera entered into a Transition Services Agreement (the “TSA”) with the Parent to facilitate an orderly transition following the Spin-off, with a term to be determined based upon certain future specified events but to end no later than December 31, 2018.  Pursuant to the TSA, Riviera agreed to provide the Parent with certain finance, financial reporting, information technology, investor relations, legal, payroll, tax and other services. Riviera will reimburse the Parent for, or pay on the Parent’s behalf, all direct and indirect costs and expenses incurred by the Parent during the term of the agreement in connection with the fees for any such services. In addition, from time to time during the term of the agreement, Riviera and the Parent may mutually agree on additional services to be provided.

The accompanying condensed consolidated and combined financial statements have been prepared on a stand-alone basis and are derived from Linn Energy, Inc.’s consolidated financial statements and accounting records for the periods presented as the Company was historically managed as a subsidiary of Linn Energy, Inc.

During the reporting period, the Parent was a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo, LLC (collectively, the “LINN Debtors”) and Berry Petroleum Company, LLC (“Berry” and collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.  During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Nature of Business

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, North Louisiana, Michigan/Illinois, the Uinta Basin and the Mid-Continent. The Blue Mountain reporting segment consists of the Chisholm Trail gas plant system which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines 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.  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.  The Company has classified the assets and liabilities, results of operations and cash flows

8

of its California properties as discontinued operations on its consolidated and combined financial statements.  See Note 4 for additional information.

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 condensed consolidated financial statements.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s financial statements in periods subsequent to the Reorganization Date.

9

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Principles of Consolidation and Combination

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission rules and regulations; as such, this report should be read in conjunction with the financial statements and notes for the year ended December 31, 2017 included in the Company’s Registration Statement on Form S-1, as amended (File No. 333-225927).  The results reported in these unaudited condensed consolidated and combined financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated and combined financial statements for Predecessor periods represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under common control of the Parent, which exclude Linn Acquisition Company, LLC (“LAC”) and Berry.  On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as standalone unaffiliated entities.  The condensed consolidated financial statements for the Successor period represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under the control of the Parent.  The Company presents its condensed consolidated and combined financial statements in accordance with U.S. GAAP.  The condensed consolidated and combined financial statements include the accounts of the Company and its subsidiaries.  All significant intercompany transactions and balances have been eliminated. The condensed consolidated and combined financial statements were prepared on a carve-out basis and reflect significant assumptions and allocations.

Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.  See Note 6 for additional information about equity method investments.

Bankruptcy Accounting

Upon LINN Energy’s emergence from bankruptcy on February 28, 2017, the Parent adopted fresh start accounting which resulted in the Parent becoming a new entity for financial reporting purposes.  As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan (as defined in Note 2), the Company’s condensed consolidated financial statements subsequent to February 28, 2017, are not comparable to its condensed consolidated and combined financial statements prior to February 28, 2017.  References to “Successor” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017.  References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, February 28, 2017.  The Company’s condensed consolidated and combined financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017.  See Note 2 for additional information.

Use of Estimates

The preparation of the accompanying condensed consolidated and combined financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, and fair values of commodity derivatives.  In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are

10

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Adopted Accounting Standards

In November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows.  The Company adopted this ASU on January 1, 2018, on a retrospective basis.  The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows (see Note 16).

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers (“ASC 606”).  The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method.  Accordingly, the comparative information for the six months ended June 30, 2017, has not been adjusted and continues to be reported under the previous revenue standard.  The adoption of this ASU impacted the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3).

Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions.  All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.  For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company.  Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company.

In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no material impact on net income.

11

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The items discussed above impacted the Company’s reported “oil, natural gas and natural gas liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses” and “interest expense.”  The impact of adoption on the Company’s current period results is as follows:

	Three Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	53,662	$	53,285	$	377
Oil sales		10,919		10,919		—
NGL sales		22,423		22,280		143
Total oil, natural gas and NGL sales		87,004		86,484		520
Marketing revenues		42,967		25,406		17,561
Other revenues		6,387		6,003		384
		136,358		117,893		18,465
Expenses:
Transportation expenses		21,213		20,693		520
Marketing expenses		40,327		22,766		17,561
Interest expense		584		420		164
Net income	$	7,197	$	6,977	$	220

	Six Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	116,990	$	117,794	$	(804	)
Oil sales		56,615		56,615		—
NGL sales		50,275		50,222		53
Total oil, natural gas and NGL sales		223,880		224,631		(751	)
Marketing revenues		89,234		53,521		35,713
Other revenues		12,281		11,676		605
		325,395		289,828		35,567
Expenses:
Transportation expenses		40,307		41,058		(751	)
Marketing expenses		82,082		46,369		35,713
Interest expense		988		824		164
Net income	$	78,136	$	77,695	$	441

New Accounting Standards Issued But Not Yet Adopted

In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted).  The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures.  The Company expects the adoption of this ASU to impact its balance sheet resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

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RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting

On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.

On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Plan”).  The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.

On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”).  LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.

On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”).  On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.

Reorganization Items, Net

The Company incurred significant costs and recognized significant gains associated with the reorganization.  Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.  The following table summarizes the components of reorganization items included on the condensed consolidated and combined statements of operations:

	Successor
	Three Months Ended June 30,
	2018			2017
	(in thousands)
Legal and other professional fees	$	(1,255	)	$	(3,128	)
Other		(4	)		69
Reorganization items, net	$	(1,259	)	$	(3,059	)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	3,914,964
Recognition of an additional claim for the Predecessor’s second lien    notes settlement		—			—			(1,000,000	)
Fresh start valuation adjustments		—			—			(591,525	)
Income tax benefit related to implementation of the Plan		—			—			264,889
Legal and other professional fees		(3,207	)		(5,698	)		(46,961	)
Terminated contracts		—			—			(6,915	)
Other		(3	)		74			(13,315	)
Reorganization items, net	$	(3,210	)	$	(5,624	)	$	2,521,137

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RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Fresh Start Accounting

Upon LINN Energy’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”), which resulted in the Parent becoming a new entity for financial reporting purposes.  In accordance with ASC 852, the Parent was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the predecessor of the Parent (the “Predecessor”) received less than 50% of the voting shares of the successor of the Parent (the “Successor”) and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.

Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations.”  The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes.”  The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet.  The effects of the Plan and the application of fresh start accounting were reflected on the condensed consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the condensed consolidated statement of operations for the two months ended February 28, 2017.

Note 3 – Revenues

Revenue from Contracts with Customers

The Company recognizes sales of oil, natural gas and NGL when it satisfies a performance obligation by transferring control of the product to a customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for the product.

Natural Gas and NGL Sales

The Company’s natural gas production is primarily sold under 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.

For its natural gas contracts, the Company generally records its wet gas sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses, and its residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses.  All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.

Oil Sales

The Company’s oil production is primarily sold under 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.  For its oil contracts, the Company generally records its sales based on the net amount received.

Production Imbalances

The Company uses the sales method to account for natural gas production imbalances.  If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance.  No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Marketing Revenues

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements.  As such, the Company separately reports third-party marketing revenues and marketing expenses.

14

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Disaggregation of Revenue

The following tables present the Company’s disaggregated revenues by source and geographic area:

	Three Months Ended June 30, 2018
	Natural Gas		Oil		NGL			Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues		Total
	(in thousands)
Hugoton Basin	$	17,401	$	238	$	16,875		$	34,514	$	22,421	$	6,303	$	63,238
Mid-Continent		7,622		4,880		3,307			15,809		—		25		15,834
East Texas		12,661		1,091		1,013			14,765		467		3		15,235
Permian Basin		256		546		(488	)		314		—		16		330
Uinta Basin		2,146		1,885		1,201			5,232		—		1		5,233
North Louisiana		6,040		1,480		503			8,023		13		2		8,038
Michigan/Illinois		7,536		799		12			8,347		—		37		8,384
Blue Mountain		—		—		—			—		20,066		—		20,066
Total	$	53,662	$	10,919	$	22,423		$	87,004	$	42,967	$	6,387	$	136,358

	Six Months Ended June 30, 2018
	Natural Gas		Oil		NGL		Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues			Total
	(in thousands)
Hugoton Basin	$	39,764	$	2,970	$	36,389	$	79,123	$	46,501	$	12,134		$	137,758
Mid-Continent		15,555		16,747		6,361		38,663		—		39			38,702
East Texas		27,437		2,431		2,319		32,187		503		8			32,698
Permian Basin		2,282		20,654		2,557		25,493		—		32			25,525
Uinta Basin		5,526		9,255		2,559		17,340		—		(1	)		17,339
North Louisiana		12,418		3,049		67		15,534		272		3			15,809
Michigan/Illinois		14,008		1,509		23		15,540		—		66			15,606
Blue Mountain		—		—		—		—		41,958		—			41,958
Total	$	116,990	$	56,615	$	50,275	$	223,880	$	89,234	$	12,281		$	325,395

Contract Balances

Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to material contract assets or contract liabilities.

The Company had trade accounts receivable related to revenue from contracts with customers of approximately $56 million and $117 million as of June 30, 2018, and December 31, 2017, respectively.

Performance Obligations

The majority of the Company’s sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction

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RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Note 4 – Divestitures and Discontinued Operations

Divestitures – 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 $15 million, and the Company recognized a net gain of approximately $11 million.

On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $132 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 $107 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $55 million.

On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $112 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.

The divestitures discussed above are not presented as discontinued operations because they do not represent a strategic shift that will have a major effect on the Company’s operations and financial results.  The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations and were included in the upstream reporting segment.

The assets and liabilities associated with the Oklahoma and Texas Assets Sale were classified as “held for sale” on the condensed consolidated balance sheet at December 31, 2017.  At December 31, 2017, the Company’s condensed consolidated balance sheet included current assets of approximately $107 million included in “assets held for sale” and current liabilities of approximately $43 million included in “liabilities held for sale” related to this transaction.

16

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet:

	December 31, 2017
	(in thousands)
Assets:
Oil and natural gas properties	$	92,245
Other property and equipment		12,983
Other		1,735
Total assets held for sale	$	106,963
Liabilities:
Asset retirement obligations	$	42,001
Other		1,301
Total liabilities held for sale	$	43,302

Other assets primarily include inventories and other liabilities primarily include accounts payable.

Divestitures – 2017

On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. (the “Salt Creek Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $76 million and the Company recognized a net gain of approximately $33 million.

On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming to Jonah Energy LLC (the “Jonah Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $560 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $270 million.

The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations and were included in the upstream reporting segment.

Discontinued Operations

During 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California.  As a result of the Company’s strategic exit from California, the Company classified the results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements.  The California properties were included in the upstream reporting segment.

17

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations:

	Successor						Predecessor
	Three Months Ended June 30, 2017			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Revenues and other	$	20,511		$	27,636		$	14,891
Expenses		12,173			16,318			13,758
Other income and (expenses)		(2,074	)		(2,791	)		(1,681	)
Income (loss) from discontinued operations before income taxes		6,264			8,527			(548	)
Income tax expense		962			2,768			—
Income (loss) from discontinued operations, net of income taxes	$	5,302		$	5,759		$	(548	)

Other income and (expenses) include an allocation of interest expense for the California properties which represents interest on debt that was required to be repaid as a result of the sales.

Note 5 – Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	June 30, 2018			December 31, 2017
	(in thousands)
Proved properties	$	739,656		$	904,390
Unproved properties		46,159			45,693
		785,815			950,083
Less accumulated depletion and amortization		(59,870	)		(49,619	)
	$	725,945		$	900,464

Note 6 – Equity Method Investments

On August 31, 2017, the Parent, through certain of its then subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play.  In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan.  LINN Energy’s equity interest in Roan was historically held by a subsidiary of the Company.

The Company used the equity method of accounting for its investment in Roan.  The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets.  At both June 30, 2018, and December 31, 2017, the Company owned 50% of Roan’s outstanding units.

At June 30, 2018, the carrying amount of the Company’s investment in Roan of approximately $466 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $355 million.  The difference is attributable to proved and unproved oil and natural gas properties and is amortized over the lives of the related assets.  Such amortization

18

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

is included in the equity earnings (losses) from the Company’s investment in Roan.  At December 31, 2017, the carrying amount of the Company’s investment in Roan of approximately $458 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $346 million.

Impairment testing on the Company’s investment in Roan was performed when events or circumstances warranted such testing and considered whether there was an inability to recover the carrying value of the investment that was other than temporary.  No impairments occurred with respect to the Company’s investment in Roan for the six months ended June 30, 2018.

As discussed above, historically, a subsidiary of the Company owned the equity interest in Roan.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s consolidated financial statements in periods subsequent to the Reorganization Date.

Following are summarized statements of operations information for Roan.

Summarized Roan Resources LLC Statements of Operations Information

	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
	(in thousands)
Revenues and other	$	44,789		$	145,873
Expenses		72,754			130,663
Other income and (expenses)		(1,087	)		(2,886	)
Net income (loss)	$	(29,052	)	$	12,324

Note 7 – Debt

Credit Facility

On August 4, 2017, the Parent entered into a credit agreement with its then subsidiary Linn Energy Holdco II LLC (the “Borrower”), as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million.

On April 30, 2018, the Parent entered into an amendment to the Credit Facility (the “Credit Facility Amendment”) which, among other things, modified the borrowing base and maximum borrowing commitment amount to $425 million.

As of June 30, 2018, there were no borrowings outstanding under the Credit Facility and there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit).  The maturity date is August 4, 2020.  In connection with the Spin-off and as required by the Credit Facility Amendment, Riviera executed a Joinder Agreement on August 7, 2018, whereby it assumed the obligations of the Parent under the Credit Facility.  Following the Spin-off, the Borrower is a subsidiary of Riviera.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October.  At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base.  Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period.  The Company is required to pay a commitment fee to the lenders under the Credit Facility, which

19

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders.

The obligations under the Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of the oil and natural gas properties of the Company and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, and certain of its subsidiaries, subject to customary exceptions.  Under the Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0.

The Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates.

The Credit Facility contains events of default and remedies customary for credit facilities of this nature.  Failure to comply with the financial and other covenants in the Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Credit Facility.

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”), providing for an initial borrowing commitment of $200 million.

Available borrowing capacity under the Blue Mountain Credit Facility is, for certain periods, subject to Blue Mountain Midstream’s compliance with financial covenants, which may from time to time result in a reduction of Blue Mountain Midstream’s available borrowing capacity.  As of August 10, 2018, there were no borrowings outstanding under the Blue Mountain Credit Facility and the initial available borrowing capacity was $70 million.  The Blue Mountain Credit Facility matures on August 10, 2023.

At Blue Mountain Midstream’s election, interest on borrowings under the Blue Mountain Credit Facility is determined by reference to either the LIBOR plus an applicable margin ranging from 2.00% to 3.00% per annum or the ABR plus an applicable margin ranging from 1.00% to 2.00% per annum, both depending on Blue Mountain Midstream’s consolidated total leverage ratio.  Interest is generally payable in arrears on the last day of March, June, September and December for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of three month intervals during such interest period.

Blue Mountain Midstream is required under the Blue Mountain Credit Facility to pay a commitment fee to the lenders, which accrues at a rate per annum of 0.375% or 0.50% (depending on Blue Mountain Midstream’s consolidated total leverage ratio) on the average daily unused amount of the available revolving loan commitments of the lenders.

The Blue Mountain Credit Facility is secured by a first priority lien on substantially all the assets of Blue Mountain Midstream.  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 potential future 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 “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 indebtedness 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.

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RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The Blue Mountain Credit Facility also contains affirmative and negative covenants customary for credit facilities of this nature, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, budgets, maintenance and operation of property, restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets and transactions with affiliates.

The Blue Mountain Credit Facility contains events of default and remedies customary for credit facilities of this nature.  If Blue Mountain Midstream does not comply with the covenants in the Blue Mountain Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Blue Mountain Credit Facility.

Note 8 – Derivatives

Commodity Derivatives

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business.  The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production.  The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside.  The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received or paid.  The Company does not enter into derivative contracts for trading purposes.  The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.

The following table presents derivative positions for the periods indicated as of June 30, 2018:

	July 1 – December 31, 2018			2019
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)		35,144			22,265
Average price ($/MMBtu)	$	3.02		$	2.89
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)		276			183
Average price ($/Bbl)	$	54.07		$	64.00
Natural gas basis differential positions: (1)
PEPL basis swaps:
Hedged volume (MMMBtu)		7,360			14,600
Hedge differential	$	(0.67	)	$	(0.67	)
NGPL TXOK basis swaps:
Hedged volume (MMMBtu)		1,840			—
Hedge differential	$	(0.19	)	$	—

⁽¹⁾ Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

During the six months ended June 30, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019. During the four months ended June 30, 2017, the Company entered into commodity derivative contracts consisting of oil fixed price swaps for January 2018 through December 2018 and natural gas fixed price swaps for January 2018 through December 2019.  The Company did not enter into any commodity derivative contracts during the two months ended February 28, 2017.

In April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019.  The Company paid net cash settlements of approximately $20 million for the cancellations.

The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month.  The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following table summarizes the fair value of derivatives outstanding on a gross basis:

	June 30, 2018		December 31, 2017
	(in thousands)
Assets:
Commodity derivatives	$	6,825	$	22,589
Liabilities:
Commodity derivatives	$	7,197	$	25,443

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.  The Company’s counterparties are participants in the Credit Facility.  The Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral.  The Company does not receive collateral from its counterparties.

The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $7 million at June 30, 2018.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains and Losses on Derivatives

Gains and losses on derivatives were net losses of approximately $8 million and $23 million for the three months and six months ended June 30, 2018, respectively, and net gains of approximately $46 million and $34 million for the three months and four months ended June 30, 2017, respectively, and approximately $93 million for the two months ended February 28, 2017.  Gains and losses on derivatives are reported on the condensed consolidated and combined statements of operations in “gains (losses) on oil and natural gas derivatives.”

22

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The Company paid net cash settlements of approximately $21 million and $25 million for the three months and six months ended June 30, 2018, respectively.  The Company received net cash settlements of approximately $2 million and $8 million for the three months and four months ended June 30, 2017, respectively, and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017.

Note 9 – Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 8) on a recurring basis.  The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.  Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, are applied to the Company’s commodity derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments into a three-level fair value hierarchy based on the priority of inputs to the valuation technique.  The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	June 30, 2018
	Level 2		Netting (1)			Total
			(in thousands)
Assets:
Commodity derivatives	$	6,825	$	(1,637	)	$	5,188
Liabilities:
Commodity derivatives	$	7,197	$	(1,637	)	$	5,560

	December 31, 2017
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	22,589	$	(12,491	)	$	10,098
Liabilities:
Commodity derivatives	$	25,443	$	(12,491	)	$	12,952

⁽¹⁾ Represents counterparty netting under agreements governing such derivatives.

Note 10 – Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations.  Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred.  The liabilities are included in “other accrued liabilities” and “asset retirement obligations and other noncurrent liabilities” on the condensed consolidated balance sheets.  Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations.  The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted

23

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

risk-free interest rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

In addition, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation of certain of Blue Mountain Midstream’s assets.  In such cases, asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life.  Indeterminate asset retirement obligation costs associated with Blue Mountain Midstream will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2017	$	164,553
Liabilities added from drilling		53
Liabilities associated with assets divested		(62,195	)
Current year accretion expense		4,081
Settlements		(1,859	)
Revisions of estimates		2,386
Asset retirement obligations at June 30, 2018	$	107,019

Note 11 – Commitments and Contingencies

On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.  On January 27, 2017, the Bankruptcy Court entered the Confirmation Order.  Consummation of the Plan was subject to certain conditions set forth in the Plan.  On the Effective Date, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms.  The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates.  However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.

In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor’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 administrative agent under the Predecessor’s credit facility.  UMB Bank then immediately filed a notice of appeal to the United States 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.  That 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.

Except for in connection with its Chapter 11 proceedings, the Company made no significant payments to settle any legal, environmental or tax proceedings during the six months ended June 30, 2018, or June 30, 2017.  The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary.  Liabilities

24

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Note 12 – Equity

Shares Issued and Outstanding

As of August 7, 2018, upon completion of the Spin-off, there were 76,190,908 shares of Riviera’s common stock, par value $0.01 per share issued and outstanding.  An additional 522,329 unvested restricted stock units of Riviera (“Riviera RSUs”) were granted and outstanding under the Company’s Omnibus Incentive Plan.  Such unvested restricted stock units were originally granted as restricted stock units of the Parent (“LINN RSUs”) pursuant to the Linn Energy, Inc. 2017 Omnibus Plan (the “LINN Incentive Plan”), and in connection with the Spin-off, the holders of such LINN RSUs received one Riviera restricted stock unit in respect of each such outstanding LINN RSU.

Share Repurchase Program

On August 16, 2018, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock.

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 Credit Facility.

Note 13 – Share-Based Compensation

Riviera Omnibus Incentive Plan

The Company had no equity awards outstanding as of June 30, 2018.  In August 2018, the Company implemented the Riviera Resources, Inc. 2018 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) pursuant to which employees, consultants and non-employee directors of the Company and its affiliates are eligible to receive stock options, restricted stock, dividend equivalents, performance awards, other stock-based awards and other cash-based awards.

The Committee (as defined in the Omnibus Incentive Plan) has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award.  As of August 7, 2018, up to 3,433,499 shares of common stock were available for issuance under the Omnibus Incentive Plan.  If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of common stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan.  If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of common stock awarded under the Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the Omnibus Incentive Plan.  Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s shareholders.

25

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Pursuant to the Spin-off, on August 7, 2018, certain employees of the Company received 522,329 Riviera RSUs.  Such Riviera RSUs were originally granted as LINN RSUs pursuant to the LINN Incentive Plan and in connection with the Spin-off, the holders of such LINN RSUs received one Riviera RSU in respect of each such outstanding LINN RSU.

Accounting for LINN Energy’s Share-Based Compensation

The condensed consolidated and combined financial statements include 100% of the Parent’s employee-related expenses, as its personnel were employed by Riviera Operating, LLC, formerly known as Linn Operating, LLC (“Riviera Operating”), a subsidiary of the Parent that became a subsidiary of Riviera in connection with the Spin-off.  Compensation cost related to the grant of share-based awards has been recorded at the subsidiary level with a corresponding credit to liability or equity, representing the Parent’s capital contribution.

A summary of share-based compensation expenses included on the condensed consolidated and combined statements of operations is presented below:

	Three Months Ended June 30,
	2018		2017
	(in thousands)
General and administrative expenses	$	58,188	$	15,422
Income tax benefit	$	4,315	$	3,128

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
General and administrative expenses	$	75,225	$	19,599	$	50,255
Income tax benefit	$	6,732	$	3,555	$	5,170

During the six months ended June 30, 2018, the Parent granted to certain employees 12,500 LINN RSUs with an aggregate grant date fair value of approximately $519,000.  The LINN RSUs vest over three years.

Upon a participant’s termination of employment and/or service (as applicable), the Parent had the right (but not the obligation) to repurchase all or any portion of the shares of Class A common stock, par value $0.001 per share of Linn Energy, Inc. (“LINN Class A common stock”), acquired pursuant to an award at a price equal to the fair market value (as determined under the LINN Incentive Plan) of the shares of LINN Class A common stock to be repurchased, measured as of the date of the Parent’s repurchase notice.  During May 2018, the Parent began exercising its right to repurchase vesting awards under the LINN Incentive Plan, which modified all outstanding awards to liability classification.  For the six months ended June 30, 2018, the Parent repurchased 271,314 restricted stock units for a total cost of approximately $11 million pursuant to its right to repurchase vesting awards.  The Company has recognized a liability of approximately $112 million related to awards required to be liability classified, included in “share-based payment liability” on the condensed consolidated balance sheet and recorded incremental share-based compensation expense of approximately $18 million related to modifying the awards to liability classification.  At June 30, 2018, all outstanding share-based payment awards of the Parent are liability classified.

In April 2018, the Parent entered into agreements with each of its then serving executive officers, under which the Parent agreed, at the option of each officer, to repurchase certain of their LINN RSU awards and outstanding LINN Class A common stock.  Pursuant to those agreements, on August 7, 2018, the Parent repurchased an aggregate of 2,477,834 shares of LINN Class A common stock for a total cost of approximately $102 million.

26

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

In addition, in January 2018, the Parent’s board of directors’ compensation committee approved a one-time liquidity program under which the Parent agreed, at the option of the participant, to 1) settle all or a portion of an eligible participant’s LINN RSUs vesting on or before March 1, 2018, in cash and/or 2) repurchase all or a portion of any shares of LINN Class A common stock held by an eligible participant as a result of a prior vesting of restricted stock units, in each case at an agreed upon price (the “Liquidity Program”).  For the six months ended June 30, 2018, the Parent settled 1,028,875 restricted stock units in cash and repurchased 120,829 shares of LINN Class A common stock for approximately $45 million pursuant to the Liquidity Program.

On August 2, 2018, the Parent’s board of directors authorized the termination of the LINN Incentive Plan following the settlement of all outstanding LINN RSUs and restricted common stock of the Parent.  In addition, all remaining unvested LINN RSUs were vested upon the Spin-off, exclusive of the dividend of Riviera associated with each unvested restricted stock unit, which remain outstanding and unvested under the Company’s Omnibus Incentive Plan.

Note 14 – Earnings Per Share

On August 7, 2018, the Parent distributed 76,190,908 shares of Riviera common stock to LINN Energy shareholders.  LINN Energy did not retain any ownership in Riviera.  Each LINN Energy shareholder received one share of Riviera common stock for each share of LINN Class A common stock held by such LINN Energy shareholder at the close of business on August 7, 2018, the record date.

Basic and diluted earnings per share and the average number of shares outstanding were retrospectively restated for the number of shares of Riviera common stock outstanding immediately following this transaction.  The same number of shares was used to calculate basic and diluted earnings per share since there were no Riviera equity awards outstanding prior to the Spin-off.

The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share computations for net income:

	Successor
	Three Months Ended June 30,
	2018		2017
Income from continuing operations	$	7,197	$	228,460
Income from discontinued operations, net of income taxes		—		5,302
Net income	$	7,197	$	233,762
Basic and diluted income from continuing operations per share	$	0.09	$	3.00
Basic and diluted income from discontinued operations per share	$	—	$	0.07
Basic and diluted earnings per share	$	0.09	$	3.07
Basic and diluted weighted average number of common shares outstanding		76,191		76,191

27

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
Income from continuing operations	$	78,136	$	222,337	$	2,587,557
Income (loss) from discontinued operations, net of income taxes		—		5,759		(548	)
Net income	$	78,136	$	228,096	$	2,587,009
Basic and diluted income from continuing operations per share	$	1.03	$	2.91	$	33.96
Basic and diluted income (loss) from discontinued operations per share	$	—	$	0.08	$	(0.01	)
Basic and diluted earnings per share	$	1.03	$	2.99	$	33.95
Basic and diluted weighted average number of common shares outstanding		76,191		76,191		76,191

Note 15 – Income Taxes

Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations.  The effective income tax rates were approximately 44% and 37% for the three months and six months ended June 30, 2018, respectively, approximately 41% for both the three months and four months ended June 30, 2017, and zero for the two months ended February 28, 2017.  For the six months ended June 30, 2018, the Company’s federal and state statutory rate net of the federal tax benefit was approximately 24%.  The increase in the effective tax rate in excess of the statutory rate is primarily due to non-deductible executive compensation.

The Successor was formed as a C corporation.  For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders.  Limited liability companies are subject to Texas margin tax.  In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes.  As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.  The deferred tax effects of the Company’s change to a C corporation are included in income from continuing operations for the two months ended February 28, 2017.

Note 16 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows

“Other current assets” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Prepaids	$	13,310	$	43,150
Receivable from related party		25,982		23,163
Inventories		3,981		7,667
Other		2,487		2,703
Other current assets	$	45,760	$	76,683

28

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Accrued compensation	$	13,533	$	29,089
Asset retirement obligations (current portion)		1,488		3,926
Deposits		3,170		15,349
Income taxes payable		—		7,009
Other		1,616		2,757
Other accrued liabilities	$	19,807	$	58,130

The following table provides a reconciliation of “cash and cash equivalents” reported on the condensed consolidated balance sheets to “cash, cash equivalents and restricted cash” reported on the condensed consolidated statement of cash flows:

	June 30, 2018		December 31, 2017
	(in thousands)
Cash and cash equivalents	$	301,365	$	464,477
Restricted cash		43,387		56,445
Cash, cash equivalents and restricted cash	$	344,752	$	520,922

Supplemental disclosures to the condensed consolidated and combined statements of cash flows are presented below:

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Cash payments for interest, net of amounts capitalized	$	—	$	14,436	$	17,651
Cash payments for income taxes	$	—	$	215	$	—
Cash payments for reorganization items, net	$	2,911	$	5,982	$	21,571
Noncash investing activities:
Accrued capital expenditures	$	21,968	$	34,547	$	22,191

For purposes of the condensed consolidated and combined statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.  At June 30, 2018, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $33 million that will be used to settle certain claims in accordance with the Plan (which is the remainder of approximately $80 million transferred to restricted cash in February 2017 to fund such items), approximately $3 million related to deposits and approximately $7 million for other items.  At December 31, 2017, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $36 million that will be used to settle certain claims in accordance with the Plan, approximately $15 million related to deposits and approximately $5 million for other items.

29

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

Note 17 – Related Party Transactions

Roan Resources LLC

On August 31, 2017, the Parent completed the Roan Contribution.  In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan.  See Note 6 for additional information.  Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Riviera Operating, pursuant to which Riviera Operating agreed to provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period.

Under the MSA, Roan agreed to reimburse Riviera Operating for certain costs and expenses incurred by Riviera Operating in connection with providing the services, and to pay to Riviera Operating a service fee of $1.25 million per month, prorated for partial months.  The MSA terminated according to its terms on April 30, 2018.

In addition, the Company’s subsidiary, Blue Mountain Midstream has an agreement in place with Roan for the purchase and processing of natural gas from certain of Roan’s properties.

For the three months and six months ended June 30, 2018, the Company made natural gas purchases from Roan of approximately $15 million and $32 million, respectively, included in “marketing expenses” on the condensed consolidated statements of operations.  In addition, for the three months and six months ended June 30, 2018, the Company recognized service fees of approximately $1 million and $5 million, respectively, under the MSA, as a reduction to general and administrative expenses.  At June 30, 2018, the Company had approximately $26 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $11 million due to Roan, associated with natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.  At December 31, 2017, the Company had approximately $23 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $18 million due to Roan, primarily associated with joint interest billings and natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.

Note 18 – Segments

During the second quarter of 2018, the Company had two reporting segments: Upstream and Blue Mountain.  The upstream reporting segment was engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and consists of the Company’s properties in the Hugoton Basin, (including the Jayhawk natural gas processing plant, located in Kansas), East Texas, North Louisiana, Michigan/Illinois, the Uinta Basin and the Mid-Continent.  The Blue Mountain reporting segment is new for the second quarter of 2018 as a result of a change in the way the chief operating decision maker (“CODM”) assesses the Company’s results of operations following the hiring of a segment manager to lead the Blue Mountain reporting segment and the commissioning of the cryogenic natural gas processing facility during the second quarter of 2018.  The Blue Mountain reporting segment consists of the Chisholm Trail gas plant system, which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play.  To assess the performance of the Company’s reporting segments, the CODM analyzes field level cash flow.  The Company defines field level cash flow as revenues less direct operating expenses.  Other indirect income (expenses) include “general and administrative expenses,” “exploration costs,” “depreciation, depletion and amortization,” “gains on sale of assets and other, net,” “other income and (expenses)” and “reorganization items, net.”  Prior period amounts are presented on a comparable basis.  In addition, information regarding total assets by reporting segment is not presented because it is not reviewed by the CODM.

30

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

The following tables present the Company’s financial information by reporting segment:

	Successor
	Three Months Ended June 30, 2018
	Upstream		Blue Mountain			Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	87,004	$	—		$	—		$	87,004
Marketing revenues		22,901		20,066		—				42,967
Other revenues		6,387		—		—				6,387
		116,292		20,066			—			136,358
Lease operating expenses		24,088		—			—			24,088
Transportation expenses		21,213		—			—			21,213
Marketing expenses		20,244		20,083			—			40,327
Taxes other than income taxes		6,737		285			93			7,115
Total direct operating expenses		72,282		20,368			93			92,743
Field level cash flow	$	44,010	$	(302	)		(93	)		43,615
Losses on oil and natural gas derivatives							(7,525	)		(7,525	)
Other indirect income (expenses)							(23,283	)		(23,283	)
Income from continuing operations before income taxes									$	12,807

	Successor
	Three Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	243,167	—		$	—		$	243,167
Marketing revenues		10,793		1,754	—				12,547
Other revenues		6,391		—	—				6,391
		260,351		1,754		—			262,105
Lease operating expenses		71,057		—		—			71,057
Transportation expenses		37,388		—		—			37,388
Marketing expenses		6,156		820		—			6,976
Taxes other than income taxes		17,486		116		269			17,871
Total direct operating expenses		132,087		936		269			133,292
Field level cash flow	$	128,264	$	818		(269	)		128,813
Gains on oil and natural gas derivatives						45,714			45,714
Other indirect income (expenses)						215,477			215,477
Income from continuing operations before income taxes								$	390,004

31

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

	Successor
	Six Months Ended June 30, 2018
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	223,880	$	—	$	—		$	223,880
Marketing revenues		47,276		41,958	—				89,234
Other revenues		12,281		—	—				12,281
		283,437		41,958		—			325,395
Lease operating expenses		71,972		—		—			71,972
Transportation expenses		40,307		—		—			40,307
Marketing expenses		41,380		40,702		—			82,082
Taxes other than income taxes		14,908		477		182			15,567
Total direct operating expenses		168,567		41,179		182			209,928
Field level cash flow	$	114,870	$	779		(182	)		115,467
Losses on oil and natural gas derivatives						(22,555	)		(22,555	)
Other indirect income (expenses)						31,166			31,166
Income from continuing operations before income taxes								$	124,078

	Successor
	Four Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	323,492	—		$	—		$	323,492
Marketing revenues		13,273		2,188	—				15,461
Other revenues		8,419		—	—				8,419
		345,184		2,188		—			347,372
Lease operating expenses		95,687		—		—			95,687
Transportation expenses		51,111		—		—			51,111
Marketing expenses		8,513		1,002		—			9,515
Taxes other than income taxes		24,478		155		315			24,948
Total direct operating expenses		179,789		1,157		315			181,261
Field level cash flow	$	165,395	$	1,031		(315	)		166,111
Gains on oil and natural gas derivatives						33,755			33,755
Other indirect income (expenses)						179,569			179,569
Income from continuing operations before income taxes								$	379,435

32

RIVIERA RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS - Continued

(Unaudited)

	Predecessor
	Two Months Ended February 28, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	188,885	$	—	$	—		$	188,885
Marketing revenues		5,999		637	—				6,636
Other revenues		9,915		—	—				9,915
		204,799		637		—			205,436
Lease operating expenses		49,665		—		—			49,665
Transportation expenses		25,972		—		—			25,972
Marketing expenses		4,602		218		—			4,820
Taxes other than income taxes		14,773		78		26			14,877
Total direct operating expenses		95,012		296		26			95,334
Field level cash flow	$	109,787	$	341		(26	)		110,102
Gains on oil and natural gas derivatives						92,691			92,691
Other indirect income (expenses)						2,384,598			2,384,598
Income from continuing operations before income taxes								$	2,587,391

33

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s Registration Statement on Form S-1, as amended (File No. 333-225927) (the “Registration Statement”).  The following discussion contains forward-looking statements based on expectations, estimates and assumptions.  Actual results may differ materially from those discussed in the forward-looking statements.  Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” below and in the Registration Statement.

Unless otherwise indicated or the context otherwise requires, references herein to the “Company” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (“Parent”) and its consolidated subsidiaries, and (ii) after 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” herein refer to the Company in periods subsequent to LINN Energy’s emergence from bankruptcy and references to “Predecessor” herein refer to the Company in periods prior to LINN Energy’s emergence from bankruptcy.

In April 2018, the Parent announced its intention to separate Riviera from LINN Energy.  Following the Spin-off, Riviera is a new 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.

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 July 25, 2018 (the “Reorganization Date”).  Following the internal reorganization, the Parent distributed all of the outstanding shares of Riviera common stock to LINN Energy shareholders on a pro rata basis (the “Spin-off”).  Prior to the completion of the Spin-off, a then-subsidiary of the Parent distributed $40 million to the Parent.  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 LINN Energy does not retain any ownership interest in Riviera.

On August 7, 2018, Riviera entered into a Transition Services Agreement (the “TSA”) with the Parent to facilitate an orderly transition following the Spin-off, with a term to be determined based upon certain future specified events but to end no later than December 31, 2018.  Pursuant to the TSA, Riviera agreed to provide the Parent with certain finance, financial reporting, information technology, investor relations, legal, payroll, tax and other services. Riviera will reimburse the Parent for, or pay on the Parent’s behalf, all direct and indirect costs and expenses incurred by the Parent during the term of the agreement in connection with the fees for any such services. In addition, from time to time during the term of the agreement, Riviera and the Parent may mutually agree on additional services to be provided.

During the reporting period, the Parent was a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo, LLC (collectively, the “LINN Debtors”) and Berry Petroleum Company, LLC (“Berry” and collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.  During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.  LINN Energy emerged from bankruptcy effective February 28, 2017 (the “Effective Date”)

The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated and Combined Financial Statements contained in Item 1. “Financial Statements.”

Executive Overview

34

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

Prior to the Spin-off the Company was an indirect subsidiary of the Parent.  After the Spin-off, the Company’s upstream reporting segment properties are currently located in six operating regions in the United States (“U.S.”):

• Hugoton Basin, which includes oil and natural gas properties, as well as the Jayhawk natural gas processing plant, located in Kansas (the “Jayhawk Plant”);

• East Texas, which includes oil and natural gas properties producing primarily from the Cotton Valley and Bossier Sandstone;

• North Louisiana, which includes oil and natural gas properties producing primarily from the Cotton Valley Sandstones;

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

• Uinta Basin, which includes non-operated properties located in the Drunkards Wash field in Utah; and

• Mid-Continent, which includes properties in the Northwest STACK in northwestern Oklahoma, the Arkoma STACK located in southeastern Oklahoma, and various other oil and natural gas producing properties throughout Oklahoma.

The Blue Mountain reporting segment consists of the Chisholm Trail gas plant system, which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines 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.

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 and combined financial statements.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s financial statements in periods subsequent to the Reorganization Date.

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 during 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 condensed consolidated and combined financial statements.  See below and Note 4 for details of the Company’s divestitures.

For the three months ended June 30, 2018, the Company’s results included the following:

• oil, natural gas and NGL sales of approximately $87 million compared to $243 million for the three months ended June 30, 2017;

• average daily production of approximately 312 MMcfe/d compared to 710 MMcfe/d for the three months ended June 30, 2017;

• net income of approximately $7 million compared to $234 million for the three months ended June 30, 2017;

• capital expenditures of approximately $42 million compared to $96 million for the three months ended June 30, 2017; and

• 10 wells drilled (all successful) compared to 14 wells drilled (all successful) for the three months ended June 30, 2017.

For the six months ended June 30, 2018, the Company’s results included the following:

• oil, natural gas and NGL sales of approximately $224 million compared to $323 million and $189 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;

• average daily production of approximately 356 MMcfe/d compared to 722 MMcfe/d and 745 MMcfe/d for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;

• net income of approximately $78 million compared to $228 million and $2.6 billion for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;

• net cash provided by operating activities from continuing operations of $57 million compared to approximately $70 million and $144 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively;

• capital expenditures of approximately $109 million compared to $114 million and $46 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively; and

35

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

• 15 wells drilled (all successful) compared to 41 wells drilled (all successful) for the six months ended June 30, 2017.

Predecessor and Successor Reporting

As a result of the application of fresh start accounting (see Note 3), the Company’s condensed consolidated and combined financial statements and certain note presentations are separated into two distinct periods, the period before the Effective Date (labeled Predecessor) and the period after that date (labeled Successor), to indicate the application of a different basis of accounting between the periods presented.  Despite this separate presentation, there was continuity of the Company’s operations.

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 (the “New Mexico Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $15 million and the Company recognized a net gain of approximately $11 million.

On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $132 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 (the “West Texas Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $107 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $55 million.

On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $112 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.

Construction of Cryogenic Plant

In August 2018, the Company’s Board of Directors approved Blue Mountain Midstream’s plan to initiate the engineering and design of a second cryogenic natural gas processing plant servicing the Merge/SCOOP/STACK play in central Oklahoma.  The second plant would increase total processing capacity to 500 MMcf/d and has a target completion date in the second half of 2019.

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.  The facility was successfully commissioned in the second quarter of 2018.

2018 Oil and Natural Gas Capital Budget

For 2018, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $235 million, including approximately $75 million related to its oil and natural gas capital program and approximately $160 million related to Blue Mountain Midstream.  This estimate is under continuous review and subject to ongoing adjustments.

36

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

Financing Activities

Share Repurchase Program

On August 16, 2018, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock.

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”), providing for an initial borrowing commitment of $200 million.

Available borrowing capacity under the Blue Mountain Credit Facility is, for certain periods, subject to Blue Mountain Midstream’s compliance with financial covenants, which may from time to time result in a reduction of Blue Mountain Midstream’s available borrowing capacity.  As of August 10, 2018, there were no borrowings outstanding under the Blue Mountain Credit Facility and the initial available borrowing capacity was $70 million.  The Blue Mountain Credit Facility matures on August 10, 2023.  See Note 7 for additional details of the Blue Mountain Credit Facility.

Commodity Derivatives

During the six months ended June 30, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019.  In April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019.  The Company paid net cash settlements of approximately $20 million for the cancellations.

37

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

Results of Operations

Three Months Ended June 30, 2018, Compared to Three Months Ended June 30, 2017

	Successor
	Three Months Ended June 30,
	2018			2017			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	53,662		$	110,481		$	(56,819	)
Oil sales		10,919			89,237			(78,318	)
NGL sales		22,423			43,449			(21,026	)
Total oil, natural gas and NGL sales		87,004			243,167			(156,163	)
Gains (losses) on oil and natural gas derivatives		(7,525	)		45,714			(53,239	)
Marketing and other revenues		49,354			18,938			30,416
		128,833			307,819			(178,986	)
Expenses:
Lease operating expenses		24,088			71,057			(46,969	)
Transportation expenses		21,213			37,388			(16,175	)
Marketing expenses		40,327			6,976			33,351
General and administrative expenses (1)		92,395			34,260			58,135
Exploration costs		53			811			(758	)
Depreciation, depletion and amortization		21,980			45,945			(23,965	)
Taxes, other than income taxes		7,115			17,871			(10,756	)
Gains on sale of assets and other, net		(101,777	)		(308,178	)		206,401
		105,394			(93,870	)		199,264
Other income and (expenses)		(9,373	)		(8,626	)		(747	)
Reorganization items, net		(1,259	)		(3,059	)		1,800
Income from continuing operations before income taxes		12,807			390,004			(377,197	)
Income tax expense		5,610			161,544			(155,934	)
Income from continuing operations		7,197			228,460			(221,263	)
Income from discontinued operations, net of income taxes		—			5,302			(5,302	)
Net income	$	7,197		$	233,762		$	(226,565	)

⁽¹⁾ General and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $58 million and $15 million, respectively, of share-based compensation expenses.  In addition, general and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $14 million and $502,000, respectively of severance costs.

38

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

	Successor
	Three Months Ended June 30,
	2018		2017		Variance
Average daily production:
Natural gas (MMcf/d)		238		432		(45	%)
Oil (MBbls/d)		1.8		21.6		(92	%)
NGL (MBbls/d)		10.5		24.8		(58	%)
Total (MMcfe/d)		312		710		(56	%)
Average daily production – Equity method investments: (1)
Total (MMcfe/d)		109		—		(100	%)
Weighted average prices: (2)
Natural gas (Mcf)	$	2.48	$	2.81		(12	%)
Oil (Bbl)	$	66.66	$	45.42		47	%
NGL (Bbl)	$	23.43	$	19.29		21	%
Average NYMEX prices:
Natural gas (MMBtu)	$	2.80	$	3.18		(12	%)
Oil (Bbl)	$	67.88	$	48.28		41	%
Costs per Mcfe of production:
Lease operating expenses	$	0.85	$	1.10		(23	%)
Transportation expenses	$	0.75	$	0.58		29	%
General and administrative expenses (3)	$	3.26	$	0.53		515	%
Depreciation, depletion and amortization	$	0.77	$	0.71		8	%
Taxes, other than income taxes	$	0.25	$	0.28		(11	%)
Average daily production – discontinued operations:
Total (MMcfe/d)		—		29		(100	%)

⁽¹⁾ Represents the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-off.

⁽²⁾ Does not include the effect of gains (losses) on derivatives.

⁽³⁾ General and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $58 million and $15 million, respectively, of share-based compensation expenses.  In addition, general and administrative expenses for the three months ended June 30, 2018, and June 30, 2017, include approximately $14 million and $502,000, respectively of severance costs.

39

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

Upstream Reporting Segment

	Successor
	Three Months Ended June 30,
	2018		2017		Variance
	(in thousands)
Oil, natural gas and NGL sales	$	87,004	$	243,167	$	(156,163	)
Marketing and other revenues		29,288		17,184		12,104
		116,292		260,351		(144,059	)
Lease operating expenses		24,088		71,057		(46,969	)
Transportation expenses		21,213		37,388		(16,175	)
Marketing expenses		20,244		6,156		14,088
Severance taxes and ad valorem taxes		6,737		17,486		(10,749	)
Total direct operating expenses		72,282		132,087		(59,805	)
Field level cash flow (1)	$	44,010	$	128,264	$	(84,254	)

⁽¹⁾ Refer to Note 18 for a reconciliation of field level cash flow to income from continuing operations before income taxes.

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $156 million or 64% to approximately $87 million for the three months ended June 30, 2018, from approximately $243 million for the three months ended June 30, 2017, due to lower production volumes as a result of divestitures completed in 2017 and 2018.  Lower natural gas prices resulted in a decrease in revenues of approximately $7 million.  Higher NGL and oil prices resulted in an increase in revenues of approximately $4 million and $3 million, respectively.  In addition, revenues increased by approximately $1 million due to the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2017, revenue is recognized net of transportation expenses if the processor is the customer and there is no redelivery of commodities to the Company.  See Note 1 for additional details of the revenue accounting standard.

Average daily production volumes decreased to approximately 312 MMcfe/d for the three months ended June 30, 2018, from 710 MMcfe/d for the three months ended June 30, 2017.  Lower oil, natural gas and NGL production volumes resulted in a decrease in revenues of approximately $82 million, $50 million and $25 million, respectively.

The following table sets forth average daily production by region:

	Successor
	Three Months Ended June 30,
	2018		2017		Variance
Average daily production (MMcfe/d):
Hugoton Basin		136		164		(28	)	(18	%)
Mid-Continent		49		126		(77	)	(61	%)
East Texas		51		53		(2	)	(3	%)
Uinta Basin		22		244		(222	)	(91	%)
Michigan/Illinois		27		29		(2	)	(6	%)
North Louisiana		27		23		4		14	%
Permian Basin		—		46		(46	)	(100	%)
South Texas		—		25		(25	)	(100	%)
		312		710		(398	)	(56	%)
Equity method investments		109		—		109		100	%

The increase in average daily production volumes in the North Louisiana region primarily reflect increased development capital spending in the region.  The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Roan Contribution on August 31, 2017, partially offset by increased

40

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

development capital spending in the region.  The decreases in average daily production volumes in the Hugoton Basin, Uinta Basin, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017 and 2018.  See Note 4 for additional information of divestitures.  In addition, the decreases in average daily production volumes in these and the remaining regions reflect lower production volumes as a result of reduced development capital spending driven by continued low commodity prices.  Equity method investments represents the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-off.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities.  Other revenues primarily include helium sales revenue.  Marketing and other revenues increased by approximately $12 million or 70% to approximately $29 million for the three months ended June 30, 2018, from approximately $17 million for the three months ended June 30, 2017.  The increase was primarily due to higher revenues generated by the Jayhawk Plant, principally driven by a change in contract terms and the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses.  Lease operating expenses decreased by approximately $47 million or 66% to approximately $24 million for the three months ended June 30, 2018, from approximately $71 million for the three months ended June 30, 2017.  The decrease was primarily due to reduced labor costs for field operations as a result of cost savings initiatives and the divestitures completed in 2017 and 2018.  Lease operating expenses per Mcfe decreased to $0.85 per Mcfe for the three months ended June 30, 2018, from $1.10 per Mcfe for the three months ended June 30, 2017.

Transportation Expenses

Transportation expenses decreased by approximately $16 million or 43% to approximately $21 million for the three months ended June 30, 2018, from approximately $37 million for the three months ended June 30, 2017.  The decrease was due to reduced costs as a result of lower production volumes primarily as a result of the divestitures completed in 2017 and 2018, partially offset by the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2018, revenue is recognized net of transportation expenses if the processor is the customer and there is no redelivery of commodities to the Company.  See Note 1 for additional details of the revenue accounting standard.  Transportation expenses per Mcfe increased to $0.75 per Mcfe for the three months ended June 30, 2018, from $0.58 per Mcfe for the three months ended June 30, 2017.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities.  Marketing expenses increased by approximately $14 million to approximately $20 million for the three months ended June 30, 2018, from approximately $6 million for the three months ended June 30, 2017.  The increase was primarily due to higher expenses associated with the Jayhawk Plant, principally driven by a change in contract terms and the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

41

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

Severance and Ad Valorem Taxes

	Successor
	Three Months Ended June 30,
	2018		2017		Variance
	(in thousands)
Severance taxes	$	2,819	$	10,669	$	(7,850	)
Ad valorem taxes		3,918		6,817		(2,899	)
	$	6,737	$	17,486	$	(10,749	)

Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower production volumes.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to divestitures completed in 2017 and 2018 and lower estimated valuations on certain of the Company’s properties.

Field Level Cash Flow

Field level cash flow decreased by approximately $84 million or 66% to approximately $44 million for the three months ended June 30, 2018, from approximately $128 million for the three months ended June 30, 2017.  The decrease was primarily due to lower production revenues, partially offset by lower direct operating expenses.

Blue Mountain Reporting Segment

	Successor
	Three Months Ended June 30,
	2018			2017		Variance
	(in thousands)
Marketing revenues	$	20,066		$	1,754	$	18,312
Marketing expenses		20,083			820		19,263
Severance taxes and ad valorem taxes		285			116		169
Total direct operating expenses		20,368			936		19,432
Field level cash flow (1)	$	(302	)	$	818	$	(1,120	)

⁽¹⁾ Refer to Note 18 for a reconciliation of field level cash flow to income from continuing operations before income taxes.

Marketing Revenues

Marketing revenues increased by approximately $18 million to approximately $20 million for the three months ended June 30, 2018, from approximately $2 million for the three months ended June 30, 2017.  The increase was primarily due to the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018, and higher throughput volumes sold.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

Marketing Expenses

Marketing expenses increased by approximately $19 million to approximately $20 million for the three months ended June 30, 2018, from approximately $820,000 for the three months ended June 30, 2017.  The increase was primarily due to the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018, and higher throughput volumes purchased.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

42

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

Field Level Cash Flow

Field level cash flow decreased by approximately $1 million to negative cash flow of approximately $302,000 for the three months ended June 30, 2018, from positive cash flow of approximately $818,000 for the three months ended June 30, 2017.  The decrease was primarily due to widening pricing spreads between the Conway and Mont Belvieu market hubs.

Indirect Income and Expenses Not Allocated to Segments

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $8 million for the three months ended June 30, 2018, compared to gains of approximately $46 million for the three months ended June 30, 2017, representing a variance of approximately $54 million.  Gains and losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts.  The fair value on unsettled derivative contracts changes as future commodity price expectations change compared to the contract prices on the derivatives.  If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional details about the Company’s commodity derivatives.  For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees.  General and administrative expenses increased by approximately $58 million or 170% to approximately $92 million for the three months ended June 30, 2018, from approximately $34 million for the three months ended June 30, 2017.  The increase was primarily due to higher share-based compensation expenses, higher severance costs, and transition service fees received from Berry in the prior year, partially offset by lower salaries and benefits related expenses.  General and administrative expenses per Mcfe increased to $3.26 per Mcfe for the three months ended June 30, 2018, from $0.53 per Mcfe for the three months ended June 30, 2017.

For the professional services expenses related to the Chapter 11 proceedings, see “Reorganization Items, Net.”

Exploration Costs

Exploration costs decreased by approximately $758,000 to approximately $53,000 for the three months ended June 30, 2018, from approximately $811,000 for the three months ended June 30, 2017.  The decrease was primarily due to lower seismic data expenses.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $24 million or 52% to approximately $22 million for the three months ended June 30, 2018, from approximately $46 million for the three months ended June 30, 2017.  The decrease was primarily due to lower total production volumes.  Depreciation, depletion and amortization per Mcfe increased to $0.77 per Mcfe for the three months ended June 30, 2018, from $0.71 per Mcfe for the three months ended June 30, 2017.

Gains on Sale of Assets and Other, Net

During the three months ended June 30, 2018, the Company recorded the following net gains on divestitures (see Note 4):

• Net gain of approximately $11 million on the New Mexico Assets Sale; and

• Net gain of approximately $83 million, including costs to sell of approximately $2 million, on the Altamont Bluebell Assets Sale.

During the three months ended June 30, 2017, the Company recorded the following net gains on divestitures (see Note 4):

• Net gain of approximately $33 million on the Salt Creek Assets Sale; and

• Net gain of approximately $270 million, including costs to sell of approximately $6 million, on the Jonah Assets Sale.

43

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

Other Income and (Expenses)

	Successor
	Three Months Ended June 30,
	2018			2017			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(584	)	$	(7,551	)	$	6,967
Earnings (losses) from equity method investments		(9,327	)		91			(9,418	)
Other, net		538			(1,166	)		1,704
	$	(9,373	)	$	(8,626	)	$	(747	)

Interest expense decreased primarily due to no outstanding debt during 2018, and lower amortization of financing fees.  For the three months ended June 30, 2018, interest expense is primarily related to amortization of financing fees.  See “Debt” under “Liquidity and Capital Resources” below for additional details.

Equity method investments primarily include the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-off.  The Company’s equity earnings consists of its share of Roan’s earnings and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets.  As discussed above, historically, a subsidiary of the Company owned the equity interest in Roan.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer be affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s financial statements in periods subsequent to the Reorganization Date.  See Note 6 for additional information.

Reorganization Items, Net

The Company incurred significant costs and recognized significant gains associated with the reorganization.  Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.  The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:

	Successor
	Three Months Ended June 30,
	2018			2017
	(in thousands)
Legal and other professional fees	$	(1,255	)	$	(3,128	)
Other		(4	)		69
Reorganization items, net	$	(1,259	)	$	(3,059	)

Income Tax Expense

The Company recognized income tax expense of approximately $6 million and $162 million for the three months ended June 30, 2018, and June 30, 2017, respectively.  The decrease is primarily due to a decrease in taxable earnings and a decrease in the federal statutory income tax rate.

Income from Discontinued Operations, Net of Income Taxes

As a result of the Company’s strategic exit from California, the Company has classified the results of operations of its California properties as discontinued operations. Income from discontinued operations, net of income taxes was approximately $5 million for the three months ended June 30, 2017.  See Note 4 for additional information.

44

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

Net Income

Net income decreased by approximately $227 million to approximately $7 million for the three months ended June 30, 2018, from approximately $234 million the three months ended June 30, 2017.  The decrease was primarily due to lower gains on sales of assets, lower production revenue and losses compared to gains on commodity derivatives, partially offset by lower expenses during the three months ended June 30, 2018.  See discussion above for explanations of variances.

45

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

Results of Operations

The following table reflects the Company’s results of operations for each of the Successor and Predecessor periods presented:

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Revenues and other:
Natural gas sales	$	116,990		$	148,551		$	99,561
Oil sales		56,615			119,475			58,560
NGL sales		50,275			55,466			30,764
Total oil, natural gas and NGL sales		223,880			323,492			188,885
Gains (losses) on oil and natural gas derivatives		(22,555	)		33,755			92,691
Marketing and other revenues (1)		101,515			23,880			16,551
		302,840			381,127			298,127
Expenses:
Lease operating expenses		71,972			95,687			49,665
Transportation expenses		40,307			51,111			25,972
Marketing expenses		82,082			9,515			4,820
General and administrative expenses (2)		137,174			44,668			71,745
Exploration costs		1,255			866			93
Depreciation, depletion and amortization		50,445			63,792			47,155
Taxes, other than income taxes		15,567			24,948			14,877
(Gains) losses on sale of assets and other, net		(207,852	)		(307,694	)		829
		190,950			(17,107	)		215,156
Other income and (expenses)		15,398			(13,175	)		(16,717	)
Reorganization items, net		(3,210	)		(5,624	)		2,521,137
Income from continuing operations before income taxes		124,078			379,435			2,587,391
Income tax expense (benefit)		45,942			157,098			(166	)
Income from continuing operations		78,136			222,337			2,587,557
Income (loss) from discontinued operations, net of income taxes		—			5,759			(548	)
Net income	$	78,136		$	228,096		$	2,587,009

⁽¹⁾ Marketing and other revenues for the two months ended February 28, 2017, include approximately $6 million of management fee revenues recognized by the Company from Berry.  Management fee revenues are included in “other revenues” on the condensed consolidated statement of operations.

⁽²⁾ General and administrative expenses for the six months ended June 30, 2018, the four months ended June 30, 2017, and the two months ended February 28, 2017, include approximately $75 million, $20 million and $50 million, respectively, of share-based compensation expenses.  General and administrative expenses for the six months ended June 30, 2018, the four months ended June 30, 2017, and the two months ended February 28, 2017, also include approximately $18 million, $596,000 and $787,000, respectively, of severance costs.  In addition, general and administrative expenses for the two months ended February 28, 2017, 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.

46

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

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
Average daily production:
Natural gas (MMcf/d)		252		448		495
Oil (MBbls/d)		5.1		21.4		20.2
NGL (MBbls/d)		12.3		24.3		21.4
Total (MMcfe/d)		356		722		745
Average daily production – Equity method investments: (1)
Total (MMcfe/d)	111			—		—
Weighted average prices: (2)
Natural gas (Mcf)	$	2.57	$	2.72	$	3.41
Oil (Bbl)	$	61.07	$	45.79	$	49.16
NGL (Bbl)	$	22.56	$	18.68	$	24.37
Average NYMEX prices:
Natural gas (MMBtu)	$	2.90	$	3.05	$	3.66
Oil (Bbl)	$	65.37	$	48.63	$	53.04
Costs per Mcfe of production:
Lease operating expenses	$	1.12	$	1.09	$	1.13
Transportation expenses	$	0.62	$	0.58	$	0.59
General and administrative expenses (3)	$	2.13	$	0.51	$	1.63
Depreciation, depletion and amortization	$	0.78	$	0.72	$	1.07
Taxes, other than income taxes	$	0.24	$	0.28	$	0.34
Average daily production – discontinued operations:
Total (MMcfe/d)		—		29		30

⁽¹⁾ Represents the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-off.

⁽²⁾ Does not include the effect of gains (losses) on derivatives.

⁽³⁾ General and administrative expenses for the six months ended June 30, 2018, the four months ended June 30, 2017, and the two months ended February 28, 2017, include approximately $75 million, $20 million and $50 million, respectively, of share-based compensation expenses.  General and administrative expenses for the six months ended June 30, 2018, the four months ended June 30, 2017, and the two months ended February 28, 2017, also include approximately $18 million, $596,000 and $787,000, respectively, of severance costs.  In addition, general and administrative expenses for the two months ended February 28, 2017, 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.

47

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

Upstream Reporting Segment

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Oil, natural gas and NGL sales	$	223,880	$	323,492	$	188,885
Marketing and other revenues		59,557		21,692		15,914
		283,437		345,184		204,799
Lease operating expenses		71,972		95,687		49,665
Transportation expenses		40,307		51,111		25,972
Marketing expenses		41,380		8,513		4,602
Severance taxes and ad valorem taxes		14,908		24,478		14,773
Total direct operating expenses		168,567		179,789		95,012
Field level cash flow (1)	$	114,870	$	165,395	$	109,787

⁽¹⁾ Refer to Note 18 for a reconciliation of field level cash flow to income from continuing operations before income taxes.

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $288 million or 56% to approximately $224 million for the six months ended June 30, 2018, from approximately $323 million and $189 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively, due to lower production volumes as a result of divestitures completed in 2017 and 2018 partially offset by higher commodity prices.  Higher oil and NGL prices resulted in an increase in revenues of approximately $13 million and $5 million, respectively.  Lower natural gas prices resulted in a decrease in revenues of approximately $16 million.  In addition, revenues decreased by approximately $1 million due to the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2017, revenue is recognized net of transportation expenses if the processor is the customer and there is no redelivery of commodities to the Company.  See Note 1 for additional details of the revenue accounting standard.

Average daily production volumes decreased to approximately 356 MMcfe/d for the six months ended June 30, 2018, from approximately 722 MMcfe/d and 745 MMcfe/d for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  Lower oil, natural gas and NGL production volumes resulted in a decrease in revenues of approximately $135 million, $113 million and $41 million, respectively.

48

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

The following table sets forth average daily production by region:

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
Average daily production (MMcfe/d):
Hugoton Basin		146		165		158
Mid-Continent		53		126		110
East Texas		53		53		52
Uinta Basin		29		254		294
Michigan/Illinois		28		29		29
North Louisiana		27		24		28
Permian Basin		20		46		49
South Texas		—		25		25
		356		722		745
Equity method investments		111		—		—

The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Roan Contribution on August 31, 2017, partially offset by increased development capital spending in the region.  The decreases in average daily production volumes in the Hugoton Basin, Uinta Basin, Permian Basin and South Texas regions primarily reflect lower production volumes as a result of divestitures completed during 2017 and 2018.  See Note 4 for additional information of divestitures.  In addition, the decreases in average daily production volumes in these and the remaining regions reflect lower production volumes as a result of reduced development capital spending driven by continued low commodity prices.  Equity method investments represents the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-off.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities.  Other revenues primarily include management fee revenues recognized by the Company from Berry (in the Predecessor period) and helium sales revenue.  Marketing and other revenues increased by approximately $22 million or 58% to approximately $60 million for the six months ended June 30, 2018, from approximately $22 million and $16 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to higher revenues generated by the Jayhawk Plant, principally driven by a change in contract terms and the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018, partially offset by management fee revenues from Berry included in the Predecessor period.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses.  Lease operating expenses decreased by approximately $74 million or 50% to approximately $72 million for the six months ended June 30, 2018, from approximately $96 million and $50 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to reduced labor costs for field operations as a result of cost savings initiatives and the divestitures completed in 2017 and 2018.  Lease operating expenses per Mcfe were $1.12 per Mcfe for the six months ended June 30, 2018, compared to $1.09 per Mcfe and $1.13 per Mcfe for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.

Transportation Expenses

Transportation expenses decreased by approximately $37 million or 48% to approximately $40 million for the six months ended June 30, 2018, from approximately $51 million and $26 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was due to reduced costs as a result of lower production volumes primarily as a result of the divestitures completed in 2017 and 2018 and due to the impact of the new accounting

49

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

standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2018, revenue is recognized net of transportation expenses if the processor is the customer and there is no redelivery of commodities to the Company.  See Note 1 for additional details of the revenue accounting standard.  Transportation expenses per Mcfe increased to $0.62 per Mcfe for the six months ended June 30, 2018, from $0.58 per Mcfe and $0.59 per Mcfe for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities.  Marketing expenses increased by approximately $28 million to approximately $41 million for the six months ended June 30, 2018, from approximately $8 million and $5 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to higher expenses associated with the Jayhawk Plant, principally driven by a change in contract terms and the impact of the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.  See Note 1 for additional details of the revenue accounting standard.

Severance and Ad Valorem Taxes

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Severance taxes	$	7,143	$	14,532	$	9,107
Ad valorem taxes		7,765		9,946		5,666
	$	14,908	$	24,478	$	14,773

Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower production volumes.  Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to divestitures completed in 2017 and 2018 and lower estimated valuations on certain of the Company’s properties.

Field Level Cash Flow

Field level cash flow decreased by approximately $160 million to approximately $115 million for the six months ended June 30, 2018, from approximately $165 million and $110 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to lower production revenues, partially offset by lower direct operating expenses.

Blue Mountain Reporting Segment

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Marketing revenues	$	41,958	$	2,188	$	637
Marketing expenses		40,702		1,002		218
Severance taxes and ad valorem taxes		477		155		78
Total direct operating expenses		41,179		1,157		296
Field level cash flow (1)	$	779	$	1,031	$	341

⁽¹⁾ Refer to Note 18 for a reconciliation of field level cash flow to income from continuing operations before income taxes.

50

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

Marketing Revenues

Marketing revenues increased by approximately $39 million to approximately $42 million for the six months ended June 30, 2018, from approximately $2 million and $637,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018, and higher throughput volumes sold.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.

Marketing Expenses

Marketing expenses increased by approximately $39 million to approximately $41 million for the six months ended June 30, 2018, from approximately $1 million and $218,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to the new accounting standard related to revenues from contracts with customers, adopted on January 1, 2018, and higher throughput volumes sold.  As of January 1, 2018, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no impact on net income.

Field Level Cash Flow

Field level cash flow decreased by approximately $593,000 to approximately $779,000 for the six months ended June 30, 2018, from approximately $1 million and $341,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to widening pricing spreads between the Conway and Mont Belvieu market hubs.

Indirect Income and Expenses Not Allocated to Segments

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $23 million for the six months ended June 30, 2018, compared to gains of approximately $34 million and $93 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively, representing a variance of approximately $150 million.  Gains and losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts.  The fair value on unsettled derivative contracts changes as future commodity price expectations change compared to the contract prices on the derivatives.  If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 8 and Note 9 for additional details about the Company’s commodity derivatives.  For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees.  In addition, general and administrative expenses in the Predecessor period includes costs incurred by LINN Energy associated with the operations of Berry.  General and administrative expenses increased by approximately $20 million or 18% to approximately $137 million for the six months ended June 30, 2018, from approximately $45 million and $72 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to higher severance costs, transition service fees received from Berry in the prior year, and higher share-based compensation expenses partially offset by lower salaries and benefits related expenses.  General and administrative expenses per Mcfe increased to $2.13 per Mcfe for the six months ended June 30, 2018, from $0.51 per Mcfe and $1.63 per Mcfe for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.

For professional services expenses related to the Chapter 11 proceedings, see “Reorganization Items, Net.”

51

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

Exploration Costs

Exploration costs increased by approximately $296,000 to approximately $1 million for the six months ended June 30, 2018, from approximately $866,000 and $93,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The increase was primarily due to higher seismic data expenses during the first quarter of 2018.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $61 million or 55% to approximately $50 million for the six months ended June 30, 2018, from approximately $64 million and $47 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to lower rates as a result of the application of fresh start accounting, as well as lower total production volumes.  Depreciation, depletion and amortization per Mcfe was $0.78 per Mcfe for the six months ended June 30, 2018, compared to $0.72 per Mcfe and $1.07 per Mcfe for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.

(Gains) Losses on Sale of Assets and Other, Net

During the six months ended June 30, 2018, the Company recorded the following amounts related to divestitures (see Note 4):

• Net gain of approximately $11 million on the New Mexico Assets Sale;

• Net gain of approximately $83 million, including costs to sell of approximately $2 million, on the Altamont Bluebell Assets Sale;

• Net gain of approximately $55 million, including costs to sell of approximately $2 million, on the West Texas Assets Sale; and

• Net gain of approximately $46 million, including costs to sell of approximately $1 million, on the Oklahoma and Texas Assets Sale.

During the four months ended June 30, 2017, the Company recorded the following net gains on divestitures (see Note 4):

• Net gain of approximately $33 million on the Salt Creek Assets Sale; and

• Net gain of approximately $270 million, including costs to sell of approximately $6 million, on the Jonah Assets Sale.

Other Income and (Expenses)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Interest expense, net of amounts capitalized	$	(988	)	$	(11,751	)	$	(16,725	)
Earnings from equity method investments		16,018			130			157
Other, net		368			(1,554	)		(149	)
	$	15,398		$	(13,175	)	$	(16,717	)

Interest expense decreased primarily due to no outstanding debt during 2018, and lower amortization of financing fees.  For the two months ended February 28, 2017, contractual interest, which was not recorded, on the Predecessor’s senior notes was approximately $37 million.  For the six months ended June 30, 2018, interest expense is related primarily to amortization of financing fees.  See “Debt” under “Liquidity and Capital Resources” below for additional details.

Equity method investments primarily include the Company’s historical 50% equity interest in Roan, which was retained by the Parent following the Spin-ff.  The Company’s equity earnings consists of its share of Roan’s earnings and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets.  As discussed above, historically, a subsidiary of the Company owned the equity interest in Roan.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer be affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s financial statements in periods subsequent to the Reorganization Date.  See Note 6 for additional information.

52

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

Reorganization Items, Net

The Company incurred significant costs and recognized significant gains associated with the reorganization.  Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.  The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations:

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	3,914,964
Recognition of an additional claim for the Predecessor’s second lien    notes settlement		—			—			(1,000,000	)
Fresh start valuation adjustments		—			—			(591,525	)
Income tax benefit related to implementation of the Plan		—			—			264,889
Legal and other professional fees		(3,207	)		(5,698	)		(46,961	)
Terminated contracts		—			—			(6,915	)
Other		(3	)		74			(13,315	)
Reorganization items, net	$	(3,210	)	$	(5,624	)	$	2,521,137

Income Tax Expense (Benefit)

The Successor was formed as a C corporation.  For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders.  Limited liability companies are subject to Texas margin tax.  In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes.  The Company recognized income tax expense of approximately $46 million for the six months ended June 30, 2018, compared to income tax expense of approximately $157 million and an income tax benefit of approximately $166,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease is primarily due to a decrease in taxable earnings and a decrease in the federal statutory income tax rate.

Income (loss) from Discontinued Operations, Net of Income Taxes

As a result of the Company’s strategic exit from California, the Company has classified the results of operations of its California properties as discontinued operations.  Income from discontinued operations, net of income taxes was approximately $6 million and a loss of $548,000 for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  See Note 4 for additional information.

Net Income

Net income decreased by approximately $2.7 billion to approximately $78 million for the six months ended June 30, 2018, from a net income of approximately $228 million and $2.6 billion for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to gains included in reorganization items in the Predecessor period, lower production revenue, losses compared to gains on commodity derivatives and lower gains on sales of assets, partially offset by lower expenses.  See discussion above for explanations of variances.

Liquidity and Capital Resources

The Company’s sources of cash have primarily consisted of proceeds from its divestitures of oil and natural gas properties and net cash provided by operating activities.  As a result of divesting certain oil and natural gas properties during the six months ended June 30, 2018, the Company received approximately $368 million in net cash proceeds.  The Company has also used its cash to fund capital expenditures, principally for the development of its oil and natural gas properties, and plant

53

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

and pipeline construction, as well as the Parent’s repurchases of LINN Energy, Inc. Class A common stock prior to the Spin-off. Based on current expectations, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations.

See below for details regarding capital expenditures for the periods presented:

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Oil and natural gas	$	17,231	$	87,632	$	39,409
Plant and pipeline		91,125		22,724		4,990
Other		598		3,919		1,243
Capital expenditures, excluding acquisitions	$	108,954	$	114,275	$	45,642
Capital expenditures, excluding acquisitions – discontinued operations	$	—	$	1,790	$	436

The decrease in capital expenditures was primarily due to lower oil and natural gas development activities, partially offset by higher plant and pipeline construction activities associated with Blue Mountain Midstream.  For 2018, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $235 million, including approximately $75 million related to its oil and natural gas capital program and approximately $160 million related to Blue Mountain Midstream.  This estimate is under continuous review and subject to ongoing adjustments.

Statements of Cash Flows

The following is a comparative cash flow summary:

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Net cash:
Provided by operating activities	$	57,049		$	84,219		$	152,714
Provided by (used in) investing activities		236,174			607,363			(58,756	)
Used in financing activities		(469,393	)		(720,088	)		(437,730	)
Net decrease in cash, cash equivalents and restricted cash	$	(176,170	)	$	(28,506	)	$	(343,772	)

Operating Activities

Cash provided by operating activities was approximately $57 million for the six months ended June 30, 2018, compared to approximately $84 million and $153 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  The decrease was primarily due to lower production related revenues principally due to lower production volumes.

54

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

Investing Activities

The following provides a comparative summary of cash flow from investing activities:

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Cash flow from investing activities:
Capital expenditures	$	(133,315	)	$	(88,821	)	$	(58,006	)
Proceeds from sale of properties and equipment and other		369,489			697,829			(166	)
Net cash provided by (used in) investing activities –    continuing operations		236,174			609,008			(58,172	)
Net cash used in investing activities – discontinued operations		—			(1,645	)		(584	)
Net cash provided by (used in) investing activities	$	236,174		$	607,363		$	(58,756	)

The primary use of cash in investing activities is for the development of the Company’s oil and natural gas properties and construction of Blue Mountain Midstream’s cryogenic natural gas processing facility.  Capital expenditures decreased primarily due to lower oil and natural gas capital spending, partially offset by higher spending on plant and pipeline construction related to Blue Mountain Midstream.  The Company made no material acquisitions of properties during the six months ended June 30, 2018, or June 30, 2017.  The Company has classified the cash flows of its California properties as discontinued operations.

Proceeds from sale of properties and equipment and other for the six months ended June 30, 2018, include cash proceeds received of approximately $109 million from the West Texas Assets Sale, approximately $101 million (excluding a deposit of approximately $12 million received in 2017) from the Oklahoma and Texas Assets Sale, approximately $134 million related to the Altamont Bluebell Assets Sale approximately $15 million related to and the New Mexico Assets Sale.  Proceeds from sale of properties and equipment and other for the four months ended June 30, 2017, include approximately $76 million in net cash proceeds received from the Salt Creek Assets Sale in June 2017 and approximately $560 million in net cash proceeds received from the Jonah Assets Sale in May 2017 and deposits received of approximately $57 million associated with divestitures completed during the third quarter of 2017.  See Note 4 for additional details of divestitures.

Financing Activities

Cash used in financing activities was approximately $469 million for the six months ended June 30, 2018, compared to approximately $720 million and $438 million for the four months ended June 30, 2017, and the two months ended February 28, 2017, respectively.  During the six months ended June 30, 2018, the primary use of cash in financing activities was for repurchases of LINN Energy’s common stock and settlement of restricted stock units (see Note 13).  During the four months ended June 30, 2017, and the two months ended February 28, 2017, the primary use of cash in financing activities was for repayments of debt.

55

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

The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Successor			Predecessor
	Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Proceeds from borrowings:
Successor’s previous credit facility	$	160,000		$	—
	$	160,000		$	—
Repayments of debt:
Successor’s previous credit facility	$	(576,570	)	$	—
Successor term loan		(300,000	)		—
Predecessor’s credit facility		—			(1,038,986	)
	$	(876,570	)	$	(1,038,986	)

On February 28, 2017, the Company canceled its obligations under the Predecessor’s credit facility and entered into the Successor’s previous credit facility, which was a net transaction and is reflected as such on the condensed consolidated and combined statement of cash flows.  In addition, in February 2017, the Company made a $30 million payment to holders of claims under the Predecessor’s second lien notes, and also issued 41,359,806 shares of LINN Energy Inc. Class A common stock to participants in the rights offerings extended by the Company to certain holders of claims arising under the Predecessor’s second lien notes and senior notes for net proceeds of approximately $514 million.

Debt

There were no borrowings outstanding under the Credit Facility as of June 30, 2018, or December 31, 2017.  As of June 30, 2018, there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit).

For additional information related to the Company’s debt, see Note 7.

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value.  The Company’s counterparties are participants in the Credit Facility.  The Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral.  The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Dividends

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 Credit Facility.

Contingencies

See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.

56

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

Off-Balance Sheet Arrangements

The Company enters into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit.  In addition, the Company enters into other contractual agreements in the normal course of business for processing and transportation as well as for other oil and natural gas activities.  Other than the items discussed above, there are no other arrangements, transactions or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or capital resource positions.

Commitments and Contractual Obligations

The Company has asset retirement obligations, capital commitments, operating leases and commodity derivative liabilities that were summarized in the table of commitments and contractual obligations in the Registration Statement.  During the six months ended June 30, 2018, the Company paid approximately $30 million of its capital commitments.  

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based on the condensed consolidated and combined financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles.  The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control.  These statements may include discussions about the Company’s:

• ability to realize the anticipated benefits of the Spin-off;

• the potential negative effects of the Spin-off;

• business strategy;

• acquisition and disposition strategy;

• financial strategy;

• ability to comply with the covenants with the Credit Facility and the Blue Mountain Credit Facility;

• effects of legal proceedings;

• drilling locations;

• oil, natural gas and NGL reserves;

• realized oil, natural gas and NGL prices;

• production volumes;

• capital expenditures;

• economic and competitive advantages;

• credit and capital market conditions;

• regulatory changes;

• lease operating expenses, general and administrative expenses and development costs;

• future operating results;

• plans, objectives, expectations and intentions; and

• taxes.

57

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

All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements.  These forward-looking statements may be found in Item 2.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management.  These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors.  Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control.  In addition, management’s assumptions may prove to be inaccurate.  The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur.  Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth under the caption “Risk Factors” in the Registration Statement and elsewhere in the Registration Statement.  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.

58

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risk is attributable to fluctuations in commodity prices.  This risk can affect the Company’s business, financial condition, operating results and cash flows.  See below for quantitative and qualitative information about this risk.

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Registration Statement.  The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated and Combined Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

The Company’s most significant market risk relates to prices of oil, natural gas and NGL.  The Company expects commodity prices to remain volatile and unpredictable.  As commodity prices decline or rise significantly, revenues and cash flows are likewise affected.  In addition, future declines in commodity prices may result in noncash write-downs of the Company’s carrying amounts of its assets.

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business.  The Company does not enter into derivative contracts for trading purposes.  The appropriate level of production to be hedged is an ongoing consideration based on a variety of factors, including among other things, current and future expected commodity market prices, the Company’s overall risk profile, including leverage and size and scale considerations, as well as any requirements for or restrictions on levels of hedging contained in any credit facility or other debt instrument applicable at the time.  In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain higher revenues for its production if commodity prices recover during the duration of the contracts.  As a result, the appropriate percentage of production volumes to be hedged may change over time.

At June 30, 2018, the fair value of fixed price swaps was a net liability of approximately $1 million.  A 10% increase in the NYMEX WTI oil and NYMEX Henry Hub natural gas prices above the June 30, 2018, prices would result in a net liability of approximately $19 million, which represents a decrease in the fair value of approximately $18 million; conversely, a 10% decrease in the NYMEX oil and Henry Hub natural gas prices below the June 30, 2018, prices would result in a net asset of approximately $17 million, which represents an increase in the fair value of approximately $18 million.

At December 31, 2017, the fair value of fixed price swaps and collars was a net liability of approximately $2 million.  A 10% increase in the NYMEX WTI oil and NYMEX Henry Hub natural gas prices above the December 31, 2017, prices would result in a net liability of approximately $45 million, which represents a decrease in the fair value of approximately $43 million; conversely, a 10% decrease in the NYMEX oil and Henry Hub natural gas prices below the December 31, 2017, prices would result in a net asset of approximately $38 million, which represents an increase in the fair value of approximately $40 million.

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.

The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue.  Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty, including regional conditions and a variety of additional factors that are beyond its control.  Actual gains or losses recognized related to the Company’s derivative contracts depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.  Additionally, the Company cannot be assured that its counterparties will be able to perform under its derivative contracts.  If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows could be impacted.

59

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2018.

Changes in the Company’s Internal Control Over Financial Reporting

The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act.  The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed consolidated and combined financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements.  Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

There were no changes in the Company’s internal control over financial reporting during the second quarter of 2018 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

60

Part II – Other Information

Item 1. Legal Proceedings

On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.  On January 27, 2017, the Bankruptcy Court entered the Confirmation Order.  Consummation of the Plan was subject to certain conditions set forth in the Plan.  On February 28, 2017, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms.  The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates.  However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.

In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor’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 administrative agent under the Predecessor’s credit facility.  UMB Bank then immediately filed a notice of appeal to the United States 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.  That 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 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 under the caption “Risk Factors” in the Registration Statement.  As of the date of this report, these risk factors have not changed materially.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the U.S. Securities and Exchange Commission.

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

Issuer Purchases of Equity Securites

The Company’s Board of Directors 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.

Item 3. Defaults Upon Senior Securities

None

61

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

None

62

Item 6.Exhibits

Exhibit Number		Description
3.1	—	Certificate of Incorporation of Riviera Resources, Inc. (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-8 filed on August 7, 2018)
3.2	—	Bylaws of Riviera Resources, Inc. (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-8 filed on August 7, 2018)
31.1*	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2*	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1*	—	Section 1350 Certification of Chief Executive Officer
32.2*	—	Section 1350 Certification of Chief Financial Officer
101.INS*	—	XBRL Instance Document
101.SCH*	—	XBRL Taxonomy Extension Schema Document
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

63

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	RIVIERA RESOURCES, INC.
	(Registrant)
Date:  August 24, 2018	/s/  Darren R. Schluter
	Darren R. Schluter
	Executive Vice President, Finance, Administration and Chief Accounting Officer
	(Duly Authorized Officer and Principal Accounting Officer)

64

EX-31.1

Exhibit 31.1

CERTIFICATION

I, David B. Rottino, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Riviera Resources, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 24, 2018

/s/  David B. Rottino

David B. Rottino

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, James G. Frew, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Riviera Resources, Inc. (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 24, 2018

/s/  James G. Frew

James G. Frew

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Riviera Resources, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David B. Rottino, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  August 24, 2018	/s/  David B. Rottino
	David B. Rottino
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Riviera Resources, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30, 2018, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James G. Frew, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  August 24, 2018	/s/  James G. Frew
	James G. Frew
	Executive Vice President and Chief Financial Officer

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Aug. 07, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Trading Symbol	RVRA
Entity Registrant Name	Riviera Resources, Inc.
Entity Central Index Key	0001737204
Current Fiscal Year End	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		76,190,908
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 301,365	$ 464,477
Accounts receivable – trade, net	64,686	140,485
Derivative instruments	3,934	9,629
Restricted cash	43,387	56,445
Other current assets	45,760	76,683
Assets held for sale	22	106,963
Total current assets	459,154	854,682
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	785,815	950,083
Less accumulated depletion and amortization	(59,870)	(49,619)
Oil and natural gas properties, successful efforts method, net	725,945	900,464
Other property and equipment	566,861	480,729
Less accumulated depreciation	(44,412)	(28,658)
Other property and equipment, net	522,449	452,071
Derivative instruments	1,254	469
Deferred income taxes	169,645	188,538
Equity method investments	473,269	464,926
Other noncurrent assets	5,264	6,975
Noncurrent assets, excluding property, total	649,432	660,908
Total noncurrent assets	1,897,826	2,013,443
Total assets	2,356,980	2,868,125
Current liabilities:
Accounts payable and accrued expenses	179,119	253,975
Share-based payment liability	111,792	0
Derivative instruments	5,536	10,103
Other accrued liabilities	19,807	58,130
Liabilities held for sale	0	43,302
Total current liabilities	316,254	365,510
Noncurrent liabilities:
Derivative instruments	24	2,849
Asset retirement obligations and other noncurrent liabilities	105,531	160,720
Total noncurrent liabilities	105,555	163,569
Commitments and contingencies (Note 11)
Equity:
Net parent company investment	1,935,171	2,339,046
Total equity	1,935,171	2,339,046
Total liabilities and equity	$ 2,356,980	$ 2,868,125

XML

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Revenues and other:
Revenues		$ 136,358	$ 262,105	$ 347,372	$ 325,395
Gains (losses) on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Total revenues		128,833	307,819	381,127	302,840
Expenses:
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		40,327	6,976	9,515	82,082
General and administrative expenses		92,395	34,260	44,668	137,174
Exploration costs		53	811	866	1,255
Depreciation, depletion and amortization		21,980	45,945	63,792	50,445
Taxes, other than income taxes		7,115	17,871	24,948	15,567
(Gains) losses on sale of assets and other, net		(101,777)	(308,178)	(307,694)	(207,852)
Total expenses		105,394	(93,870)	(17,107)	190,950
Other income and (expenses):
Interest expense, net of amounts capitalized		(584)	(7,551)	(11,751)	(988)
Earnings (losses) from equity method investments		(9,327)	91	130	16,018
Other, net		538	(1,166)	(1,554)	368
Total other income and (expenses)		(9,373)	(8,626)	(13,175)	15,398
Reorganization items, net		(1,259)	(3,059)	(5,624)	(3,210)
Income from continuing operations before income taxes		12,807	390,004	379,435	124,078
Income tax expense (benefit)		5,610	161,544	157,098	45,942
Income from continuing operations		7,197	228,460	222,337	78,136
Income (loss) from discontinued operations, net of income taxes		0	5,302	5,759	0
Net income		$ 7,197	$ 233,762	$ 228,096	$ 78,136
Income per share:
Basic and diluted income from continuing operations per share		$ 0.09	$ 3.00	$ 2.91	$ 1.03
Basic and diluted income from discontinued operations per share		0	0.07	0.08	0
Basic and diluted net income per share		$ 0.09	$ 3.07	$ 2.99	$ 1.03
Basic and diluted weighted average shares outstanding		76,191	76,191	76,191	76,191
Predecessor
Revenues and other:
Revenues	$ 205,436
Gains (losses) on oil and natural gas derivatives	92,691
Total revenues	298,127
Expenses:
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,820
General and administrative expenses	71,745
Exploration costs	93
Depreciation, depletion and amortization	47,155
Taxes, other than income taxes	14,877
(Gains) losses on sale of assets and other, net	829
Total expenses	215,156
Other income and (expenses):
Interest expense, net of amounts capitalized	(16,725)
Earnings (losses) from equity method investments	157
Other, net	(149)
Total other income and (expenses)	(16,717)
Reorganization items, net	2,521,137
Income from continuing operations before income taxes	2,587,391
Income tax expense (benefit)	(166)
Income from continuing operations	2,587,557
Income (loss) from discontinued operations, net of income taxes	(548)
Net income	$ 2,587,009
Income per share:
Basic and diluted income from continuing operations per share	$ 33.96
Basic and diluted income from discontinued operations per share	(0.01)
Basic and diluted net income per share	$ 33.95
Basic and diluted weighted average shares outstanding	76,191
Oil, Natural Gas and Natural Gas Liquids Sales
Revenues and other:
Revenues		$ 87,004	$ 243,167	$ 323,492	$ 223,880
Oil, Natural Gas and Natural Gas Liquids Sales | Predecessor
Revenues and other:
Revenues	$ 188,885
Marketing
Revenues and other:
Revenues		42,967	12,547	15,461	89,234
Marketing | Predecessor
Revenues and other:
Revenues	6,636
Other Revenues
Revenues and other:
Revenues		$ 6,387	$ 6,391	$ 8,419	$ 12,281
Other Revenues | Predecessor
Revenues and other:
Revenues	$ 9,915

XML

CONDENSED CONSOLIDATED STATEMENT OF EQUITY (Unaudited) - 6 months ended Jun. 30, 2018 $ in Thousands	USD ($)
Beginning of period at Dec. 31, 2017	$ 2,339,046
Net income	78,136
Net transfers to parent	(482,011)
Ending of period at Jun. 30, 2018	$ 1,935,171

XML

CONDENSED CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	2 Months Ended	4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2017	Jun. 30, 2018
Cash flow from operating activities:
Net income		$ 228,096	$ 78,136
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations		(5,759)	0
Depreciation, depletion and amortization		63,792	50,445
Deferred income taxes		134,698	46,077
Total (gains) losses on derivatives, net		(33,755)	22,555
Cash settlements on derivatives		7,929	(25,037)
Share-based compensation expenses		19,599	66,374
Amortization and write-off of deferred financing fees		82	824
(Gains) losses on sale of assets and other, net		(295,100)	(224,091)
Reorganization items, net		0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		27,212	76,465
(Increase) decrease in other assets		(3,642)	33,654
Increase (decrease) in accounts payable and accrued expenses		(95,320)	(52,538)
Increase (decrease) in other liabilities		22,421	(15,815)
Net cash provided by operating activities – continuing operations		70,253	57,049
Net cash provided by operating activities – discontinued operations		13,966	0
Net cash provided by operating activities		84,219	57,049
Cash flow from investing activities:
Development of oil and natural gas properties		(61,534)	(45,938)
Purchases of other property and equipment		(27,287)	(87,377)
Proceeds from sale of properties and equipment and other		697,829	369,489
Net cash provided by (used in) investing activities – continuing operations		609,008	236,174
Net cash used in investing activities – discontinued operations		(1,645)	0
Net cash provided by (used in) investing activities		607,363	236,174
Cash flow from financing activities:
Net transfers (to) from parent		(458)	(456,925)
Proceeds from borrowings		160,000	0
Repayments of debt		(876,570)	0
Payment to holders of claims under the Predecessor’s second lien notes		0	0
Distributions to unitholders		0	(12,174)
Other		(3,060)	(294)
Net cash used in financing activities – continuing operations		(720,088)	(469,393)
Net cash used in financing activities – discontinued operations		0	0
Net cash used in financing activities		(720,088)	(469,393)
Net decrease in cash, cash equivalents and restricted cash		(28,506)	(176,170)
Cash, cash equivalents and restricted cash:
Beginning		144,022	520,922
Ending	$ 144,022	115,516	$ 344,752
Predecessor
Cash flow from operating activities:
Net income	2,587,009
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations	548
Depreciation, depletion and amortization	47,155
Deferred income taxes	(166)
Total (gains) losses on derivatives, net	(92,691)
Cash settlements on derivatives	(11,572)
Share-based compensation expenses	50,255
Amortization and write-off of deferred financing fees	1,338
(Gains) losses on sale of assets and other, net	1,069
Reorganization items, net	(2,456,074)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(7,216)
(Increase) decrease in other assets	528
Increase (decrease) in accounts payable and accrued expenses	20,949
Increase (decrease) in other liabilities	2,801
Net cash provided by operating activities – continuing operations	143,933
Net cash provided by operating activities – discontinued operations	8,781
Net cash provided by operating activities	152,714
Cash flow from investing activities:
Development of oil and natural gas properties	(50,597)
Purchases of other property and equipment	(7,409)
Proceeds from sale of properties and equipment and other	(166)
Net cash provided by (used in) investing activities – continuing operations	(58,172)
Net cash used in investing activities – discontinued operations	(584)
Net cash provided by (used in) investing activities	(58,756)
Cash flow from financing activities:
Net transfers (to) from parent	636,000
Proceeds from borrowings	0
Repayments of debt	(1,038,986)
Payment to holders of claims under the Predecessor’s second lien notes	(30,000)
Distributions to unitholders	0
Other	(4,744)
Net cash used in financing activities – continuing operations	(437,730)
Net cash used in financing activities – discontinued operations	0
Net cash used in financing activities	(437,730)
Net decrease in cash, cash equivalents and restricted cash	(343,772)
Cash, cash equivalents and restricted cash:
Beginning	487,794	$ 144,022
Ending	$ 144,022

XML

Basis of Presentation

6 Months Ended

Jun. 30, 2018

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Basis of Presentation

Note 1 – Basis of Presentation

Unless otherwise indicated or the context otherwise requires, references herein to the “Company” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (“Parent”) and its consolidated subsidiaries, and (ii) after 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.

In April 2018, the Parent announced its intention to separate Riviera from LINN Energy.  Following the Spin-off, Riviera is a new 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.

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 LINN Energy shareholders on a pro rata basis (the “Spin-off”).  Prior to the completion of the Spin-off, a then subsidiary of the Parent distributed $40 million to the Parent.  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 LINN Energy does not retain any ownership interest in Riviera. 

On August 7, 2018, Riviera entered into a Transition Services Agreement (the “TSA”) with the Parent to facilitate an orderly transition following the Spin-off, with a term to be determined based upon certain future specified events but to end no later than December 31, 2018.  Pursuant to the TSA, Riviera agreed to provide the Parent with certain finance, financial reporting, information technology, investor relations, legal, payroll, tax and other services. Riviera will reimburse the Parent for, or pay on the Parent’s behalf, all direct and indirect costs and expenses incurred by the Parent during the term of the agreement in connection with the fees for any such services. In addition, from time to time during the term of the agreement, Riviera and the Parent may mutually agree on additional services to be provided.

The accompanying condensed consolidated and combined financial statements have been prepared on a stand-alone basis and are derived from Linn Energy, Inc.’s consolidated financial statements and accounting records for the periods presented as the Company was historically managed as a subsidiary of Linn Energy, Inc.

During the reporting period, the Parent was a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo, LLC (collectively, the “LINN Debtors”) and Berry Petroleum Company, LLC (“Berry” and collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”).  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.  During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

Nature of Business

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, North Louisiana, Michigan/Illinois, the Uinta Basin and the Mid-Continent.  The Blue Mountain reporting segment consists of the Chisholm Trail gas plant system which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines 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.  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.  The Company has classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its consolidated and combined financial statements.  See Note 4 for additional information.

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 condensed consolidated financial statements.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s financial statements in periods subsequent to the Reorganization Date.

Principles of Consolidation and Combination

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission rules and regulations; as such, this report should be read in conjunction with the financial statements and notes for the year ended December 31, 2017 included in the Company’s Registration Statement on Form S-1, as amended (File No. 333-225927).  The results reported in these unaudited condensed consolidated and combined financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated and combined financial statements for Predecessor periods represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under common control of the Parent, which exclude Linn Acquisition Company, LLC (“LAC”) and Berry.  On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as standalone unaffiliated entities.  The condensed consolidated financial statements for the Successor period represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under the control of the Parent.  The Company presents its condensed consolidated and combined financial statements in accordance with U.S. GAAP.  The condensed consolidated and combined financial statements include the accounts of the Company and its subsidiaries.  All significant intercompany transactions and balances have been eliminated. The condensed consolidated and combined financial statements were prepared on a carve-out basis and reflect significant assumptions and allocations.

Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.  See Note 6 for additional information about equity method investments.

Bankruptcy Accounting

Upon LINN Energy’s emergence from bankruptcy on February 28, 2017, the Parent adopted fresh start accounting which resulted in the Parent becoming a new entity for financial reporting purposes.  As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan (as defined in Note 2), the Company’s condensed consolidated financial statements subsequent to February 28, 2017, are not comparable to its condensed consolidated and combined financial statements prior to February 28, 2017.  References to “Successor” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017.  References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, February 28, 2017.  The Company’s condensed consolidated and combined financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017.  See Note 2 for additional information.

Use of Estimates

The preparation of the accompanying condensed consolidated and combined financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, and fair values of commodity derivatives.  In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Adopted Accounting Standards

In November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows.  The Company adopted this ASU on January 1, 2018, on a retrospective basis.  The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows (see Note 16).

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers (“ASC 606”).  The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method.  Accordingly, the comparative information for the six months ended June 30, 2017, has not been adjusted and continues to be reported under the previous revenue standard.  The adoption of this ASU impacted the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3).

Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions.  All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.  For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company.  Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company.

In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no material impact on net income.

The items discussed above impacted the Company’s reported “oil, natural gas and natural gas liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses” and “interest expense.”  The impact of adoption on the Company’s current period results is as follows:

	Three Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	53,662	$	53,285	$	377
Oil sales		10,919		10,919		—
NGL sales		22,423		22,280		143
Total oil, natural gas and NGL sales		87,004		86,484		520
Marketing revenues		42,967		25,406		17,561
Other revenues		6,387		6,003		384
		136,358		117,893		18,465
Expenses:
Transportation expenses		21,213		20,693		520
Marketing expenses		40,327		22,766		17,561
Interest expense		584		420		164
Net income	$	7,197	$	6,977	$	220

	Six Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	116,990	$	117,794	$	(804	)
Oil sales		56,615		56,615		—
NGL sales		50,275		50,222		53
Total oil, natural gas and NGL sales		223,880		224,631		(751	)
Marketing revenues		89,234		53,521		35,713
Other revenues		12,281		11,676		605
		325,395		289,828		35,567
Expenses:
Transportation expenses		40,307		41,058		(751	)
Marketing expenses		82,082		46,369		35,713
Interest expense		988		824		164
Net income	$	78,136	$	77,695	$	441

New Accounting Standards Issued But Not Yet Adopted

In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted).  The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures.  The Company expects the adoption of this ASU to impact its balance sheet resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

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Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting

6 Months Ended

Jun. 30, 2018

Emergence From Voluntary Reorganization Under Chapter11 [Abstract]

Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting

Note 2 – Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting

On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.

On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Plan”).  The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court.

On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”).  LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.

On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”).  On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.

Reorganization Items, Net

The Company incurred significant costs and recognized significant gains associated with the reorganization.  Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined.  The following table summarizes the components of reorganization items included on the condensed consolidated and combined statements of operations:

	Successor
	Three Months Ended June 30,
	2018			2017
	(in thousands)
Legal and other professional fees	$	(1,255	)	$	(3,128	)
Other		(4	)		69
Reorganization items, net	$	(1,259	)	$	(3,059	)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	3,914,964
Recognition of an additional claim for the Predecessor’s second lien    notes settlement		—			—			(1,000,000	)
Fresh start valuation adjustments		—			—			(591,525	)
Income tax benefit related to implementation of the Plan		—			—			264,889
Legal and other professional fees		(3,207	)		(5,698	)		(46,961	)
Terminated contracts		—			—			(6,915	)
Other		(3	)		74			(13,315	)
Reorganization items, net	$	(3,210	)	$	(5,624	)	$	2,521,137

Fresh Start Accounting

Upon LINN Energy’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”), which resulted in the Parent becoming a new entity for financial reporting purposes.  In accordance with ASC 852, the Parent was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the predecessor of the Parent (the “Predecessor”) received less than 50% of the voting shares of the successor of the Parent (the “Successor”) and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.

Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations.”  The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes.”  The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet.  The effects of the Plan and the application of fresh start accounting were reflected on the condensed consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the condensed consolidated statement of operations for the two months ended February 28, 2017.

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Revenues

6 Months Ended

Jun. 30, 2018

Revenue From Contract With Customer [Abstract]

Revenues

Note 3 – Revenues

Revenue from Contracts with Customers

The Company recognizes sales of oil, natural gas and NGL when it satisfies a performance obligation by transferring control of the product to a customer, in an amount that reflects the consideration to which the Company expects to be entitled in exchange for the product.

Natural Gas and NGL Sales

The Company’s natural gas production is primarily sold under 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.

For its natural gas contracts, the Company generally records its wet gas sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses, and its residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses.  All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.

Oil Sales

The Company’s oil production is primarily sold under 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.  For its oil contracts, the Company generally records its sales based on the net amount received.

Production Imbalances

The Company uses the sales method to account for natural gas production imbalances.  If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance.  No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Marketing Revenues

The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements.  As such, the Company separately reports third-party marketing revenues and marketing expenses.

Disaggregation of Revenue

The following tables present the Company’s disaggregated revenues by source and geographic area:

	Three Months Ended June 30, 2018
	Natural Gas		Oil		NGL			Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues		Total
	(in thousands)
Hugoton Basin	$	17,401	$	238	$	16,875		$	34,514	$	22,421	$	6,303	$	63,238
Mid-Continent		7,622		4,880		3,307			15,809		—		25		15,834
East Texas		12,661		1,091		1,013			14,765		467		3		15,235
Permian Basin		256		546		(488	)		314		—		16		330
Uinta Basin		2,146		1,885		1,201			5,232		—		1		5,233
North Louisiana		6,040		1,480		503			8,023		13		2		8,038
Michigan/Illinois		7,536		799		12			8,347		—		37		8,384
Blue Mountain		—		—		—			—		20,066		—		20,066
Total	$	53,662	$	10,919	$	22,423		$	87,004	$	42,967	$	6,387	$	136,358

	Six Months Ended June 30, 2018
	Natural Gas		Oil		NGL		Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues			Total
	(in thousands)
Hugoton Basin	$	39,764	$	2,970	$	36,389	$	79,123	$	46,501	$	12,134		$	137,758
Mid-Continent		15,555		16,747		6,361		38,663		—		39			38,702
East Texas		27,437		2,431		2,319		32,187		503		8			32,698
Permian Basin		2,282		20,654		2,557		25,493		—		32			25,525
Uinta Basin		5,526		9,255		2,559		17,340		—		(1	)		17,339
North Louisiana		12,418		3,049		67		15,534		272		3			15,809
Michigan/Illinois		14,008		1,509		23		15,540		—		66			15,606
Blue Mountain		—		—		—		—		41,958		—			41,958
Total	$	116,990	$	56,615	$	50,275	$	223,880	$	89,234	$	12,281		$	325,395

Contract Balances

Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional.  Accordingly, the Company’s product sales contracts do not give rise to material contract assets or contract liabilities.

The Company had trade accounts receivable related to revenue from contracts with customers of approximately $56 million and $117 million as of June 30, 2018, and December 31, 2017, respectively.

Performance Obligations

The majority of the Company’s sales are short-term in nature with a contract term of one year or less.  For those contracts, the Company utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.  Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

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Divestitures and Discontinued Operations

6 Months Ended

Jun. 30, 2018

Discontinued Operations [Abstract]

Divestitures and Discontinued Operations

Note 4 – Divestitures and Discontinued Operations

Divestitures – 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 $15 million, and the Company recognized a net gain of approximately $11 million.

On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $132 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 $107 million, net of costs to sell of approximately $2 million, and the Company recognized a net gain of approximately $55 million.

On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $112 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.

The divestitures discussed above are not presented as discontinued operations because they do not represent a strategic shift that will have a major effect on the Company’s operations and financial results.  The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations and were included in the upstream reporting segment.

The assets and liabilities associated with the Oklahoma and Texas Assets Sale were classified as “held for sale” on the condensed consolidated balance sheet at December 31, 2017.  At December 31, 2017, the Company’s condensed consolidated balance sheet included current assets of approximately $107 million included in “assets held for sale” and current liabilities of approximately $43 million included in “liabilities held for sale” related to this transaction.

The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet:

	December 31, 2017
	(in thousands)
Assets:
Oil and natural gas properties	$	92,245
Other property and equipment		12,983
Other		1,735
Total assets held for sale	$	106,963
Liabilities:
Asset retirement obligations	$	42,001
Other		1,301
Total liabilities held for sale	$	43,302

Other assets primarily include inventories and other liabilities primarily include accounts payable.

Divestitures – 2017

On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. (the “Salt Creek Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $76 million and the Company recognized a net gain of approximately $33 million.

On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming to Jonah Energy LLC (the “Jonah Assets Sale”).  Cash proceeds received from the sale of these properties were approximately $560 million, net of costs to sell of approximately $6 million, and the Company recognized a net gain of approximately $270 million.

The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations and were included in the upstream reporting segment.

Discontinued Operations

During 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California.  As a result of the Company’s strategic exit from California, the Company classified the results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements.  The California properties were included in the upstream reporting segment.

The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations:

	Successor						Predecessor
	Three Months Ended June 30, 2017			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Revenues and other	$	20,511		$	27,636		$	14,891
Expenses		12,173			16,318			13,758
Other income and (expenses)		(2,074	)		(2,791	)		(1,681	)
Income (loss) from discontinued operations before income taxes		6,264			8,527			(548	)
Income tax expense		962			2,768			—
Income (loss) from discontinued operations, net of income taxes	$	5,302		$	5,759		$	(548	)

Other income and (expenses) include an allocation of interest expense for the California properties which represents interest on debt that was required to be repaid as a result of the sales.

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Oil and Natural Gas Properties

6 Months Ended

Jun. 30, 2018

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Oil and Natural Gas Properties

Note 5 – Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	June 30, 2018			December 31, 2017
	(in thousands)
Proved properties	$	739,656		$	904,390
Unproved properties		46,159			45,693
		785,815			950,083
Less accumulated depletion and amortization		(59,870	)		(49,619	)
	$	725,945		$	900,464

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Equity Method Investments

6 Months Ended

Jun. 30, 2018

Equity Method Investments [Abstract]

Equity Method Investments

Note 6 – Equity Method Investments

On August 31, 2017, the Parent, through certain of its then subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play.  In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan.  LINN Energy’s equity interest in Roan was historically held by a subsidiary of the Company.

The Company used the equity method of accounting for its investment in Roan.  The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets.  At both June 30, 2018, and December 31, 2017, the Company owned 50% of Roan’s outstanding units.

At June 30, 2018, the carrying amount of the Company’s investment in Roan of approximately $466 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $355 million.  The difference is attributable to proved and unproved oil and natural gas properties and is amortized over the lives of the related assets.  Such amortization is included in the equity earnings (losses) from the Company’s investment in Roan.  At December 31, 2017, the carrying amount of the Company’s investment in Roan of approximately $458 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $346 million.

Impairment testing on the Company’s investment in Roan was performed when events or circumstances warranted such testing and considered whether there was an inability to recover the carrying value of the investment that was other than temporary.  No impairments occurred with respect to the Company’s investment in Roan for the six months ended June 30, 2018.

As discussed above, historically, a subsidiary of the Company owned the equity interest in Roan.  However, following an internal reorganization in connection with the Spin-off, the equity interest in Roan is owned by the Parent and is no longer affiliated with Riviera.  As such, equity earnings (losses) in Roan will not be included in Riviera’s consolidated financial statements in periods subsequent to the Reorganization Date.

Following are summarized statements of operations information for Roan.

Summarized Roan Resources LLC Statements of Operations Information

	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
	(in thousands)
Revenues and other	$	44,789		$	145,873
Expenses		72,754			130,663
Other income and (expenses)		(1,087	)		(2,886	)
Net income (loss)	$	(29,052	)	$	12,324

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Debt

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Debt

Note 7 – Debt

Credit Facility

On August 4, 2017, the Parent entered into a credit agreement with its then subsidiary Linn Energy Holdco II LLC (the “Borrower”), as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million.

On April 30, 2018, the Parent entered into an amendment to the Credit Facility (the “Credit Facility Amendment”) which, among other things, modified the borrowing base and maximum borrowing commitment amount to $425 million.

As of June 30, 2018, there were no borrowings outstanding under the Credit Facility and there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit).  The maturity date is August 4, 2020.  In connection with the Spin-off and as required by the Credit Facility Amendment, Riviera executed a Joinder Agreement on August 7, 2018, whereby it assumed the obligations of the Parent under the Credit Facility.  Following the Spin-off, the Borrower is a subsidiary of Riviera.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October.  At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base.  Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period.  The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders.

The obligations under the Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of the oil and natural gas properties of the Company and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, and certain of its subsidiaries, subject to customary exceptions.  Under the Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0, and (ii) a minimum adjusted current ratio of 1.0 to 1.0.

The Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates.

The Credit Facility contains events of default and remedies customary for credit facilities of this nature.  Failure to comply with the financial and other covenants in the Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Credit Facility.

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”), providing for an initial borrowing commitment of $200 million.

Available borrowing capacity under the Blue Mountain Credit Facility is, for certain periods, subject to Blue Mountain Midstream’s compliance with financial covenants, which may from time to time result in a reduction of Blue Mountain Midstream’s available borrowing capacity.  As of August 10, 2018, there were no borrowings outstanding under the Blue Mountain Credit Facility and the initial available borrowing capacity was $70 million.  The Blue Mountain Credit Facility matures on August 10, 2023.

At Blue Mountain Midstream’s election, interest on borrowings under the Blue Mountain Credit Facility is determined by reference to either the LIBOR plus an applicable margin ranging from 2.00% to 3.00% per annum or the ABR plus an applicable margin ranging from 1.00% to 2.00% per annum, both depending on Blue Mountain Midstream’s consolidated total leverage ratio.  Interest is generally payable in arrears on the last day of March, June, September and December for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of three month intervals during such interest period.

Blue Mountain Midstream is required under the Blue Mountain Credit Facility to pay a commitment fee to the lenders, which accrues at a rate per annum of 0.375% or 0.50% (depending on Blue Mountain Midstream’s consolidated total leverage ratio) on the average daily unused amount of the available revolving loan commitments of the lenders.

The Blue Mountain Credit Facility is secured by a first priority lien on substantially all the assets of Blue Mountain Midstream.  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 potential future 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 “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 indebtedness 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.

The Blue Mountain Credit Facility also contains affirmative and negative covenants customary for credit facilities of this nature, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, budgets, maintenance and operation of property, restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets and transactions with affiliates.

The Blue Mountain Credit Facility contains events of default and remedies customary for credit facilities of this nature.  If Blue Mountain Midstream does not comply with the covenants in the Blue Mountain Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Blue Mountain Credit Facility.

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Derivatives

6 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivatives

Note 8 – Derivatives

Commodity Derivatives

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business.  The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production.  The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside.  The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received or paid.  The Company does not enter into derivative contracts for trading purposes.  The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.  See Note 9 for fair value disclosures about oil and natural gas commodity derivatives.

The following table presents derivative positions for the periods indicated as of June 30, 2018:

	July 1 – December 31, 2018			2019
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)		35,144			22,265
Average price ($/MMBtu)	$	3.02		$	2.89
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)		276			183
Average price ($/Bbl)	$	54.07		$	64.00
Natural gas basis differential positions: (1)
PEPL basis swaps:
Hedged volume (MMMBtu)		7,360			14,600
Hedge differential	$	(0.67	)	$	(0.67	)
NGPL TXOK basis swaps:
Hedged volume (MMMBtu)		1,840			—
Hedge differential	$	(0.19	)	$	—

(1) Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

During the six months ended June 30, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019.  During the four months ended June 30, 2017, the Company entered into commodity derivative contracts consisting of oil fixed price swaps for January 2018 through December 2018 and natural gas fixed price swaps for January 2018 through December 2019.  The Company did not enter into any commodity derivative contracts during the two months ended February 28, 2017.

In April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019.  The Company paid net cash settlements of approximately $20 million for the cancellations.

The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month.  The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following table summarizes the fair value of derivatives outstanding on a gross basis:

	June 30, 2018		December 31, 2017
	(in thousands)
Assets:
Commodity derivatives	$	6,825	$	22,589
Liabilities:
Commodity derivatives	$	7,197	$	25,443

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk.  The Company’s counterparties are participants in the Credit Facility.  The Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral.  The Company does not receive collateral from its counterparties.

The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $7 million at June 30, 2018.  The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis.  In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains and Losses on Derivatives

Gains and losses on derivatives were net losses of approximately $8 million and $23 million for the three months and six months ended June 30, 2018, respectively, and net gains of approximately $46 million and $34 million for the three months and four months ended June 30, 2017, respectively, and approximately $93 million for the two months ended February 28, 2017.  Gains and losses on derivatives are reported on the condensed consolidated and combined statements of operations in “gains (losses) on oil and natural gas derivatives.”

The Company paid net cash settlements of approximately $21 million and $25 million for the three months and six months ended June 30, 2018, respectively.  The Company received net cash settlements of approximately $2 million and $8 million for the three months and four months ended June 30, 2017, respectively, and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017.

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Fair Value Measurements on a Recurring Basis

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements on a Recurring Basis

Note 9 – Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 8) on a recurring basis.  The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis.  Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.  Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.  Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, are applied to the Company’s commodity derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments into a three-level fair value hierarchy based on the priority of inputs to the valuation technique.  The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	June 30, 2018
	Level 2		Netting (1)			Total
			(in thousands)
Assets:
Commodity derivatives	$	6,825	$	(1,637	)	$	5,188
Liabilities:
Commodity derivatives	$	7,197	$	(1,637	)	$	5,560

	December 31, 2017
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	22,589	$	(12,491	)	$	10,098
Liabilities:
Commodity derivatives	$	25,443	$	(12,491	)	$	12,952

(1) Represents counterparty netting under agreements governing such derivatives.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 10 – Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations.  Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred.  The liabilities are included in “other accrued liabilities” and “asset retirement obligations and other noncurrent liabilities” on the condensed consolidated balance sheets.  Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations.  The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount.  Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

In addition, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation of certain of Blue Mountain Midstream’s assets.  In such cases, asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life.  Indeterminate asset retirement obligation costs associated with Blue Mountain Midstream will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2017	$	164,553
Liabilities added from drilling		53
Liabilities associated with assets divested		(62,195	)
Current year accretion expense		4,081
Settlements		(1,859	)
Revisions of estimates		2,386
Asset retirement obligations at June 30, 2018	$	107,019

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2018

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 11 – Commitments and Contingencies

On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.  The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040.  On January 27, 2017, the Bankruptcy Court entered the Confirmation Order.  Consummation of the Plan was subject to certain conditions set forth in the Plan.  On the Effective Date, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms.  The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates.  However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.

In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor’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 administrative agent under the Predecessor’s credit facility.  UMB Bank then immediately filed a notice of appeal to the United States 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.  That 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.

Except for in connection with its Chapter 11 proceedings, the Company made no significant payments to settle any legal, environmental or tax proceedings during the six months ended June 30, 2018, or June 30, 2017.  The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary.  Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

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Equity

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

Equity

Note 12 – Equity

Shares Issued and Outstanding

As of August 7, 2018, upon completion of the Spin-off, there were 76,190,908 shares of Riviera’s common stock, par value $0.01 per share issued and outstanding.  An additional 522,329 unvested restricted stock units of Riviera (“Riviera RSUs”) were granted and outstanding under the Company’s Omnibus Incentive Plan.  Such unvested restricted stock units were originally granted as restricted stock units of the Parent (“LINN RSUs”) pursuant to the Linn Energy, Inc. 2017 Omnibus Plan (the “LINN Incentive Plan”), and in connection with the Spin-off, the holders of such LINN RSUs received one Riviera restricted stock unit in respect of each such outstanding LINN RSU.

Share Repurchase Program

On August 16, 2018, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock.

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 Credit Facility.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Share-Based Compensation

Note 13 – Share-Based Compensation

Riviera Omnibus Incentive Plan

The Company had no equity awards outstanding as of June 30, 2018.  In August 2018, the Company implemented the Riviera Resources, Inc. 2018 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) pursuant to which employees, consultants and non-employee directors of the Company and its affiliates are eligible to receive stock options, restricted stock, dividend equivalents, performance awards, other stock-based awards and other cash-based awards.

The Committee (as defined in the Omnibus Incentive Plan) has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award.  As of August 7, 2018, up to 3,433,499 shares of common stock were available for issuance under the Omnibus Incentive Plan.  If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of common stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan.  If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of common stock awarded under the Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the Omnibus Incentive Plan.  Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s shareholders.

Pursuant to the Spin-off, on August 7, 2018, certain employees of the Company received 522,329 Riviera RSUs.  Such Riviera RSUs were originally granted as LINN RSUs pursuant to the LINN Incentive Plan and in connection with the Spin-off, the holders of such LINN RSUs received one Riviera RSU in respect of each such outstanding LINN RSU.

Accounting for LINN Energy’s Share-Based Compensation

The condensed consolidated and combined financial statements include 100% of the Parent’s employee-related expenses, as its personnel were employed by Riviera Operating, LLC, formerly known as Linn Operating, LLC (“Riviera Operating”), a subsidiary of the Parent that became a subsidiary of Riviera in connection with the Spin-off.  Compensation cost related to the grant of share-based awards has been recorded at the subsidiary level with a corresponding credit to liability or equity, representing the Parent’s capital contribution.

A summary of share-based compensation expenses included on the condensed consolidated and combined statements of operations is presented below:

	Three Months Ended June 30,
	2018		2017
	(in thousands)
General and administrative expenses	$	58,188	$	15,422
Income tax benefit	$	4,315	$	3,128

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
General and administrative expenses	$	75,225	$	19,599	$	50,255
Income tax benefit	$	6,732	$	3,555	$	5,170

During the six months ended June 30, 2018, the Parent granted to certain employees 12,500 LINN RSUs with an aggregate grant date fair value of approximately $519,000.  The LINN RSUs vest over three years.

Upon a participant’s termination of employment and/or service (as applicable), the Parent had the right (but not the obligation) to repurchase all or any portion of the shares of Class A common stock, par value $0.001 per share of Linn Energy, Inc. (“LINN Class A common stock”), acquired pursuant to an award at a price equal to the fair market value (as determined under the LINN Incentive Plan) of the shares of LINN Class A common stock to be repurchased, measured as of the date of the Parent’s repurchase notice.  During May 2018, the Parent began exercising its right to repurchase vesting awards under the LINN Incentive Plan, which modified all outstanding awards to liability classification.  For the six months ended June 30, 2018, the Parent repurchased 271,314 restricted stock units for a total cost of approximately $11 million pursuant to its right to repurchase vesting awards.  The Company has recognized a liability of approximately $112 million related to awards required to be liability classified, included in “share-based payment liability” on the condensed consolidated balance sheet and recorded incremental share-based compensation expense of approximately $18 million related to modifying the awards to liability classification.  At June 30, 2018, all outstanding share-based payment awards of the Parent are liability classified.

In April 2018, the Parent entered into agreements with each of its then serving executive officers, under which the Parent agreed, at the option of each officer, to repurchase certain of their LINN RSU awards and outstanding LINN Class A common stock.  Pursuant to those agreements, on August 7, 2018, the Parent repurchased an aggregate of 2,477,834 shares of LINN Class A common stock for a total cost of approximately $102 million.

In addition, in January 2018, the Parent’s board of directors’ compensation committee approved a one-time liquidity program under which the Parent agreed, at the option of the participant, to 1) settle all or a portion of an eligible participant’s LINN RSUs vesting on or before March 1, 2018, in cash and/or 2) repurchase all or a portion of any shares of LINN Class A common stock held by an eligible participant as a result of a prior vesting of restricted stock units, in each case at an agreed upon price (the “Liquidity Program”).  For the six months ended June 30, 2018, the Parent settled 1,028,875 restricted stock units in cash and repurchased 120,829 shares of LINN Class A common stock for approximately $45 million pursuant to the Liquidity Program.

On August 2, 2018, the Parent’s board of directors authorized the termination of the LINN Incentive Plan following the settlement of all outstanding LINN RSUs and restricted common stock of the Parent.  In addition, all remaining unvested LINN RSUs were vested upon the Spin-off, exclusive of the dividend of Riviera associated with each unvested restricted stock unit, which remain outstanding and unvested under the Company’s Omnibus Incentive Plan.

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Earnings Per Share

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Earnings Per Share

Note 14 – Earnings Per Share

On August 7, 2018, the Parent distributed 76,190,908 shares of Riviera common stock to LINN Energy shareholders.  LINN Energy did not retain any ownership in Riviera.  Each LINN Energy shareholder received one share of Riviera common stock for each share of LINN Class A common stock held by such LINN Energy shareholder at the close of business on August 7, 2018, the record date.

Basic and diluted earnings per share and the average number of shares outstanding were retrospectively restated for the number of shares of Riviera common stock outstanding immediately following this transaction.  The same number of shares was used to calculate basic and diluted earnings per share since there were no Riviera equity awards outstanding prior to the Spin-off.

The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share computations for net income:

	Successor
	Three Months Ended June 30,
	2018		2017
Income from continuing operations	$	7,197	$	228,460
Income from discontinued operations, net of income taxes		—		5,302
Net income	$	7,197	$	233,762
Basic and diluted income from continuing operations per share	$	0.09	$	3.00
Basic and diluted income from discontinued operations per share	$	—	$	0.07
Basic and diluted earnings per share	$	0.09	$	3.07
Basic and diluted weighted average number of common shares outstanding		76,191		76,191

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
Income from continuing operations	$	78,136	$	222,337	$	2,587,557
Income (loss) from discontinued operations, net of income taxes		—		5,759		(548	)
Net income	$	78,136	$	228,096	$	2,587,009
Basic and diluted income from continuing operations per share	$	1.03	$	2.91	$	33.96
Basic and diluted income (loss) from discontinued operations per share	$	—	$	0.08	$	(0.01	)
Basic and diluted earnings per share	$	1.03	$	2.99	$	33.95
Basic and diluted weighted average number of common shares outstanding		76,191		76,191		76,191

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Income Taxes

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Note 15 – Income Taxes

Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations.  The effective income tax rates were approximately 44% and 37% for the three months and six months ended June 30, 2018, respectively, approximately 41% for both the three months and four months ended June 30, 2017, and zero for the two months ended February 28, 2017.  For the six months ended June 30, 2018, the Company’s federal and state statutory rate net of the federal tax benefit was approximately 24%.  The increase in the effective tax rate in excess of the statutory rate is primarily due to non-deductible executive compensation.

The Successor was formed as a C corporation.  For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders.  Limited liability companies are subject to Texas margin tax.  In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes.  As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor.  The deferred tax effects of the Company’s change to a C corporation are included in income from continuing operations for the two months ended February 28, 2017.

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows

6 Months Ended

Jun. 30, 2018

Supplemental Disclosures To The Condensed Consolidated Statements Of Cash Flows [Abstract]

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows

Note 16 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows

“Other current assets” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Prepaids	$	13,310	$	43,150
Receivable from related party		25,982		23,163
Inventories		3,981		7,667
Other		2,487		2,703
Other current assets	$	45,760	$	76,683

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Accrued compensation	$	13,533	$	29,089
Asset retirement obligations (current portion)		1,488		3,926
Deposits		3,170		15,349
Income taxes payable		—		7,009
Other		1,616		2,757
Other accrued liabilities	$	19,807	$	58,130

The following table provides a reconciliation of “cash and cash equivalents” reported on the condensed consolidated balance sheets to “cash, cash equivalents and restricted cash” reported on the condensed consolidated statement of cash flows:

	June 30, 2018		December 31, 2017
	(in thousands)
Cash and cash equivalents	$	301,365	$	464,477
Restricted cash		43,387		56,445
Cash, cash equivalents and restricted cash	$	344,752	$	520,922

Supplemental disclosures to the condensed consolidated and combined statements of cash flows are presented below:

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Cash payments for interest, net of amounts capitalized	$	—	$	14,436	$	17,651
Cash payments for income taxes	$	—	$	215	$	—
Cash payments for reorganization items, net	$	2,911	$	5,982	$	21,571
Noncash investing activities:
Accrued capital expenditures	$	21,968	$	34,547	$	22,191

For purposes of the condensed consolidated and combined statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.  At June 30, 2018, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $33 million that will be used to settle certain claims in accordance with the Plan (which is the remainder of approximately $80 million transferred to restricted cash in February 2017 to fund such items), approximately $3 million related to deposits and approximately $7 million for other items.  At December 31, 2017, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $36 million that will be used to settle certain claims in accordance with the Plan, approximately $15 million related to deposits and approximately $5 million for other items.

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Related Party Transactions

6 Months Ended

Jun. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions Disclosure

Note 17 – Related Party Transactions

Roan Resources LLC

On August 31, 2017, the Parent completed the Roan Contribution.  In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan.  See Note 6 for additional information.  Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Riviera Operating, pursuant to which Riviera Operating agreed to provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period.

Under the MSA, Roan agreed to reimburse Riviera Operating for certain costs and expenses incurred by Riviera Operating in connection with providing the services, and to pay to Riviera Operating a service fee of $1.25 million per month, prorated for partial months.  The MSA terminated according to its terms on April 30, 2018.

In addition, the Company’s subsidiary, Blue Mountain Midstream has an agreement in place with Roan for the purchase and processing of natural gas from certain of Roan’s properties.

For the three months and six months ended June 30, 2018, the Company made natural gas purchases from Roan of approximately $15 million and $32 million, respectively, included in “marketing expenses” on the condensed consolidated statements of operations.  In addition, for the three months and six months ended June 30, 2018, the Company recognized service fees of approximately $1 million and $5 million, respectively, under the MSA, as a reduction to general and administrative expenses.  At June 30, 2018, the Company had approximately $26 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $11 million due to Roan, associated with natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.  At December 31, 2017, the Company had approximately $23 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $18 million due to Roan, primarily associated with joint interest billings and natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet.

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Segments

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Segments

Note 18 – Segments

During the second quarter of 2018, the Company had two reporting segments: Upstream and Blue Mountain.  The upstream reporting segment was engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and consists of the Company’s properties in the Hugoton Basin, (including the Jayhawk natural gas processing plant, located in Kansas), East Texas, North Louisiana, Michigan/Illinois, the Uinta Basin and the Mid-Continent.  The Blue Mountain reporting segment is new for the second quarter of 2018 as a result of a change in the way the chief operating decision maker (“CODM”) assesses the Company’s results of operations following the hiring of a segment manager to lead the Blue Mountain reporting segment and the commissioning of the cryogenic natural gas processing facility during the second quarter of 2018.  The Blue Mountain reporting segment consists of the Chisholm Trail gas plant system, which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play.  To assess the performance of the Company’s reporting segments, the CODM analyzes field level cash flow.  The Company defines field level cash flow as revenues less direct operating expenses.  Other indirect income (expenses) include “general and administrative expenses,” “exploration costs,” “depreciation, depletion and amortization,” “gains on sale of assets and other, net,” “other income and (expenses)” and “reorganization items, net.”  Prior period amounts are presented on a comparable basis.  In addition, information regarding total assets by reporting segment is not presented because it is not reviewed by the CODM.

The following tables present the Company’s financial information by reporting segment:

	Successor
	Three Months Ended June 30, 2018
	Upstream		Blue Mountain			Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	87,004	$	—		$	—		$	87,004
Marketing revenues		22,901		20,066		—				42,967
Other revenues		6,387		—		—				6,387
		116,292		20,066			—			136,358
Lease operating expenses		24,088		—			—			24,088
Transportation expenses		21,213		—			—			21,213
Marketing expenses		20,244		20,083			—			40,327
Taxes other than income taxes		6,737		285			93			7,115
Total direct operating expenses		72,282		20,368			93			92,743
Field level cash flow	$	44,010	$	(302	)		(93	)		43,615
Losses on oil and natural gas derivatives							(7,525	)		(7,525	)
Other indirect income (expenses)							(23,283	)		(23,283	)
Income from continuing operations before income taxes									$	12,807

	Successor
	Three Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	243,167	—		$	—		$	243,167
Marketing revenues		10,793		1,754	—				12,547
Other revenues		6,391		—	—				6,391
		260,351		1,754		—			262,105
Lease operating expenses		71,057		—		—			71,057
Transportation expenses		37,388		—		—			37,388
Marketing expenses		6,156		820		—			6,976
Taxes other than income taxes		17,486		116		269			17,871
Total direct operating expenses		132,087		936		269			133,292
Field level cash flow	$	128,264	$	818		(269	)		128,813
Gains on oil and natural gas derivatives						45,714			45,714
Other indirect income (expenses)						215,477			215,477
Income from continuing operations before income taxes								$	390,004

	Successor
	Six Months Ended June 30, 2018
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	223,880	$	—	$	—		$	223,880
Marketing revenues		47,276		41,958	—				89,234
Other revenues		12,281		—	—				12,281
		283,437		41,958		—			325,395
Lease operating expenses		71,972		—		—			71,972
Transportation expenses		40,307		—		—			40,307
Marketing expenses		41,380		40,702		—			82,082
Taxes other than income taxes		14,908		477		182			15,567
Total direct operating expenses		168,567		41,179		182			209,928
Field level cash flow	$	114,870	$	779		(182	)		115,467
Losses on oil and natural gas derivatives						(22,555	)		(22,555	)
Other indirect income (expenses)						31,166			31,166
Income from continuing operations before income taxes								$	124,078

	Successor
	Four Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	323,492	—		$	—		$	323,492
Marketing revenues		13,273		2,188	—				15,461
Other revenues		8,419		—	—				8,419
		345,184		2,188		—			347,372
Lease operating expenses		95,687		—		—			95,687
Transportation expenses		51,111		—		—			51,111
Marketing expenses		8,513		1,002		—			9,515
Taxes other than income taxes		24,478		155		315			24,948
Total direct operating expenses		179,789		1,157		315			181,261
Field level cash flow	$	165,395	$	1,031		(315	)		166,111
Gains on oil and natural gas derivatives						33,755			33,755
Other indirect income (expenses)						179,569			179,569
Income from continuing operations before income taxes								$	379,435

	Predecessor
	Two Months Ended February 28, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	188,885	$	—	$	—		$	188,885
Marketing revenues		5,999		637	—				6,636
Other revenues		9,915		—	—				9,915
		204,799		637		—			205,436
Lease operating expenses		49,665		—		—			49,665
Transportation expenses		25,972		—		—			25,972
Marketing expenses		4,602		218		—			4,820
Taxes other than income taxes		14,773		78		26			14,877
Total direct operating expenses		95,012		296		26			95,334
Field level cash flow	$	109,787	$	341		(26	)		110,102
Gains on oil and natural gas derivatives						92,691			92,691
Other indirect income (expenses)						2,384,598			2,384,598
Income from continuing operations before income taxes								$	2,587,391

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Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2018

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Principles of Consolidation and Combination

Principles of Consolidation and Combination

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission rules and regulations; as such, this report should be read in conjunction with the financial statements and notes for the year ended December 31, 2017 included in the Company’s Registration Statement on Form S-1, as amended (File No. 333-225927).  The results reported in these unaudited condensed consolidated and combined financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated and combined financial statements for Predecessor periods represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under common control of the Parent, which exclude Linn Acquisition Company, LLC (“LAC”) and Berry.  On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as standalone unaffiliated entities.  The condensed consolidated financial statements for the Successor period represent the financial position and results of operations of entities held by the Company after the Spin-off that were historically under the control of the Parent.  The Company presents its condensed consolidated and combined financial statements in accordance with U.S. GAAP.  The condensed consolidated and combined financial statements include the accounts of the Company and its subsidiaries.  All significant intercompany transactions and balances have been eliminated. The condensed consolidated and combined financial statements were prepared on a carve-out basis and reflect significant assumptions and allocations.

Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.  See Note 6 for additional information about equity method investments.

Use of Estimates

Use of Estimates

The preparation of the accompanying condensed consolidated and combined financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events.  These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses.  The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, and fair values of commodity derivatives.  In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes.

As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results could differ from these estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

Recently Adopted Accounting Standards

In November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows.  The Company adopted this ASU on January 1, 2018, on a retrospective basis.  The adoption of this ASU resulted in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statement of cash flows (see Note 16).

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers (“ASC 606”).  The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method.  Accordingly, the comparative information for the six months ended June 30, 2017, has not been adjusted and continues to be reported under the previous revenue standard.  The adoption of this ASU impacted the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3).

Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions.  All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.  For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company.  Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company.

In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities.  This recognition results in an increase to revenues and expenses with no material impact on net income.

The items discussed above impacted the Company’s reported “oil, natural gas and natural gas liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses” and “interest expense.”  The impact of adoption on the Company’s current period results is as follows:

	Three Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	53,662	$	53,285	$	377
Oil sales		10,919		10,919		—
NGL sales		22,423		22,280		143
Total oil, natural gas and NGL sales		87,004		86,484		520
Marketing revenues		42,967		25,406		17,561
Other revenues		6,387		6,003		384
		136,358		117,893		18,465
Expenses:
Transportation expenses		21,213		20,693		520
Marketing expenses		40,327		22,766		17,561
Interest expense		584		420		164
Net income	$	7,197	$	6,977	$	220

	Six Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	116,990	$	117,794	$	(804	)
Oil sales		56,615		56,615		—
NGL sales		50,275		50,222		53
Total oil, natural gas and NGL sales		223,880		224,631		(751	)
Marketing revenues		89,234		53,521		35,713
Other revenues		12,281		11,676		605
		325,395		289,828		35,567
Expenses:
Transportation expenses		40,307		41,058		(751	)
Marketing expenses		82,082		46,369		35,713
Interest expense		988		824		164
Net income	$	78,136	$	77,695	$	441

New Accounting Standards Issued But Not Yet Adopted

In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet.  This ASU is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted).  The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures.  The Company expects the adoption of this ASU to impact its balance sheet resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

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Basis of Presentation (Tables)

6 Months Ended

Jun. 30, 2018

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

The impact of adoption on the Company’s current period results is as follows:

	Three Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	53,662	$	53,285	$	377
Oil sales		10,919		10,919		—
NGL sales		22,423		22,280		143
Total oil, natural gas and NGL sales		87,004		86,484		520
Marketing revenues		42,967		25,406		17,561
Other revenues		6,387		6,003		384
		136,358		117,893		18,465
Expenses:
Transportation expenses		21,213		20,693		520
Marketing expenses		40,327		22,766		17,561
Interest expense		584		420		164
Net income	$	7,197	$	6,977	$	220

	Six Months Ended June 30, 2018
	Under ASC 606		Under Prior Rule		Increase/ (Decrease)
	(in thousands)
Revenues:
Natural gas sales	$	116,990	$	117,794	$	(804	)
Oil sales		56,615		56,615		—
NGL sales		50,275		50,222		53
Total oil, natural gas and NGL sales		223,880		224,631		(751	)
Marketing revenues		89,234		53,521		35,713
Other revenues		12,281		11,676		605
		325,395		289,828		35,567
Expenses:
Transportation expenses		40,307		41,058		(751	)
Marketing expenses		82,082		46,369		35,713
Interest expense		988		824		164
Net income	$	78,136	$	77,695	$	441

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Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting (Tables)

6 Months Ended

Jun. 30, 2018

Emergence From Voluntary Reorganization Under Chapter11 [Abstract]

Schedule of Components of Reorganization Items

The following table summarizes the components of reorganization items included on the condensed consolidated and combined statements of operations:

	Successor
	Three Months Ended June 30,
	2018			2017
	(in thousands)
Legal and other professional fees	$	(1,255	)	$	(3,128	)
Other		(4	)		69
Reorganization items, net	$	(1,259	)	$	(3,059	)

	Successor						Predecessor
	Six Months Ended June 30, 2018			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Gain on settlement of liabilities subject to compromise	$	—		$	—		$	3,914,964
Recognition of an additional claim for the Predecessor’s second lien    notes settlement		—			—			(1,000,000	)
Fresh start valuation adjustments		—			—			(591,525	)
Income tax benefit related to implementation of the Plan		—			—			264,889
Legal and other professional fees		(3,207	)		(5,698	)		(46,961	)
Terminated contracts		—			—			(6,915	)
Other		(3	)		74			(13,315	)
Reorganization items, net	$	(3,210	)	$	(5,624	)	$	2,521,137

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Revenues (Tables)

6 Months Ended

Jun. 30, 2018

Revenue From Contract With Customer [Abstract]

Schedule of Company's Disaggregated revenues

The following tables present the Company’s disaggregated revenues by source and geographic area:

	Three Months Ended June 30, 2018
	Natural Gas		Oil		NGL			Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues		Total
	(in thousands)
Hugoton Basin	$	17,401	$	238	$	16,875		$	34,514	$	22,421	$	6,303	$	63,238
Mid-Continent		7,622		4,880		3,307			15,809		—		25		15,834
East Texas		12,661		1,091		1,013			14,765		467		3		15,235
Permian Basin		256		546		(488	)		314		—		16		330
Uinta Basin		2,146		1,885		1,201			5,232		—		1		5,233
North Louisiana		6,040		1,480		503			8,023		13		2		8,038
Michigan/Illinois		7,536		799		12			8,347		—		37		8,384
Blue Mountain		—		—		—			—		20,066		—		20,066
Total	$	53,662	$	10,919	$	22,423		$	87,004	$	42,967	$	6,387	$	136,358

	Six Months Ended June 30, 2018
	Natural Gas		Oil		NGL		Oil, Natural Gas and NGL Sales		Marketing Revenues		Other Revenues			Total
	(in thousands)
Hugoton Basin	$	39,764	$	2,970	$	36,389	$	79,123	$	46,501	$	12,134		$	137,758
Mid-Continent		15,555		16,747		6,361		38,663		—		39			38,702
East Texas		27,437		2,431		2,319		32,187		503		8			32,698
Permian Basin		2,282		20,654		2,557		25,493		—		32			25,525
Uinta Basin		5,526		9,255		2,559		17,340		—		(1	)		17,339
North Louisiana		12,418		3,049		67		15,534		272		3			15,809
Michigan/Illinois		14,008		1,509		23		15,540		—		66			15,606
Blue Mountain		—		—		—		—		41,958		—			41,958
Total	$	116,990	$	56,615	$	50,275	$	223,880	$	89,234	$	12,281		$	325,395

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Divestitures and Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2018

Discontinued Operations [Abstract]

Disclosure of Long Lived Assets Held-for-sale

The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet:

	December 31, 2017
	(in thousands)
Assets:
Oil and natural gas properties	$	92,245
Other property and equipment		12,983
Other		1,735
Total assets held for sale	$	106,963
Liabilities:
Asset retirement obligations	$	42,001
Other		1,301
Total liabilities held for sale	$	43,302

Other assets primarily include inventories and other liabilities primarily include accounts payable.

Summarized statements of operations

The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations:

	Successor						Predecessor
	Three Months Ended June 30, 2017			Four Months Ended June 30, 2017			Two Months Ended February 28, 2017
(in thousands)
Revenues and other	$	20,511		$	27,636		$	14,891
Expenses		12,173			16,318			13,758
Other income and (expenses)		(2,074	)		(2,791	)		(1,681	)
Income (loss) from discontinued operations before income taxes		6,264			8,527			(548	)
Income tax expense		962			2,768			—
Income (loss) from discontinued operations, net of income taxes	$	5,302		$	5,759		$	(548	)

Other income and (expenses) include an allocation of interest expense for the California properties which represents interest on debt that was required to be repaid as a result of the sales.

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Oil and Natural Gas Properties (Tables)

6 Months Ended

Jun. 30, 2018

Oil And Gas Exploration And Production Industries Disclosures [Abstract]

Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:

	June 30, 2018			December 31, 2017
	(in thousands)
Proved properties	$	739,656		$	904,390
Unproved properties		46,159			45,693
		785,815			950,083
Less accumulated depletion and amortization		(59,870	)		(49,619	)
	$	725,945		$	900,464

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Equity Method Investments (Tables)

6 Months Ended

Jun. 30, 2018

Equity Method Investments [Abstract]

Summarized Roan Resources LLC Statements of Operations Information

Following are summarized statements of operations information for Roan.

Summarized Roan Resources LLC Statements of Operations Information

	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
	(in thousands)
Revenues and other	$	44,789		$	145,873
Expenses		72,754			130,663
Other income and (expenses)		(1,087	)		(2,886	)
Net income (loss)	$	(29,052	)	$	12,324

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Derivative Positions

The following table presents derivative positions for the periods indicated as of June 30, 2018:

	July 1 – December 31, 2018			2019
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)		35,144			22,265
Average price ($/MMBtu)	$	3.02		$	2.89
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)		276			183
Average price ($/Bbl)	$	54.07		$	64.00
Natural gas basis differential positions: (1)
PEPL basis swaps:
Hedged volume (MMMBtu)		7,360			14,600
Hedge differential	$	(0.67	)	$	(0.67	)
NGPL TXOK basis swaps:
Hedged volume (MMMBtu)		1,840			—
Hedge differential	$	(0.19	)	$	—

(1) Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

Summary of Fair Value of Derivatives Outstanding on Gross Basis

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets.  The following table summarizes the fair value of derivatives outstanding on a gross basis:

	June 30, 2018		December 31, 2017
	(in thousands)
Assets:
Commodity derivatives	$	6,825	$	22,589
Liabilities:
Commodity derivatives	$	7,197	$	25,443

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Fair Value Measurements on a Recurring Basis (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:

	June 30, 2018
	Level 2		Netting (1)			Total
			(in thousands)
Assets:
Commodity derivatives	$	6,825	$	(1,637	)	$	5,188
Liabilities:
Commodity derivatives	$	7,197	$	(1,637	)	$	5,560

	December 31, 2017
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	22,589	$	(12,491	)	$	10,098
Liabilities:
Commodity derivatives	$	25,443	$	(12,491	)	$	12,952

(1) Represents counterparty netting under agreements governing such derivatives.

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2018

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Reconciliation of Company's Asset Retirement Obligations

The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2017	$	164,553
Liabilities added from drilling		53
Liabilities associated with assets divested		(62,195	)
Current year accretion expense		4,081
Settlements		(1,859	)
Revisions of estimates		2,386
Asset retirement obligations at June 30, 2018	$	107,019

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2018

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Share-Based Compensation Expenses

A summary of share-based compensation expenses included on the condensed consolidated and combined statements of operations is presented below:

	Three Months Ended June 30,
	2018		2017
	(in thousands)
General and administrative expenses	$	58,188	$	15,422
Income tax benefit	$	4,315	$	3,128

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
General and administrative expenses	$	75,225	$	19,599	$	50,255
Income tax benefit	$	6,732	$	3,555	$	5,170

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Reconciliation of Numerators and Denominators of Basic and Diluted Per Share Computations for Net Income

The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share computations for net income:

	Successor
	Three Months Ended June 30,
	2018		2017
Income from continuing operations	$	7,197	$	228,460
Income from discontinued operations, net of income taxes		—		5,302
Net income	$	7,197	$	233,762
Basic and diluted income from continuing operations per share	$	0.09	$	3.00
Basic and diluted income from discontinued operations per share	$	—	$	0.07
Basic and diluted earnings per share	$	0.09	$	3.07
Basic and diluted weighted average number of common shares outstanding		76,191		76,191

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
Income from continuing operations	$	78,136	$	222,337	$	2,587,557
Income (loss) from discontinued operations, net of income taxes		—		5,759		(548	)
Net income	$	78,136	$	228,096	$	2,587,009
Basic and diluted income from continuing operations per share	$	1.03	$	2.91	$	33.96
Basic and diluted income (loss) from discontinued operations per share	$	—	$	0.08	$	(0.01	)
Basic and diluted earnings per share	$	1.03	$	2.99	$	33.95
Basic and diluted weighted average number of common shares outstanding		76,191		76,191		76,191

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Disclosures To The Condensed Consolidated Statements Of Cash Flows [Abstract]

Schedule of Other Current Assets

Other current assets” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Prepaids	$	13,310	$	43,150
Receivable from related party		25,982		23,163
Inventories		3,981		7,667
Other		2,487		2,703
Other current assets	$	45,760	$	76,683

Schedule of Other Current Liabilities

Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	June 30, 2018		December 31, 2017
	(in thousands)
Accrued compensation	$	13,533	$	29,089
Asset retirement obligations (current portion)		1,488		3,926
Deposits		3,170		15,349
Income taxes payable		—		7,009
Other		1,616		2,757
Other accrued liabilities	$	19,807	$	58,130

Schedule of Reconciliation of Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of “cash and cash equivalents” reported on the condensed consolidated balance sheets to “cash, cash equivalents and restricted cash” reported on the condensed consolidated statement of cash flows:

	June 30, 2018		December 31, 2017
	(in thousands)
Cash and cash equivalents	$	301,365	$	464,477
Restricted cash		43,387		56,445
Cash, cash equivalents and restricted cash	$	344,752	$	520,922

Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows

Supplemental disclosures to the condensed consolidated and combined statements of cash flows are presented below:

	Successor				Predecessor
	Six Months Ended June 30, 2018		Four Months Ended June 30, 2017		Two Months Ended February 28, 2017
(in thousands)
Cash payments for interest, net of amounts capitalized	$	—	$	14,436	$	17,651
Cash payments for income taxes	$	—	$	215	$	—
Cash payments for reorganization items, net	$	2,911	$	5,982	$	21,571
Noncash investing activities:
Accrued capital expenditures	$	21,968	$	34,547	$	22,191

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Segments (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The following tables present the Company’s financial information by reporting segment:

	Successor
	Three Months Ended June 30, 2018
	Upstream		Blue Mountain			Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	87,004	$	—		$	—		$	87,004
Marketing revenues		22,901		20,066		—				42,967
Other revenues		6,387		—		—				6,387
		116,292		20,066			—			136,358
Lease operating expenses		24,088		—			—			24,088
Transportation expenses		21,213		—			—			21,213
Marketing expenses		20,244		20,083			—			40,327
Taxes other than income taxes		6,737		285			93			7,115
Total direct operating expenses		72,282		20,368			93			92,743
Field level cash flow	$	44,010	$	(302	)		(93	)		43,615
Losses on oil and natural gas derivatives							(7,525	)		(7,525	)
Other indirect income (expenses)							(23,283	)		(23,283	)
Income from continuing operations before income taxes									$	12,807

	Successor
	Three Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	243,167	—		$	—		$	243,167
Marketing revenues		10,793		1,754	—				12,547
Other revenues		6,391		—	—				6,391
		260,351		1,754		—			262,105
Lease operating expenses		71,057		—		—			71,057
Transportation expenses		37,388		—		—			37,388
Marketing expenses		6,156		820		—			6,976
Taxes other than income taxes		17,486		116		269			17,871
Total direct operating expenses		132,087		936		269			133,292
Field level cash flow	$	128,264	$	818		(269	)		128,813
Gains on oil and natural gas derivatives						45,714			45,714
Other indirect income (expenses)						215,477			215,477
Income from continuing operations before income taxes								$	390,004

	Successor
	Six Months Ended June 30, 2018
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	223,880	$	—	$	—		$	223,880
Marketing revenues		47,276		41,958	—				89,234
Other revenues		12,281		—	—				12,281
		283,437		41,958		—			325,395
Lease operating expenses		71,972		—		—			71,972
Transportation expenses		40,307		—		—			40,307
Marketing expenses		41,380		40,702		—			82,082
Taxes other than income taxes		14,908		477		182			15,567
Total direct operating expenses		168,567		41,179		182			209,928
Field level cash flow	$	114,870	$	779		(182	)		115,467
Losses on oil and natural gas derivatives						(22,555	)		(22,555	)
Other indirect income (expenses)						31,166			31,166
Income from continuing operations before income taxes								$	124,078

	Successor
	Four Months Ended June 30, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	323,492	—		$	—		$	323,492
Marketing revenues		13,273		2,188	—				15,461
Other revenues		8,419		—	—				8,419
		345,184		2,188		—			347,372
Lease operating expenses		95,687		—		—			95,687
Transportation expenses		51,111		—		—			51,111
Marketing expenses		8,513		1,002		—			9,515
Taxes other than income taxes		24,478		155		315			24,948
Total direct operating expenses		179,789		1,157		315			181,261
Field level cash flow	$	165,395	$	1,031		(315	)		166,111
Gains on oil and natural gas derivatives						33,755			33,755
Other indirect income (expenses)						179,569			179,569
Income from continuing operations before income taxes								$	379,435

	Predecessor
	Two Months Ended February 28, 2017
	Upstream		Blue Mountain		Not Allocated to Segments			Consolidated
	(in thousands)
Oil, natural gas and natural gas liquids sales	$	188,885	$	—	$	—		$	188,885
Marketing revenues		5,999		637	—				6,636
Other revenues		9,915		—	—				9,915
		204,799		637		—			205,436
Lease operating expenses		49,665		—		—			49,665
Transportation expenses		25,972		—		—			25,972
Marketing expenses		4,602		218		—			4,820
Taxes other than income taxes		14,773		78		26			14,877
Total direct operating expenses		95,012		296		26			95,334
Field level cash flow	$	109,787	$	341		(26	)		110,102
Gains on oil and natural gas derivatives						92,691			92,691
Other indirect income (expenses)						2,384,598			2,384,598
Income from continuing operations before income taxes								$	2,587,391

XML

Basis of Presentation - Additional Information (Details) - USD ($) $ in Millions	Aug. 07, 2018	Jun. 30, 2018	Dec. 31, 2017	Aug. 31, 2017
Roan Resources LLC
Basis Of Presentation [Line Items]
Ownership percentage		50.00%	50.00%	50.00%
Subsequent Event
Basis Of Presentation [Line Items]
Spin-off completion date	Aug. 07, 2018
Subsequent Event | Roan Resources LLC
Basis Of Presentation [Line Items]
Subsidiary distribution to parent	$ 40

XML

Basis of Presentation - Schedule of Impact of Adoption of ASC 606 on Current Period Results (Details) - USD ($) $ in Thousands	3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Revenues:
Revenues	$ 136,358	$ 262,105	$ 347,372	$ 325,395
Expenses:
Transportation expenses	21,213	37,388	51,111	40,307
Marketing expenses	40,327	6,976	9,515	82,082
Interest expense	584	7,551	11,751	988
Net income	7,197	233,762	228,096	78,136
Natural Gas Sales
Revenues:
Revenues	53,662			116,990
Oil Sales
Revenues:
Revenues	10,919			56,615
NGL
Revenues:
Revenues	22,423			50,275
Oil, Natural Gas and NGL Sales
Revenues:
Revenues	87,004	243,167	323,492	223,880
Marketing
Revenues:
Revenues	42,967	12,547	15,461	89,234
Other Revenues
Revenues:
Revenues	6,387	$ 6,391	$ 8,419	12,281
Accounting Standards Update 2014-09 | Under Prior Rule
Revenues:
Revenues	117,893			289,828
Expenses:
Transportation expenses	20,693			41,058
Marketing expenses	22,766			46,369
Interest expense	420			824
Net income	6,977			77,695
Accounting Standards Update 2014-09 | Increase / (Decrease)
Revenues:
Revenues	18,465			35,567
Expenses:
Transportation expenses	520			(751)
Marketing expenses	17,561			35,713
Interest expense	164			164
Net income	220			441
Accounting Standards Update 2014-09 | Natural Gas Sales | Under Prior Rule
Revenues:
Revenues	53,285			117,794
Accounting Standards Update 2014-09 | Natural Gas Sales | Increase / (Decrease)
Revenues:
Revenues	377			(804)
Accounting Standards Update 2014-09 | Oil Sales | Under Prior Rule
Revenues:
Revenues	10,919			56,615
Accounting Standards Update 2014-09 | Oil Sales | Increase / (Decrease)
Revenues:
Revenues	0			0
Accounting Standards Update 2014-09 | NGL | Under Prior Rule
Revenues:
Revenues	22,280			50,222
Accounting Standards Update 2014-09 | NGL | Increase / (Decrease)
Revenues:
Revenues	143			53
Accounting Standards Update 2014-09 | Oil, Natural Gas and NGL Sales | Under Prior Rule
Revenues:
Revenues	86,484			224,631
Accounting Standards Update 2014-09 | Oil, Natural Gas and NGL Sales | Increase / (Decrease)
Revenues:
Revenues	520			(751)
Accounting Standards Update 2014-09 | Marketing | Under Prior Rule
Revenues:
Revenues	25,406			53,521
Accounting Standards Update 2014-09 | Marketing | Increase / (Decrease)
Revenues:
Revenues	17,561			35,713
Accounting Standards Update 2014-09 | Other Revenues | Under Prior Rule
Revenues:
Revenues	6,003			11,676
Accounting Standards Update 2014-09 | Other Revenues | Increase / (Decrease)
Revenues:
Revenues	$ 384			$ 605

XML

Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting Reorganization - Schedule of Components of Reorganization Items (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Reorganization Items
Gain on settlement of liabilities subject to compromise				$ 0	$ 0
Recognition of an additional claim for the Predecessor’s second lien notes settlement				0	0
Fresh start valuation adjustments				0	0
Income tax benefit related to implementation of the Plan				0	0
Legal and other professional fees		$ (1,255)	$ (3,128)	(5,698)	(3,207)
Terminated contracts				0	0
Other		(4)	69	74	(3)
Reorganization items, net		$ (1,259)	$ (3,059)	$ (5,624)	$ (3,210)
Predecessor
Reorganization Items
Gain on settlement of liabilities subject to compromise	$ 3,914,964
Recognition of an additional claim for the Predecessor’s second lien notes settlement	(1,000,000)
Fresh start valuation adjustments	(591,525)
Income tax benefit related to implementation of the Plan	264,889
Legal and other professional fees	(46,961)
Terminated contracts	(6,915)
Other	(13,315)
Reorganization items, net	$ 2,521,137

XML

Revenues - Schedule of Company's Disaggregated revenues (Details) - USD ($) $ in Thousands	3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 136,358	$ 262,105	$ 347,372	$ 325,395
Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	53,662			116,990
Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	10,919			56,615
NGL
Disaggregation of Revenue [Line Items]
Revenues	22,423			50,275
Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	87,004	243,167	323,492	223,880
Marketing
Disaggregation of Revenue [Line Items]
Revenues	42,967	12,547	15,461	89,234
Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	6,387	6,391	8,419	12,281
Hugoton Basin
Disaggregation of Revenue [Line Items]
Revenues	63,238			137,758
Hugoton Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	17,401			39,764
Hugoton Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	238			2,970
Hugoton Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues	16,875			36,389
Hugoton Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	34,514			79,123
Hugoton Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues	22,421			46,501
Hugoton Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	6,303			12,134
Mid-Continent
Disaggregation of Revenue [Line Items]
Revenues	15,834			38,702
Mid-Continent | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	7,622			15,555
Mid-Continent | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	4,880			16,747
Mid-Continent | NGL
Disaggregation of Revenue [Line Items]
Revenues	3,307			6,361
Mid-Continent | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	15,809			38,663
Mid-Continent | Marketing
Disaggregation of Revenue [Line Items]
Revenues	0			0
Mid-Continent | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	25			39
East Texas
Disaggregation of Revenue [Line Items]
Revenues	15,235			32,698
East Texas | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	12,661			27,437
East Texas | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	1,091			2,431
East Texas | NGL
Disaggregation of Revenue [Line Items]
Revenues	1,013			2,319
East Texas | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	14,765			32,187
East Texas | Marketing
Disaggregation of Revenue [Line Items]
Revenues	467			503
East Texas | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	3			8
Permian Basin
Disaggregation of Revenue [Line Items]
Revenues	330			25,525
Permian Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	256			2,282
Permian Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	546			20,654
Permian Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues	(488)			2,557
Permian Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	314			25,493
Permian Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues	0			0
Permian Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	16			32
Uinta Basin
Disaggregation of Revenue [Line Items]
Revenues	5,233			17,339
Uinta Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	2,146			5,526
Uinta Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	1,885			9,255
Uinta Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues	1,201			2,559
Uinta Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	5,232			17,340
Uinta Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues	0			0
Uinta Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	1			(1)
North Louisiana
Disaggregation of Revenue [Line Items]
Revenues	8,038			15,809
North Louisiana | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	6,040			12,418
North Louisiana | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	1,480			3,049
North Louisiana | NGL
Disaggregation of Revenue [Line Items]
Revenues	503			67
North Louisiana | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	8,023			15,534
North Louisiana | Marketing
Disaggregation of Revenue [Line Items]
Revenues	13			272
North Louisiana | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	2			3
Michigan/Illinois
Disaggregation of Revenue [Line Items]
Revenues	8,384			15,606
Michigan/Illinois | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	7,536			14,008
Michigan/Illinois | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	799			1,509
Michigan/Illinois | NGL
Disaggregation of Revenue [Line Items]
Revenues	12			23
Michigan/Illinois | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	8,347			15,540
Michigan/Illinois | Marketing
Disaggregation of Revenue [Line Items]
Revenues	0			0
Michigan/Illinois | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	37			66
Blue Mountain
Disaggregation of Revenue [Line Items]
Revenues	20,066	1,754	2,188	41,958
Blue Mountain | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	0			0
Blue Mountain | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	0			0
Blue Mountain | NGL
Disaggregation of Revenue [Line Items]
Revenues	0			0
Blue Mountain | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	0	0	0	0
Blue Mountain | Marketing
Disaggregation of Revenue [Line Items]
Revenues	20,066	1,754	2,188	41,958
Blue Mountain | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	$ 0	$ 0	$ 0	$ 0

XML

Revenues - Additional Information (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Revenue From Contract With Customer [Abstract]
Contract with Customer, Accounts Receivable	$ 56	$ 117

XML

Divestitures and Discontinued Operations - Additional Information (Details) - USD ($) $ in Thousands	Apr. 10, 2018	Apr. 04, 2018	Mar. 29, 2018	Feb. 28, 2018	Jun. 30, 2017	May 31, 2017	Jun. 30, 2018	Dec. 31, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Deposits							$ 3,170	$ 15,349
Assets held for sale							22	106,963
Liabilities held for sale							$ 0	43,302
New Mexico Assets Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses	$ 15,000
Gain (Loss) on Disposition of Oil and Gas Property	$ 11,000
Altamont Bluebell Assets Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses		$ 132,000
Gain (Loss) on Disposition of Oil and Gas Property		83,000
Costs Associated With Sale of Oil and Gas Property and Equipment		$ 2,000
West Texas Assets Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses			$ 107,000
Gain (Loss) on Disposition of Oil and Gas Property			55,000
Costs Associated With Sale of Oil and Gas Property and Equipment			$ 2,000
OK Waterfloods & TXPHS
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses				$ 112,000
Gain (Loss) on Disposition of Oil and Gas Property				46,000
Costs Associated With Sale of Oil and Gas Property and Equipment				$ 1,000
Deposits								$ 12,000
Salt Creek
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses					$ 76,000
Gain (Loss) on Disposition of Oil and Gas Property					$ 33,000
Jonah
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses						$ 560,000
Gain (Loss) on Disposition of Oil and Gas Property						270,000
Costs Associated With Sale of Oil and Gas Property and Equipment						$ 6,000

XML

Divestitures and Discontinued Operations - Disclosure of Long Lived Assets Held-for-sale (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
ASSETS
Oil and natural gas properties		$ 92,245
Other property and equipment		12,983
Other		1,735
Total assets held for sale	$ 22	106,963
Liabilities:
Asset retirement obligations		42,001
Other		1,301
Total liabilities held for sale	$ 0	$ 43,302

XML

Divestitures and Discontinued Operations - Summarized Statements of Operations (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues and other			$ 20,511	$ 27,636
Expenses			12,173	16,318
Other income and (expenses)			(2,074)	(2,791)
Income (loss) from discontinued operations before income taxes			6,264	8,527
Income tax expense			962	2,768
Income (loss) from discontinued operations, net of income taxes		$ 0	$ 5,302	$ 5,759	$ 0
Predecessor
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues and other	$ 14,891
Expenses	13,758
Other income and (expenses)	(1,681)
Income (loss) from discontinued operations before income taxes	(548)
Income (loss) from discontinued operations, net of income taxes	$ (548)

XML

Oil and Natural Gas Properties - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Proved properties	$ 739,656	$ 904,390
Unproved properties	46,159	45,693
Oil and natural gas properties (successful efforts method)	785,815	950,083
Less accumulated depletion and amortization	(59,870)	(49,619)
Oil and natural gas properties, successful efforts method, net	$ 725,945	$ 900,464

XML

Equity Method Investments - Additional Information (Details) - USD ($)	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Aug. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 473,269,000	$ 464,926,000
Roan Resources LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%	50.00%	50.00%
Equity method investments	$ 466,000,000	$ 458,000,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	355,000,000	$ 346,000,000
Impairments occurred on investment	$ 0

XML

Equity Method Investments - Summarized Roan Resources LLC Statements of Operations Information (Details) - Roan Resources LLC - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Schedule of Equity Method Investments [Line Items]
Revenues and other	$ 44,789	$ 145,873
Expenses	72,754	130,663
Other income and (expenses)	(1,087)	(2,886)
Net income (loss)	$ (29,052)	$ 12,324

XML

Debt - Additional Information (Details) - USD ($)		6 Months Ended
	Aug. 10, 2018	Jun. 30, 2018	Apr. 30, 2018	Aug. 04, 2017
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 500,000,000
Line of Credit Facility, Current Borrowing Capacity			$ 425,000,000
Long-term Line of Credit		$ 0
Line of Credit Facility, Remaining Borrowing Capacity		378,000,000
Letters of Credit Outstanding, Amount		$ 47,000,000
Line of credit facility joinder agreement date		Aug. 07, 2018
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages		85.00%
Debt to EBITDAX Ratio		400.00%
Current Ratio		100.00%
Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Line of Credit Facility, Interest Payment Term		Interest is generally payable in arrears on the last day of March, June, September and December for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of three month intervals during such interest period.
Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000,000
Line of Credit Facility, Current Borrowing Capacity	70,000,000
Long-term Line of Credit	$ 0
Line of Credit, Maturity Date	Aug. 10, 2023
Maximum Ratio of Consolidated Owners’ Equity Interest	35.00%
Minimum Ratio of Consolidated EBITDA to Consolidated Interest Expense	250.00%
Maximum Ratio of Consolidated Net Debt Secured by Lien on Property to Consolidated EBITDA	300.00%
Minimum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.375%
Maximum Ratio of Consolidated Net Debt to Consolidated EBITDA	450.00%
Maximum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Maximum Ratio of Consolidated Net Debt to Consolidated EBITDA	500.00%
London Interbank Offered Rate (LIBOR) | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.50%
London Interbank Offered Rate (LIBOR) | Minimum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%
London Interbank Offered Rate (LIBOR) | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
London Interbank Offered Rate (LIBOR) | Maximum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.00%
ABR | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
ABR | Minimum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
ABR | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.50%
ABR | Maximum | Subsequent Event | Blue Mountain Credit Facility | Blue Mountain Midstream
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%

XML

Derivatives - Schedule of Derivative Positions (Details) - Swap	Jun. 30, 2018 MMMBTU MBbls $ / MMBTU $ / bbl $ / MMMBTU
July 1 - December 31, 2018 | Natural Gas Commodity Contract
Derivative [Line Items]
Hedged volume (MMMBtu)	35,144
Average price ($/MMBtu) | $ / MMBTU	3.02
July 1 - December 31, 2018 | Oil Commodity Contract
Derivative [Line Items]
Hedged volume (MMMBtu) | MBbls	276
Average price ($/MMBtu) | $ / bbl	54.07
July 1 - December 31, 2018 | PEPL Basis Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	7,360	[1]
Hedge differential | $ / MMMBTU	(0.67)	[1]
July 1 - December 31, 2018 | NGPL Basis Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	1,840	[1]
Hedge differential | $ / MMMBTU	(0.19)	[1]
Year 2019 | Natural Gas Commodity Contract
Derivative [Line Items]
Hedged volume (MMMBtu)	22,265
Average price ($/MMBtu) | $ / MMBTU	2.89
Year 2019 | Oil Commodity Contract
Derivative [Line Items]
Hedged volume (MMMBtu) | MBbls	183
Average price ($/MMBtu) | $ / bbl	64.00
Year 2019 | PEPL Basis Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	14,600	[1]
Hedge differential | $ / MMMBTU	(0.67)	[1]
Year 2019 | NGPL Basis Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	0	[1]
Hedge differential | $ / MMMBTU	0	[1]

[1] Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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Derivatives - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Apr. 30, 2018	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Settlements on Canceled Derivatives	$ 20,000
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure						$ 7,000
Gains (losses) on oil and natural gas derivatives			$ (7,525)	$ 45,714	$ 33,755	(22,555)
Cash settlements on derivatives			$ (21,000)	$ 2,000	$ 7,929	$ (25,037)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on oil and natural gas derivatives		$ 92,691
Cash settlements on derivatives		$ (11,572)

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Derivatives - Summary of Fair Value of Derivatives Outstanding on Gross Basis (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Assets:
Commodity derivatives	$ 6,825	$ 22,589
Liabilities:
Commodity derivatives	$ 7,197	$ 25,443

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Fair Value Measurements on a Recurring Basis - Schedule of Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Assets:
Commodity derivatives		$ 6,825	$ 22,589
Commodity derivatives	[1]	(1,637)	(12,491)
Commodity derivatives		5,188	10,098
Liabilities:
Commodity derivatives		7,197	25,443
Commodity derivatives	[1]	(1,637)	(12,491)
Commodity derivatives		$ 5,560	$ 12,952

[1] Represents counterparty netting under agreements governing such derivatives.

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Asset Retirement Obligations - Schedule of Reconciliation of Company's Asset Retirement Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018 USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at December 31, 2017	$ 164,553
Liabilities added from drilling	53
Liabilities associated with assets divested	(62,195)
Current year accretion expense	4,081
Settlements	(1,859)
Revisions of estimates	2,386
Asset retirement obligations at June 30, 2018	$ 107,019

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Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Loss Contingency, Damages Sought, Value	$ 31,000
Payments for Legal Settlements	$ 0	$ 0

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Equity - Additional Information (Details) - Subsequent Event - USD ($)	Aug. 16, 2018	Aug. 07, 2018
Common Stock
Class Of Stock [Line Items]
Common stock, shares, issued		76,190,908
Common stock, shares, outstanding		76,190,908
Common stock, par value		$ 0.01
Common Stock | Maximum
Class Of Stock [Line Items]
Stock repurchase program, authorized amount	$ 100,000,000
Omnibus Incentive Plan | Restricted Stock Units (RSUs)
Class Of Stock [Line Items]
Unvested restricted stock units, granted		522,329

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Share-Based Compensation - Additional Information (Details) - USD ($)		6 Months Ended
	Aug. 07, 2018	Jun. 30, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of parent’s employee-related expenses		100.00%
Share-based payment liability		$ 111,792,000	$ 0
Authorized termination date of incentive plan by parent's board of directors		Aug. 02, 2018
LINN Energy
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Plan Modification, Incremental Compensation Cost		$ 18,000,000
LINN Energy | Class A Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, par value		$ 0.001
Stock Repurchased During Period, Shares	2,477,834
Stock repurchased during period, value	$ 102,000,000
Share-based payment liability		$ 112,000,000
LINN Energy | Liquidity program
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock Repurchased During Period, Shares		120,829
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards		$ 45,000,000
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	522,329
Restricted Stock Units (RSUs) | LINN Energy
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		12,500
Stock Issued During Period, Value, Restricted Stock Award, Gross		$ 519,000
Vesting period		3 years
Stock Repurchased During Period, Shares		271,314
Stock repurchased during period, value		$ 11,000,000
Restricted Stock Units (RSUs) | LINN Energy | Liquidity program
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock Repurchased During Period, Shares		1,028,875
Omnibus Incentive Plan | Common Stock | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement, Shares Available for Issuance	3,433,499

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Share-Based Compensation - Summary of Share-Based Compensation Expenses (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Income tax benefit		$ 4,315	$ 3,128	$ 3,555	$ 6,732
Predecessor
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Income tax benefit	$ 5,170
General and Administrative Expense
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share/unit-based compensation expenses		$ 58,188	$ 15,422	$ 19,599	$ 75,225
General and Administrative Expense | Predecessor
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share/unit-based compensation expenses	$ 50,255

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Earnings Per Share - Additional Information (Details) - shares	6 Months Ended
	Jun. 30, 2018	Aug. 07, 2018
Earnings Per Share Basic [Line Items]
Equity awards outstanding	0
LINN Energy
Earnings Per Share Basic [Line Items]
Stock split description	Each LINN Energy shareholder received one share of Riviera common stock for each share of LINN Class A common stock held by such LINN Energy shareholder at the close of business on August 7, 2018, the record date.
LINN Energy | Subsequent Event
Earnings Per Share Basic [Line Items]
Common stock, shares, issued		76,190,908

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Earnings Per Share - Reconciliation of Numerators and Denominators of Basic and Diluted Per Share Computations for Net Income (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Earnings Per Share Basic [Line Items]
Income from continuing operations		$ 7,197	$ 228,460	$ 222,337	$ 78,136
Income (loss) from discontinued operations, net of income taxes		0	5,302	5,759	0
Net income		$ 7,197	$ 233,762	$ 228,096	$ 78,136
Basic and diluted income from continuing operations per share		$ 0.09	$ 3.00	$ 2.91	$ 1.03
Basic and diluted income (loss) from discontinued operations per share		0	0.07	0.08	0
Basic and diluted earnings per share		$ 0.09	$ 3.07	$ 2.99	$ 1.03
Basic and diluted weighted average number of common shares outstanding		76,191	76,191	76,191	76,191
Predecessor
Earnings Per Share Basic [Line Items]
Income from continuing operations	$ 2,587,557
Income (loss) from discontinued operations, net of income taxes	(548)
Net income	$ 2,587,009
Basic and diluted income from continuing operations per share	$ 33.96
Basic and diluted income (loss) from discontinued operations per share	(0.01)
Basic and diluted earnings per share	$ 33.95
Basic and diluted weighted average number of common shares outstanding	76,191

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Income Taxes - Additional Information (Details)	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Income Tax [Line Items]
Effective Income Tax Rate Reconciliation, Percent		44.00%	41.00%	41.00%	37.00%
Blended Tax Rate					24.00%
Predecessor
Income Tax [Line Items]
Effective Income Tax Rate Reconciliation, Percent	0.00%

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Other current assets
Prepaids	$ 13,310	$ 43,150
Receivable from related party	25,982	23,163
Inventories	3,981	7,667
Other	2,487	2,703
Other current assets	$ 45,760	$ 76,683

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows - Schedule of Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Other accrued liabilities
Accrued compensation	$ 13,533	$ 29,089
Asset retirement obligations (current portion)	1,488	3,926
Deposits	3,170	15,349
Income taxes payable		7,009
Other	1,616	2,757
Other accrued liabilities	$ 19,807	$ 58,130

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows - Schedule of Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Feb. 28, 2017
Supplemental Disclosures To The Condensed Consolidated Statements Of Cash Flows [Abstract]
Cash and cash equivalents	$ 301,365	$ 464,477
Restricted cash	43,387	56,445
Cash, cash equivalents and restricted cash	$ 344,752	$ 520,922	$ 115,516	$ 144,022

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows - Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands	2 Months Ended	4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2017	Jun. 30, 2018
Schedule of supplemental cash flow disclosures [Line Items]
Cash payments for interest, net of amounts capitalized		$ 14,436	$ 0
Cash payments for income taxes		215	0
Cash payments for reorganization items, net		5,982	2,911
Noncash investing activities:
Accrued capital expenditures		$ 34,547	$ 21,968
Predecessor
Schedule of supplemental cash flow disclosures [Line Items]
Cash payments for interest, net of amounts capitalized	$ 17,651
Cash payments for income taxes	0
Cash payments for reorganization items, net	21,571
Noncash investing activities:
Accrued capital expenditures	$ 22,191

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated and Combined Statements of Cash Flows - Additional Information (Details) - USD ($) $ in Thousands	2 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Dec. 31, 2017
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		$ 43,387	$ 56,445
Predecessor
Schedule of supplemental cash flow disclosures [Line Items]
Increase (Decrease) in Restricted Cash for Operating Activities	$ 80,000
Professional fees
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		33,000	36,000
Deposits for divestitures
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		3,000	15,000
Other
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		$ 7,000	$ 5,000

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Related Party Transactions - Additional Information (Details) - Roan Resources LLC - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2018	Dec. 31, 2017	Aug. 31, 2017
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage					50.00%
Related party monthly fee	$ 1,000	$ 1,250	$ 5,000
Related Party Transaction, Purchases from Related Party	15,000		32,000
Revenue from Related Parties	26,000		26,000	$ 23,000
Due to Related Parties, Current	$ 11,000		$ 11,000	$ 18,000

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Segments - Additional Information (Details)	3 Months Ended
	Jun. 30, 2018 Segment
Segment Reporting [Abstract]
Number of reportable segments	2

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Segments - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Segment Reporting Information [Line Items]
Revenues		$ 136,358	$ 262,105	$ 347,372	$ 325,395
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		40,327	6,976	9,515	82,082
Taxes other than income taxes		7,115	17,871	24,948	15,567
Total direct operating expenses		92,743	133,292	181,261	209,928
Field level cash flow		43,615	128,813	166,111	115,467
Gains (losses) on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Other indirect income (expenses)		(23,283)	215,477	179,569	31,166
Income from continuing operations before income taxes		12,807	390,004	379,435	124,078
Predecessor
Segment Reporting Information [Line Items]
Revenues	$ 205,436
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,820
Taxes other than income taxes	14,877
Total direct operating expenses	95,334
Field level cash flow	110,102
Gains (losses) on oil and natural gas derivatives	92,691
Other indirect income (expenses)	2,384,598
Income from continuing operations before income taxes	2,587,391
Upstream
Segment Reporting Information [Line Items]
Revenues		116,292	260,351	345,184	283,437
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		20,244	6,156	8,513	41,380
Taxes other than income taxes		6,737	17,486	24,478	14,908
Total direct operating expenses		72,282	132,087	179,789	168,567
Field level cash flow		44,010	128,264	165,395	114,870
Upstream | Predecessor
Segment Reporting Information [Line Items]
Revenues	204,799
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,602
Taxes other than income taxes	14,773
Total direct operating expenses	95,012
Field level cash flow	109,787
Blue Mountain
Segment Reporting Information [Line Items]
Revenues		20,066	1,754	2,188	41,958
Marketing expenses		20,083	820	1,002	40,702
Taxes other than income taxes		285	116	155	477
Total direct operating expenses		20,368	936	1,157	41,179
Field level cash flow		(302)	818	1,031	779
Blue Mountain | Predecessor
Segment Reporting Information [Line Items]
Revenues	637
Marketing expenses	218
Taxes other than income taxes	78
Total direct operating expenses	296
Field level cash flow	341
Not Allocated to Segments
Segment Reporting Information [Line Items]
Taxes other than income taxes		93	269	315	182
Total direct operating expenses		93	269	315	182
Field level cash flow		(93)	(269)	(315)	(182)
Gains (losses) on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Other indirect income (expenses)		(23,283)	215,477	179,569	31,166
Not Allocated to Segments | Predecessor
Segment Reporting Information [Line Items]
Taxes other than income taxes	26
Total direct operating expenses	26
Field level cash flow	(26)
Gains (losses) on oil and natural gas derivatives	92,691
Other indirect income (expenses)	2,384,598
Oil, Natural Gas and NGL Sales
Segment Reporting Information [Line Items]
Revenues		87,004	243,167	323,492	223,880
Oil, Natural Gas and NGL Sales | Predecessor
Segment Reporting Information [Line Items]
Revenues	188,885
Oil, Natural Gas and NGL Sales | Upstream
Segment Reporting Information [Line Items]
Revenues		87,004	243,167	323,492	223,880
Oil, Natural Gas and NGL Sales | Upstream | Predecessor
Segment Reporting Information [Line Items]
Revenues	188,885
Oil, Natural Gas and NGL Sales | Blue Mountain
Segment Reporting Information [Line Items]
Revenues		0	0	0	0
Marketing
Segment Reporting Information [Line Items]
Revenues		42,967	12,547	15,461	89,234
Marketing | Predecessor
Segment Reporting Information [Line Items]
Revenues	6,636
Marketing | Upstream
Segment Reporting Information [Line Items]
Revenues		22,901	10,793	13,273	47,276
Marketing | Upstream | Predecessor
Segment Reporting Information [Line Items]
Revenues	5,999
Marketing | Blue Mountain
Segment Reporting Information [Line Items]
Revenues		20,066	1,754	2,188	41,958
Marketing | Blue Mountain | Predecessor
Segment Reporting Information [Line Items]
Revenues	637
Other Revenues
Segment Reporting Information [Line Items]
Revenues		6,387	6,391	8,419	12,281
Other Revenues | Predecessor
Segment Reporting Information [Line Items]
Revenues	9,915
Other Revenues | Upstream
Segment Reporting Information [Line Items]
Revenues		6,387	6,391	8,419	12,281
Other Revenues | Upstream | Predecessor
Segment Reporting Information [Line Items]
Revenues	$ 9,915
Other Revenues | Blue Mountain
Segment Reporting Information [Line Items]
Revenues		$ 0	$ 0	$ 0	$ 0