Edgar Filing: ROAN RESOURCES, INC.

Document



	UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
	Washington, D.C. 20549



	FORM 10-Q

x QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2018

¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES

EXCHANGE ACT OF 1934

For the transition period from __________ to ___________

Commission File Number: 001-32720



	Roan Resources, Inc.
	(Exact Name of Registrant as Specified in its Charter)

Delaware		83-1984112
(State or Other Jurisdiction of Incorporation)		(IRS Employer Identification No.)

14701 Hertz Quail Springs Pkwy Oklahoma City, OK		73134
(Address of Principal Executive Offices)		(Zip Code)
(405) 896-8050
(Registrant’s Telephone Number, including Area Code)

Linn Energy, Inc. 600 Travis Street Houston, Texas 77002
(Former Name or Former Address, 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 past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 12 b-2 of the Exchange Act. (Check One):



Large Accelerated Filer ¨		Accelerated Filer ¨
Non-Accelerated Filer x		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 x

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 x No ¨

As of November 9, 2018, there were 152,539,532 shares of Class A common stock, par value $0.001 per share, outstanding.

TABLE OF CONTENTS



Cautionary Note Regarding Forward-Looking Statements			1
Glossary of Oil and Natural Gas Terms			2

PART I - FINANCIAL INFORMATION
	Item 1. Financial Statements		5
		Condensed Consolidated Balance Sheets	5
		Condensed Consolidated Statements of Operations	6
		Condensed Consolidated Statement of Changes in Equity	7
		Condensed Consolidated Statements of Cash Flows	8
		Notes to Condensed Consolidated Financial Statements	10
	Item 2. Management's Discussion and Analysis of Financial Condition and Result of Operations		27
	Item 3. Quantitative and Qualitative Disclosures About Market Risk		44
	Item 4. Controls and Procedures		45
PART II - OTHER INFORMATION
	Item 1. Legal Proceedings		47
	Item 1A. Risk Factors		47
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		48
	Item 3. Defaults Upon Senior Securities		48
	Item 4. Mine Safety Disclosure		48
	Item 5. Other Information		48
	Item 6. Exhibits		49
	Signatures		51

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (the “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” in our Current Report on Form 8-K filed with the Securities and Exchange Commission (the “SEC”) on September 24, 2018 (the “Current Report”) and in Part II, Item 1A. “Risk Factors” of this Quarterly Report.

Forward-looking statements may include statements about:


•	our business strategy;


•	our reserves;


•	our drilling plans, prospects, inventories, projects and programs;


•	our ability to replace the reserves we produce through drilling and property acquisitions;


•	our financial strategy, liquidity and capital required for our drilling program and timing related thereto;


•	our realized oil, natural gas and NGL prices;


•	the timing and amount of our future production of oil, natural gas and NGLs;


•	our competition and government regulations;


•	our ability to obtain permits and governmental approvals;


•	our pending legal or environmental matters;


•	our marketing of oil, natural gas and NGLs;


•	our leasehold or business acquisitions;


•	our costs of developing our properties;


•	our hedging strategy and results;


•	general economic conditions;


•	credit markets;


•	uncertainty regarding our future operating results including initial production values and liquid yields in our type curve areas;


•	the costs, terms and availability of gathering, processing, fractionation and other midstream services; and


•	our plans, objectives, expectations and intentions that are not historical.

These forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incidental to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in Part II, Item 1A. “Risk Factors” of this Quarterly Report.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.

Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Btu. British thermal unit.

Completion. Preparation of a well bore and installation of permanent equipment for production of oil, natural gas or NGLs or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. For a complete definition of development costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(7).

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held by production. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.

Liquids. Describes oil, condensate and natural gas liquids.

MBbl. One thousand barrels of crude oil, condensate or NGLs.

MBoe. One thousand Boe.

MBoe/d. One thousand Boe per day.

Mcf. One thousand cubic feet of natural gas.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

Net acres. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% working interest in 100 acres owns 50 net acres.

Net production. Production that is owned by us less royalties and production due to others.

NGLs or Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

NYMEX. The New York Mercantile Exchange.

Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.

Play. A geographic area with hydrocarbon potential.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through (i) existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved properties. Properties with proved reserves.

Proved reserves. Those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

Proved undeveloped reserves or PUDs. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Realized price. The cash market price less all expected quality, transportation and demand adjustments.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Success rate. The percentage of wells drilled which produce hydrocarbons in commercial quantities.

Unproved properties. Properties with no proved reserves.

Wellbore. The hole drilled by the bit that is equipped for oil, natural gas and NGL production on a completed well. Also called well or borehole.

Working interest. The right granted to the lessee of a property to develop and produce and own natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Roan Resources, Inc.

Condensed Consolidated Balance Sheets (Unaudited)



	September 30, 2018			December 31, 2017
	(in thousands, except par value and share data)
ASSETS
Current assets
Cash and cash equivalents	$	3,900		$	1,471
Accounts receivable
Oil, natural gas and natural gas liquid sales	47,365			74,527
Affiliates	14,689			4,695
Joint interest owners and other	110,991			320
Prepaid drilling advances	49,279			—
Derivative contracts	203			152
Other current assets	6,412			930
Total current assets	232,839			82,095
Noncurrent assets
Oil and natural gas properties, successful efforts method	2,429,892			1,876,951
Accumulated depreciation, depletion, amortization and impairment	(183,557		)	(78,307		)
Oil and natural gas properties, net	2,246,335			1,798,644
Other property and equipment, net	2,935			1,147
Deferred financing costs	4,417			2,710
Derivative contracts	—			996
Total assets	$	2,486,526		$	1,885,592
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	198,020		$	10,245
Accounts payable and accrued liabilities – Affiliates	7,748			183,820
Revenue payable	88,029			—
Drilling advances	57,374			—
Derivative contracts	64,261			9,279
Asset retirement obligations	535			—
Total current liabilities	415,967			203,344
Noncurrent liabilities
Long-term debt	394,639			85,339
Deferred tax liabilities	299,662			—
Asset retirement obligations	12,876			10,769
Derivative contracts	18,901			1,371
Other	662			—
Total liabilities	1,142,707			300,823
Commitments and contingencies (Note 14)
Equity
Common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at September 30, 2018	153			—
Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at September 30, 2018	—			—
Additional paid-in capital	1,643,431			—
Accumulated deficit	(299,765		)	—
Members’ equity	—			1,584,769
Total equity	1,343,819			1,584,769
Total liabilities and equity	$	2,486,526		$	1,885,592

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

Roan Resources, Inc.

Condensed Consolidated Statements of Operations (Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands, except per share amounts)
Revenues
Oil sales	$	74,987		$	16,701		$	197,356		$	45,702
Natural gas sales	10,442			11,818			31,900			29,857
Natural gas sales – Affiliates	7,617			1,027			17,056			1,027
Natural gas liquid sales	12,983			9,224			38,127			21,199
Natural gas liquid sales – Affiliates	14,123			850			27,250			850
(Loss) gain on derivative contracts	(36,704		)	131			(100,920		)	2,385
Total revenues	83,448			39,751			210,769			101,020
Operating Expenses
Production expenses	14,737			4,336			30,111			10,450
Gathering, transportation and processing	—			4,890			—			11,360
Production taxes	6,210			847			10,892			2,057
Exploration expenses	11,646			4,229			30,129			4,475
Depreciation, depletion, amortization and accretion	37,164			10,824			83,630			22,176
General and administrative	13,177			4,489			40,283			22,062
Gain on sale of oil and natural gas properties	—			(838		)	—			(838		)
Total operating expenses	82,934			28,777			195,045			71,742
Total operating income	514			10,974			15,724			29,278
Other income (expense)
Interest expense, net	(2,092)			(264)			(4,978)			(441)
Net (loss) income before income taxes	(1,578		)	10,710			10,746			28,837
Income tax expense	299,662			—			299,662			—
Net (loss) income	$	(301,240	)	$	10,710		$	(288,916	)	$	28,837
Earnings (loss) per share
Basic	$	(1.97	)	$	0.11		$	(1.90	)	$	0.35
Diluted	$	(1.97	)	$	0.11		$	(1.90	)	$	0.35
Weighted average number of shares outstanding
Basic	152,540			99,859			152,129			83,578
Diluted	152,540			99,859			152,129			83,578

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

Roan Resources, Inc.

Condensed Consolidated Statement of Changes in Equity (Unaudited)



	Stockholders' Equity
	Common Stock (Shares)	Common Stock		Additional Paid-in Capital		Accumulated Deficit			Members' Equity			Total Equity
	(in thousands)
Balance at December 31, 2017	—	$	—	$	—	$	—		$	1,584,769		$	1,584,769
Acquisition of oil and natural gas properties in exchange for equity units	—	—		—		—			39,906			39,906
Equity-based compensation ⁽¹⁾	—	—		192		—			7,868			8,060
Net loss ⁽¹⁾	—	—		—		(299,765		)	10,849			(288,916		)
Issuance of common stock upon Reorganization	152,540	153		1,643,239		—			(1,643,392		)	—
Balance at September 30, 2018	152,540	$	153	$	1,643,431	$	(299,765	)	$	—		$	1,343,819

⁽¹⁾ Amounts are allocated to stockholders' equity and members' equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.

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

Roan Resources, Inc.

Condensed Consolidated Statements of Cash Flows (Unaudited)



	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Cash flows from operating activities
Net (loss) income	$	(288,916	)	$	28,837
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	83,630			22,176
Unproved leasehold amortization and impairment and dry hole expense	25,642			4,475
Gain on sale of oil and natural gas properties	—			(838		)
Amortization of deferred financing costs	571			39
Amortization of deferred rent	662			—
Loss (gain) on derivative contracts	100,920			(2,385		)
Net cash (paid) received upon settlement of derivative contracts	(27,462		)	2,385
Equity-based compensation	8,060			—
Deferred income taxes	299,662			—
Other	(111		)	(8		)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable – Oil, natural gas and natural gas liquid sales	27,162			(10,820		)
Accounts receivable – Affiliates	(9,994		)	(1,877		)
Accounts receivable – Joint interest owners and other	(110,671		)	(8,410		)
Prepaid drilling advances	(55,815		)	—
Other current assets	(5,398		)	(1,805		)
Accounts payable and accrued liabilities	37,773			37,816
Accounts payable and accrued liabilities – Affiliates	(24,474		)	1,913
Drilling advances	57,374			(25,363		)
Revenue payable	88,029			13,113
Net cash provided by operating activities	206,644			59,248
Cash flows from investing activities
Acquisition of oil and natural gas properties	(22,935		)	(42,701		)
Capital expenditures for oil and natural gas properties	(485,580		)	(138,152		)
Acquisition of other property and equipment	(2,353		)	(153		)
Proceeds from sale of oil and natural gas properties	—			1,435
Purchase of investment	—			(3,000		)
Net cash used in investing activities	(510,868		)	(182,571		)
Cash flows from financing activities
Proceeds from borrowings	309,300			75,340
Repayment of borrowings	—			(40,000		)
Deferred financing costs	(2,279		)	(2,340		)
Deferred offering costs	(368		)	—
Contributions from Citizen members	—			95,557
Distributions to Citizen members	—			(11,147		)
Net cash provided by financing activities	306,653			117,410
Net increase (decrease) in cash and cash equivalents	2,429			(5,913		)
Cash and cash equivalents, beginning of period	1,471			6,853
Cash and cash equivalents, end of period	$	3,900		$	940

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

Roan Resources, Inc.

Condensed Statements of Cash Flows (Unaudited), continued



	Nine Months Ended September 30,
	2018		2017
	(in thousands)
Supplemental disclosure of cash flow information
Cash paid for interest, net of capitalized interest	$	4,024	$	341
Supplemental disclosure of non-cash investing and financing activities
Change in accrued capital expenditures	$	38,593	$	22,456
Acquisition of oil and natural gas properties for equity	$	39,906	$	1,281,743
Distribution to Citizen Members of assets and liabilities	$	—	$	(74,467	)

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

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1 – Business and Organization

Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a series of transactions were executed with Roan LLC's members which resulted in Roan LLC becoming a wholly owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Reorganization” and Roan Inc. with its subsidiaries are collectively referred to as the “Company.” See Note 10 – Equity for further discussion of the Reorganization transaction. The accompanying historical financial statements through the date of Reorganization are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc.

Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, the Company executed a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to the Company (collectively the “Contribution”). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in the Company.

The contributions of oil and natural gas properties to Roan LLC by Citizen and Linn were determined to meet the definition of a business. However, as Roan LLC had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC Topic 805, Business Combinations (“ASC 805”). As a result, the information in the accompanying financial statements and footnotes for the period prior to the Contribution reflects the historical results of Citizen. Citizen was formed in July 2014 to engage in the acquisition, exploration, development, production, and sale of oil and natural gas properties located in Central Oklahoma. Subsequent to the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan LLC and after the Reorganization, the results of Roan Inc. See Note 4 – Acquisitions for additional discussion of the business combination of the oil and natural gas properties contributed by Linn. In conjunction with the Contribution Agreement, the Company entered into master services agreements with both Citizen and Linn (“MSAs”). See Note 12 –Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.

The Company was formed to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma.

Note 2 – Summary of Significant Accounting Policies

For a description of the Company’s significant accounting policies, refer to Note 2 to the Company’s 2017 audited financial statements included in the Current Report. The accompanying condensed consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

Principles of Consolidation

The condensed consolidated financial statements of the Company include the accounts of Roan Inc. and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Interim Financial Statements

The accompanying condensed consolidated financial statements as of December 31, 2017 were derived from the annual financial statements included in the Current Report. The unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2018 and 2017 were prepared by the Company in accordance with the accounting policies stated in the audited financial statements. In the opinion of management, the Company’s unaudited condensed consolidated financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and disclosures normally included in financial statements prepared in conformity with GAAP have been consolidated or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s annual financial statements and notes thereto.

Income Taxes

The Company is a corporation and therefore a taxable entity. As a result of the Reorganization, the Company recorded a deferred tax liability based on the change in tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxes for further information on the Company’s taxes.

Use of Estimates

The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Recent Accounting Standards Issued

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). This guidance supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (“ASU 2016-08”), pertaining to the presentation of revenues on a gross basis

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

(revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. Effective January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition under which the standard is applied only to the most current period presented. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. See Note 3 – Revenue from Contracts with Customers for discussion of the impact upon adoption and the additional disclosures.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for fiscal years beginning after December 15, 2018, including interim reporting periods within those fiscal years, with early application permitted. The Company enters into lease agreements to support its operations, such as office space, vehicles and drilling rigs. ASU 2016-02 will not impact the accounting or financial presentation of the Company’s mineral leases. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11 Leases (Topic 842): Targeted Improvements, and therefore will apply the new standard as of January 1, 2019 and will recognize a cumulative-effect adjustment to the opening balance of retained earnings, if any, upon adoption in lieu of retrospectively applying the new standard to periods before adoption. The Company is working to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies, and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures.

Note 3 – Revenue from Contracts with Customers

The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company’s presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue Recognition (“ASC 605”):



	Three Months Ended September 30, 2018									Nine Months Ended September 30, 2018
	Under ASC 606			Under ASC 605			Increase/ (decrease)			Under ASC 606			Under ASC 605			Increase/ (decrease)
	(in thousands)
Revenues
Oil sales	$	74,987		$	75,062		$	(75	)	$	197,356		$	197,431		$	(75	)
Natural gas sales	$	18,059		$	21,739		$	(3,680	)	$	48,956		$	60,919		$	(11,963	)
Natural gas liquid sales	$	27,106		$	35,195		$	(8,089	)	$	65,377		$	83,735		$	(18,358	)

Operating expenses
Gathering, transportation and processing	$	—		$	11,844		$	(11,844	)	$	—		$	30,396		$	(30,396	)

Net loss	$	(301,240	)	$	(301,240	)	$	—		$	(288,916	)	$	(288,916	)	$	—

Oil Sales

Most of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received.

Natural Gas and NGL Sales

Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas.

For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts.

Performance Obligations

The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred.

The Company’s oil sales contracts 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, which provides an exemption 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 natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 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.

Contract Balances

The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $62.1 million as of September 30, 2018, which represent this unconditional right to receive payment.

Prior Period Performance Obligations

To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the three and nine months ended September 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Note 4 – Acquisitions

Linn Acquisition

As noted in Note 1 – Business and Organization, in connection with the Contribution, Roan LLC acquired from Linn certain oil and natural gas properties located in Central Oklahoma (the “Linn Acquisition”). In exchange for the contributed oil and natural gas properties, Linn received a 50% equity interest in Roan LLC valued at approximately $1.3 billion based on the value of the business. Accordingly, the fair value of the Company was primarily comprised of the fair value of these contributed oil and natural gas properties. See Note 10 – Equity for further discussion of the equity issued to Linn.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Because the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties:



Discount rate	9.50	%
Reserve risk factor ⁽¹⁾	35%-100%
Oil price	three years NYMEX WTI forward curve
Natural gas price	three years NYMEX Henry Hub forward curve
NGL price	39% of oil price
Price escalation ⁽²⁾	2.00	%
⁽¹⁾ Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%.
⁽²⁾ Prices were escalated at the end of the forward curve

The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands):



Consideration given
Equity units	$	1,281,743
Allocation of purchase price
Inventory	$	205
Proved oil and natural gas properties	214,647
Unproved oil and natural gas properties	1,086,600
Total assets acquired	1,301,452
Asset retirement obligations	(7,547		)
Revenue suspense	(12,162		)
Total fair value of net assets acquired	$	1,281,743

The following unaudited pro forma combined results of operations is provided for the three and nine months ended September 30, 2017 as though the Linn Acquisition had been completed as of the earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition.



	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(in thousands)
Revenue	$	55,119	$	156,593
Net income	$	17,052	$	55,253

Acquisitions of Unproved Properties

During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties.

As discussed in Note 12 –Transactions with Affiliates, Citizen and Linn acquired acreage during 2017 on behalf of Roan LLC for $63.0 million, which was included in accounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, Roan LLC paid Linn $22.9 million in cash and issued equity units to both Citizen and Linn to settle the amount due.

Note 5 – Oil and Natural Gas Properties

The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following:



	September 30, 2018			December 31, 2017
	(in thousands)
Oil and natural gas properties
Proved	$	1,276,950		$	750,492
Unproved	1,152,942			1,126,459
Less: accumulated depreciation, depletion, amortization and impairment	(183,557		)	(78,307		)
Oil and natural gas properties, net	$	2,246,335		$	1,798,644

The Company recorded depletion expense on capitalized oil and natural gas properties of $36.7 million and $10.7 million for the three months ended September 30, 2018 and 2017, respectively, and $82.4 million and $22.0 million for the nine months ended September 30, 2018 and 2017, respectively.

For the three and nine months ended September 30, 2018, the Company recorded amortization expense on its unproved oil and natural gas properties of $11.2 million and $25.6 million, respectively, which is reflected in exploration expense on the accompanying condensed consolidated statements of operations. There was no such expense recorded for the three and nine months ended September 30, 2017. Unproved leasehold

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

amortization for the three and nine months ended September 30, 2018 reflects consideration of the Company’s drilling plans and the lease terms of its existing unproved properties. For the three and nine months ended September 30, 2017, the Company recorded impairment expense on its unproved oil and natural gas properties of $4.2 million and $4.5 million, respectively, for leases which expired. No impairment of proved oil and natural gas properties was recorded for the three and nine months ended September 30, 2018.

Note 6 – Asset Retirement Obligations

The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the nine months ended September 30, 2018 (in thousands):



Asset retirement obligation, December 31, 2017	$	10,769
Liabilities incurred or acquired	1,815
Revisions in estimated cash flows	318
Liabilities settled	(111		)
Accretion expense	620
Asset retirement obligation, September 30, 2018	13,411
Less: current portion of obligations	535
Asset retirement obligation – long term	$	12,876

Note 7 – Long-Term Debt

In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of September 30, 2018, the Company had $394.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. The 2017 Credit Facility is secured by substantially all of the assets of the Company.

The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and alternate base rate (“ABR”) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375%.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement):



Utilization Level	Utilization	LIBOR Margin	Applicable Margin	Commitment Fee
Level I	<25%	2.00%	1.00%	0.375%
Level II	>25% but <50%	2.25%	1.25%	0.375%
Level III	>50% but <75%	2.50%	1.50%	0.500%
Level IV	>75% but <90%	2.75%	1.75%	0.500%
Level V	>90%	3.00%	2.00%	0.500%

The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report.

The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of September 30, 2018, the Company was in compliance with the covenants under the 2017 Credit Facility.

Prior to the 2017 Credit Facility, Citizen had a two-year, $500.0 million credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of $82.5 million. In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid.

Note 8 – Derivative Instruments

The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, or Panhandle Eastern Pipeline. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume.

The following table reflects the Company’s open commodity contracts at September 30, 2018:



	2018		2019		2020		Total
Oil fixed price swaps
Volume (Bbl)	1,233,180		5,540,670		1,599,500		8,373,350
Weighted-average price	$	57.09	$	59.86	$	63.14	$	60.08
Natural gas fixed price swaps
Volume (MMBtu)	8,004,000		29,200,000		12,325,000		49,529,000
Weighted-average price	$	2.94	$	2.86	$	2.63	$	2.81
Natural gas basis swaps
Volume (MMBtu)	4,600,000		21,900,000		3,640,000		30,140,000
Weighted-average price	$	0.54	$	0.58	$	0.62	$	0.58

The Company nets the fair value of derivative instruments by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. See Note 9 – Fair Value Measurements for further information regarding the fair value measurement of the Company’s derivatives.

As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in (loss) gain on derivative contracts included in the consolidated statement of operations.

The following table presents the Company’s (loss) gain on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the three and nine months ended September 30, 2018 and 2017:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(in thousands)
(Loss) gain on derivative contracts	$	(36,704	)	$	131	$	(100,920	)	$	2,385
Net cash (paid) received upon settlement of derivative contracts	$	(13,551	)	$	2,255	$	(27,462	)	$	2,385
Net cash received upon settlement of derivative contracts prior to contractual maturity	$	—		2,255		$	377		$	2,255

Note 9 – Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.

Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the three and nine months ended September 30, 2018, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company's recurring fair value measurements are performed for its commodity derivatives.

Commodity Derivative Instruments

Commodity derivative contracts are stated at fair value in the accompanying condensed consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors.

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of September 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):



	September 30, 2018
	Level 1		Level 2			Level 3		Gross Fair Value			Netting			Carrying Value
Assets
Current commodity derivatives	$	—	$	4,282		$	—	$	4,282		$	(4,079	)	$	203
Noncurrent commodity derivatives	—		908			—		908			(908		)	—
Total assets	$	—	$	5,190		$	—	$	5,190		$	(4,987	)	$	203
Liabilities
Current commodity derivatives	$	—	$	(68,340	)	$	—	$	(68,340	)	$	4,079		$	(64,261	)
Noncurrent commodity derivatives	—		(19,809		)	—		(19,809		)	908			(18,901		)
Total liabilities	$	—	$	(88,149	)	$	—	$	(88,149	)	$	4,987		$	(83,162	)

	December 31, 2017
	Level 1		Level 2			Level 3		Gross Fair Value			Netting			Carrying Value
Assets
Current commodity derivatives	$	—	$	2,856		$	—	$	2,856		$	(2,704	)	$	152
Noncurrent commodity derivatives	—		2,182			—		2,182			(1,186		)	996
Total assets	$	—	$	5,038		$	—	$	5,038		$	(3,890	)	$	1,148
Liabilities
Current commodity derivatives	$	—	$	(11,983	)	$	—	$	(11,983	)	$	2,704		$	(9,279	)
Noncurrent commodity derivatives	—		(2,557		)	—		(2,557		)	1,186			(1,371		)
Total liabilities	$	—	$	(14,540	)	$	—	$	(14,540	)	$	3,890		$	(10,650	)

Non-Recurring Fair Value Measurements

The Company’s non‑recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations and the determination of the grant date fair value of the Company’s performance share units. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to Note 4 – Acquisitions and Note 11 – Equity Compensation for additional discussion.

Other Financial Instruments

The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates.

Note 10 – Equity

In September 2018 and in conjunction with the Reorganization, the Company issued 152.5 million shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented.

For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the "LLC Units") for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn.

As discussed in Note 4 – Acquisitions, Citizen and Linn acquired acreage during 2017 on Roan LLC’s behalf. In March 2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn for the additional leasehold acreage.

For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Class A and Class B members pro rata in accordance with their membership interests; however, once the Class A members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

Note 11 – Equity Compensation

The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards.

Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs.

The following table summarizes information related to the total number of PSUs awarded as of September 30, 2018:



	Number of PSUs		Weighted Average Fair Value		Total Fair Value ($ in thousands)
PSUs outstanding at December 31, 2017	16,350,000		$	1.41	$	23,054
PSUs granted	6,825,000		$	1.88	$	12,810
PSUs vested	—		$	—	$	—
Conversion ⁽¹⁾	(22,016,250	)	$	—	$	—
PSUs outstanding at September 30, 2018	1,158,750		$	30.95	$	35,864

⁽¹⁾ PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification.

Compensation expense associated with the PSUs for the three and nine months ended September 30, 2018 was $2.9 million and $8.1 million, respectively, and is included in general and administrative expenses on the accompanying condensed consolidated statements of operations. Unrecognized expense as of September 30, 2018 for all outstanding PSU awards was $27.4 million and will be recognized over a weighted-average remaining period of 2.25 years. Under the treasury stock method, the PSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying condensed consolidated statements of operations.

The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date.

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the following periods:



	Six Months Ended June 30, 2018			Three Months Ended September 30, 2018
Company enterprise value (in billions)	$	4.56		$	4.19
Equity volatility	34.0		%	36.0		%
Weighted average risk-free interest rate	1.96		%	2.54		%

Note 12 –Transactions with Affiliates

Management Service Agreements

Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn.

For the nine months ended September 30, 2018, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying condensed consolidated statements of operations. Since the MSA ended in April 2018, there were no such charges related to the MSA in the three months ended September 30, 2018.

Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets. At December 31, 2017, the Company had $19.0 million due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying condensed consolidated balance sheets.

Acquisition of Acreage

As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. See Note 4 – Acquisitions and Note 10 – Equity for further discussion of the settlement of the payable due to Citizen and Linn related to the additional acquired acreage.

Natural Gas Dedication Agreement

The Company has a gas dedication agreement with Blue Mountain Midstream LLC (“Blue Mountain”), a subsidiary of Riviera Resources, Inc. (“Riviera”), which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at September 30, 2018 and December 31, 2017 are reflected as accounts receivable – affiliates in the accompanying condensed consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying condensed consolidated statements of operations. See further discussion of this gas dedication agreement in Note 14 – Commitments and Contingencies.

Corporate Office Lease

During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years. The Company paid $0.4 million during the nine months ended September 30, 2018 under this lease. Total remaining payments under the lease are $8.3 million.

Tax Matters Agreement

In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See Note 13 – Income Taxes for further discussion of the TMA and the related payable to Riviera.

Roan Resources LLC
Notes to Financial Statements

Note 13 – Income Taxes

As discussed in Note 1 – Business and Organization, the Company was formed in September 2018 in connection with the Reorganization. The Company’s accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members.

A deferred tax liability was recorded as a result of the Reorganization based on the Company being taxable as a corporation under the Internal Revenue Code of 1986, as amended. The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization.

The Company records its quarterly tax provision based on an estimate of the annual effective tax rate expected to apply to continuing operations for the various jurisdictions in which it operates. The tax effects of certain items, such as tax rate changes, significant unusual or infrequent items, and certain changes in the assessment of the realizability of deferred taxes, are recognized as discrete items in the period in which they occur and are excluded from the estimated annual effective tax rate.

The Company’s effective combined U.S. federal and state income tax rate for the nine months ended September 30, 2018 excluding discrete items was 25.5%. During the third quarter of 2018, the Company recognized income tax expense of $299.7 million, primarily representing the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization.

In conjunction with the Reorganization, the Company entered into a TMA with Riviera. The TMA, in part, provides for indemnification of the Company and entitlement of refunds by Riviera of certain taxes related to Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an estimated overpayment of federal taxes by Linn Energy, Inc., the Company has recorded a $7.7 million income tax receivable and a payable of $7.7 million to Riviera at September 30, 2018. The receivable is included in accounts receivable - other and the payable is included in accounts payable and accrued liabilities - affiliates in the accompanying condensed consolidated balance sheets.

The Company’s deferred tax liabilities as of September 30, 2018 include the following (in thousands):



Deferred income tax assets (liabilities):
Oil and natural gas properties	$	(322,911	)
Derivative contracts	22,530
Other	719
Deferred tax liabilities, net	$	(299,662	)

Roan Resources, Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 14 – Commitments and Contingencies

Litigation

In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At September 30, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.

Natural Gas Dedication Agreements

The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement.

Volume Commitment

Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. If the Company was unable to deliver any additional natural gas volumes, it would owe deficiency fees of $8.6 million as of September 30, 2018. Based on natural gas volumes delivered as of September 30, 2018, current production from producing wells and expected production from wells planned to be drilled in the specified area, the Company expects to meet the required minimum volume commitment.

Note 15 – Subsequent Events

Subsequent to September 30, 2018, the Company entered into fixed price swaps for 2,500 Bbls per day of NGL production at a weighted average price of $34.03 for the period of October 2018 to December 2019 and for 20,000 Mcf per day of natural gas production at a weighted average price of $2.93 for the period of January 2019 to December 2019.

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

The following discussion and analysis of the financial condition and results of the Company should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this report as well as our audited consolidated financial statements and notes included in our Current Report on Form 8-K filed September 24, 2018. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are subject to risk and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and NGLs. Please refer to Part II, Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for additional information regarding these risks and uncertainties. In light of these risks and uncertainties, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Roan Inc. was incorporated in September 2018 to serve as a holding company, and prior to the Reorganization, had no previous operations, assets or liabilities. The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to August 31, 2017, the date of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas properties contributed by Linn.

Overview

We are an independent oil and natural gas company focused on the development of our assets throughout the eastern and southern Anadarko Basin. The Anadarko Basin, which spans from south-central Oklahoma to the northeast corner of the Texas panhandle, is one of the largest and most prolific onshore oil and natural gas basins in the United States, featuring multiple producing horizons and extensive well production history demonstrated over seven decades of development. We focus our development on formations where we believe we can apply our technical and operational expertise in order to increase production and cash flow to deliver compelling economic rates of return on a risk adjusted basis. Our objective is to maximize shareholder value and corporate returns by generating steady production growth, strong pre-tax margins and significant cash flow.

Our primary developmental focus is on our Merge acreage position in Canadian, Grady and McClain counties in Central Oklahoma. We are one of the most active operators in Oklahoma, with eight rigs actively operating as of September 30, 2018, all of which are focused on drilling horizontal well laterals in the Merge and SCOOP plays. Our acreage position is concentrated in what we believe are the oil and liquids-rich fairways of the Merge play and provides us development opportunities through multiple stacked prospective development horizons.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:


•	actual and projected reserve and production levels;


•	realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;


•	lease operating expenses; and


•	capital expenditures on our oil and natural gas properties.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Corporate Reorganization

On September 24, 2018, we completed the Reorganization, where Roan LLC, our accounting predecessor, became a wholly owned subsidiary of Roan Inc. Roan Inc. was incorporated to serve as a holding company and, prior to the Reorganization, had no previous operations, assets or liabilities. For more information on our Reorganization, please see Note 1 – Business and Organization.

The historical financial and operating information included in this Quarterly Report, (i) on and after September 24, 2018, is that of Roan Inc., and (ii) prior to September 24, 2018, is the information of Roan LLC, our accounting predecessor. The historical financial and operating information of Roan LLC presented here, (i) prior to August 31, 2017, the date of the completion of the Contribution is that of Citizen, the predecessor of Roan LLC for financial reporting purposes and (ii) on and after August 31, 2017, is that of Roan LLC. Therefore, the operating information of Citizen prior to August 31, 2017 does not include financial information relating to the oil and natural gas properties contributed by Linn.

Income Taxes

As a result of the Reorganization, we became subject to federal and state tax. Due to the change in tax status, we have recorded a tax provision for the initial recording of the deferred tax liability recognized as a result of the Reorganization. Our accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for federal income tax purposes, were deemed to pass to the members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of the members.

Impact of ASC Topic 606 Adoption

Revenue for the three and nine months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. For a discussion of the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standards, see Note 3 – Revenue from Contracts with Customers.

Financial and Operational Performance

Our financial and operational performance for the nine months ended September 30, 2018 included the following highlights:


•	Net loss was $288.9 million for the nine months ended September 30, 2018, as compared to net income of $28.8 million for the nine months ended September 30, 2017. The net loss was primarily due to:


•	$100.9 million loss on derivative contracts during the nine months ended September 30, 2018 as a result of increases in oil prices during this period;


•	$19.7 million increase in production expenses, primarily related to an increase in production volumes for the nine months ended September 30, 2018;


•	$25.7 million increase in exploration expenses, primarily related to increased unproved leasehold amortization during the nine months ended September 30, 2018;


•	$61.5 million increase in depreciation, depletion, amortization and accretion, primarily due to increased production volumes and a higher depletion rate due to increases in capital expenditures;


•	$18.2 million increase in general & administrative expenses, primarily due to fees paid to Citizen and Linn under MSAs, salaries and benefits to our employees and equity-based compensation expense during the nine months ended September 30, 2018; and


•	$299.7 million income tax expense during the nine months ended September 30, 2018 as a result of recognizing a deferred tax liability upon becoming a taxable entity after the Reorganization.

Partially offset by:


•	$213.1 million increase in oil, natural gas and NGL sales, primarily as a result of an increase in total production volumes during the nine months ended September 30, 2018.


•	Average daily sales volumes were 40.1 MBoe for the nine months ended September 30, 2018, an increase of 208% compared to 13.0 MBoe during 2017.


•	Drilled or participated in 165 gross (51 net) wells in the first nine months of 2018.


•	1,246 gross (502 net) producing wells online at September 30, 2018, including 584 gross (430 net) operated wells.


•	Our Class A common stock began trading on the New York Stock Exchange (“NYSE”) under the ticker symbol “ROAN” on November 9, 2018. Upon trading on the NYSE, our Class A common stock ceased trading on the OTCQB market.

Sources of Revenue

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. For the nine months ended September 30, 2018, our revenues, excluding loss on derivative contracts, were derived 63% from oil sales, 16% from natural gas sales and 21% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sales of Oil, Natural Gas and NGL Volumes

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and NGLs, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. From time to time, we enter into derivative arrangements for our oil and natural gas production to mitigate the impact of price volatility on our business. See Item 3. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk for further discussion of the risks related to commodity price exposure and our derivative contracts.

Pricing for certain of our natural gas contracts are based on Oklahoma indexes, including ONEOK Gas Transportation (“OGT”), Natural Gas Pipeline Company of America Mid-Continent (“NGPL MC”), Panhandle Eastern Pipeline (“PEPL”) and Southern Star Central Gas Pipeline (“SSCGP”) due to the proximity of those pipelines to our producing properties. These indexes fluctuate from Henry Hub pricing due to a variety of reasons including the distance to the retail market, availability and capacity of pipelines to move the product to distribution hubs, customer demand, and competition between suppliers.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average oil prices were higher while the average natural gas prices remained consistent during the three and nine months ended September 30, 2018 compared to the same periods in 2017. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2018 and 2017:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Average NYMEX prices
Oil (Bbl)	$	69.55	$	48.21	$	66.75	$	49.47
Natural gas (MMcf)	$	3.04	$	3.06	$	3.06	$	3.12

Results of Operations

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

The following table presents selected financial and operating information for the periods presented.



	Three Months Ended September 30,
	2018		2017
Production Data
Oil (MBbls)	1,089		348
Natural gas (MMcf)	11,417		4,709
Natural gas liquids (MBbls)	1,286		405
Total volumes (MBoe)	4,278		1,538
Average daily total volumes (MBoe/d)	46.5		16.7
Average Prices - as reported ⁽¹⁾
Oil (per Bbl)	$	68.86	$	47.99
Natural gas (per Mcf)	$	1.58	$	2.73
Natural gas liquids (per Bbl)	$	21.08	$	24.87
Total (per Boe)	$	28.09	$	25.76
Average Prices - including impact of derivative contract settlements ⁽¹⁾⁽²⁾
Oil (per Bbl)	$	55.71	$	47.99
Natural gas (per Mcf)	$	1.62	$	2.73
Natural gas liquids (per Bbl)	$	21.08	$	24.87
Total (per Boe)	$	24.83	$	25.76
Average Prices - excluding gathering, transportation and processing costs ⁽³⁾
Oil (per Bbl)	$	68.93	$	47.99
Natural gas (per Mcf)	$	1.90	$	2.73
Natural gas liquids (per Bbl)	$	27.37	$	24.87
Total (per Boe)	$	30.86	$	25.76

(1)

Average prices for the three months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.


(2)	Excludes settlement of derivative contracts prior to their contractual maturity.


(3)	Excludes the effects of netting gathering, transportation and processing costs under ASC 606.

Revenues

Our operating revenues includes revenues from the sale of oil, natural gas and NGLs and gain (loss) on our derivative contracts. The following table provides information on our operating revenues:



	Three Months Ended September 30,
	2018			2017
Revenues	(in thousands)
Oil sales ⁽¹⁾	$	74,987		$	16,701
Natural gas sales ⁽¹⁾	18,059			12,845
Natural gas liquid sales ⁽¹⁾	27,106			10,074
(Loss) gain on derivative contracts	(36,704		)	131
Total revenues	$	83,448		$	39,751

(1)

Revenue for the three months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

Oil sales. Our oil sales increased by approximately $58.3 million, or 349%, to $75.0 million for the three months ended September 30, 2018 from $16.7 million for the three months ended September 30, 2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for those produced volumes. Our oil production increased 741 MBbls, or 213%, to 1,089 MBbls for the three months ended September 30, 2018 from 348 MBbls for the three months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The increase in average sales prices received on our oil production for the three months ended September 30, 2018 reflects the increase in the index price for oil in the 2018 period as compared to the 2017 period.

Natural Gas sales. Our natural gas sales increased by approximately $5.2 million, or 41%, to $18.1 million for the three months ended September 30, 2018 from $12.8 million for the three months ended September 30, 2017. This increase was primarily due to the increase in production partially offset by the decrease in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 6,708 MMcf, or 142%, to 11,417 MMcf for the three months ended September 30, 2018 from 4,709 MMcf for the three months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The decrease in average sales prices received on our natural gas production for the three months ended September 30, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 period.

NGL sales. Our NGL sales increased by approximately $17.0 million, or 169%, to $27.1 million for the three months ended September 30, 2018 from $10.1 million for the three months ended September 30, 2017. This increase was primarily due to the increase in production and an increase in the average sales prices received for those produced volumes, partially offset by the impact of netting of transportation costs with revenue as a result of adopting ASC 606. Our NGL production increased 881 MBbls, or 218%, to 1,286 MBbls for the three months ended September 30, 2018 from 405 MBbls for the three months ended September 30, 2017.

The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018.

(Loss) gain on derivative contracts. For the three months ended September 30, 2018, changes in oil prices had a negative impact on the fair value and settlement of our derivative contracts. We had a loss on derivative contracts of $36.7 million, including loss on settlement of derivatives contracts of $13.6 million and unfavorable change in the fair value of derivative contracts of $23.1 million. For the three months ended September 30, 2017, we had a gain on derivative contracts of $0.1 million related to the settlement of derivative contracts prior to their contractual maturity.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production and sale of oil, natural gas and NGLs. The following table provides information on our operating expenses:



	Three Months Ended September 30,
	2018		2017
	(in thousands, except costs per Boe)
Operating Expenses
Production expenses	$	14,737	$	4,336
Gathering, transportation and processing ⁽¹⁾	—		4,890
Production taxes	6,210		847
Exploration expenses	11,646		4,229
Depreciation, depletion, amortization and accretion	37,164		10,824
General and administrative ⁽²⁾	13,177		4,489
Gain on sale of oil and natural gas properties	—		(838		)
Total	$	82,934	$	28,777
Average Costs per Boe
Production expenses	$	3.44	$	2.82
Gathering, transportation and processing ⁽¹⁾	—		3.18
Production taxes	1.45		0.55
Exploration expenses	2.72		2.75
Depreciation, depletion, amortization and accretion	8.69		7.04
General and administrative ⁽²⁾	3.08		2.92
Gain on sale of oil and natural gas properties	—		(0.54		)
Total	$	19.38	$	18.72

(1)

Gathering, transportation and processing for the three months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.


(2)	General and administrative expenses for the three months ended September 30, 2018 include $2.9 million, or $0.69 per Boe, of equity-based compensation expense.

Production expenses. Production expenses are the operating costs incurred to maintain production. Such costs include the cost of saltwater disposal, monitoring, pumping, chemicals, maintenance, repairs, workover expenses and direct labor and overhead related to production activities. Production expenses were $14.7 million, or $3.44 per Boe, for the three months ended September 30, 2018, which was an increase of $10.4 million, or 240%, from $4.3 million for the three months ended September 30, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production. The increase in production expenses per Boe was primarily driven by increases in maintenance and surface repairs incurred during the three months ended September 30, 2018.

Gathering, transportation and processing. These costs are incurred to get oil, natural gas and NGLs to market. Gathering, transportation, and processing costs were $4.9 million, or $3.18 per Boe, for the three months ended September 30, 2017. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from revenue for the three months ended September 30, 2018.

Production taxes. Production taxes are paid on produced oil, natural gas, and NGLs based primarily on a percentage of sales revenues from production sold at fixed rates established by federal, state or local taxing authorities. Production taxes were $6.2 million for the three months ended September 30, 2018, an increase of $5.4 million, or 633%, from $0.8 million for the three months ended September 30, 2017. Production taxes primarily increased due to increased revenues and increased production tax rates, which became effective in July 2018.

Exploration expenses. These are primarily geological and geophysical costs that include seismic survey costs, amortization of the costs of unproved properties assessed for impairment on a group basis, costs of carrying and retaining unproved properties, and costs related to unsuccessful leasing efforts. For the three months ended September 30, 2018, exploration expenses of $11.6 million primarily consisted of unproved leasehold amortization. Unproved leasehold amortization is calculated by considering our drilling plans and the lease terms of our existing unproved properties. For the three months ended September 30, 2017, exploration expenses of $4.2 million consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Linn.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $37.2 million, or $8.69 per Boe, for the three months ended September 30, 2018, compared to $10.8 million, or $7.04 per Boe, for the three months ended September 30, 2017, which is an increase of $26.3 million or 243%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production.

General and administrative. General and administrative expenses were $13.2 million, or $3.08 per Boe, for the three months ended September 30, 2018, an increase of $8.7 million or 194% from $4.5 million, or $2.92 per Boe, for the three months ended September 30, 2017. During the three months ended September 30, 2018, general and administrative expenses included salaries and benefits of $6.9 million and equity-based compensation expense of $2.9 million. There were no such expenses incurred in the three months ended September 30, 2017. These expenses were offset by fees paid to Citizen and Linn under the MSAs of $2.5 million during the three months ended September 30, 2017. The MSAs with Citizen and Linn concluded in April 2018.

Other Expenses

Interest expense, net. Interest expense, net of capitalized interest, for the three months ended September 30, 2018 was $2.1 million as compared to $0.3 million for the three months ended September 30, 2017. This increase was due to increased borrowings outstanding during the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

Income tax expense. Income tax expense for the three months ended September 30, 2018 was $299.7 million and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

The following table presents selected financial and operating information for the periods presented.



	Nine Months Ended September 30,
	2018		2017
Production Data
Oil (MBbls)	3,004		884
Natural gas (MMcf)	29,486		10,523
Natural gas liquids (MBbls)	3,042		911
Total volumes (MBoe)	10,960		3,549
Average daily total volumes (MBoe/d)	40.1		13.0
Average Prices - as reported ⁽¹⁾
Oil (per Bbl)	$	65.70	$	51.70
Natural gas (per Mcf)	$	1.66	$	2.93
Natural gas liquids (per Bbl)	$	21.49	$	24.20
Total (per Boe)	$	28.44	$	27.79
Average Prices - including impact of derivative contract settlements ⁽¹⁾⁽²⁾
Oil (per Bbl)	$	55.70	$	51.70
Natural gas (per Mcf)	$	1.73	$	2.95
Natural gas liquids (per Bbl)	$	21.49	$	24.20
Total (per Boe)	$	25.90	$	27.83
Average Prices - excluding gathering, transportation and processing costs ⁽³⁾
Oil (per Bbl)	$	65.72	$	51.70
Natural gas (per Mcf)	$	2.07	$	2.93
Natural gas liquids (per Bbl)	$	27.53	$	24.20
Total (per Boe)	$	31.21	$	27.79

(1)

Average prices for the nine months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.


(2)	Excludes settlement of derivative contracts prior to their contractual maturity.


(3)	Excludes the effects of netting gathering, transportation and processing costs under ASC 606.

Revenues

The following table provides information on our operating revenues:



	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Revenues
Oil sales ⁽¹⁾	$	197,356		$	45,702
Natural gas sales ⁽¹⁾	48,956			30,884
Natural gas liquid sales ⁽¹⁾	65,377			22,049
(Loss) gain on derivative contracts	(100,920		)	2,385
Total revenues	$	210,769		$	101,020

(1)

Revenue for the nine months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.

Oil Sales. Our oil sales increased by approximately $151.7 million, or 332%, to $197.4 million for the nine months ended September 30, 2018 from $45.7 million for the nine months ended September 30, 2017. This increase was primarily due to the increase in production as well as the increase in average sales prices received for our produced volumes. Our oil production increased 2,120 MBbls, or 240%, to 3,004 MBbls for the nine months ended September 30, 2018 from 884 MBbls for the nine months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The increase in average sales prices received on our oil production for the nine months ended September 30, 2018 reflects the increase in the index price for oil in the 2018 period as compared to the 2017 period.

Natural Gas Sales. Our natural gas sales increased by approximately $18.1 million, or 59%, to $49.0 million for the nine months ended September 30, 2018 from $30.9 million for the nine months ended September 30, 2017. This increase was primarily due to the increase in production, partially offset by a decrease in average sales prices received for those produced volumes and the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our natural gas production increased 18,963 MMcf, or 180%, to 29,486 MMcf for the nine months ended September 30, 2018 from 10,523 MMcf for the nine months ended September 30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018. The decrease in average sales prices received on our natural gas production for the nine months ended September 30, 2018 reflects the decrease in the Oklahoma index prices we received under our contract terms for natural gas in the 2018 period as compared to the 2017 period.

NGL Sales. Our NGL sales increased by approximately $43.3 million, or 197%, to $65.4 million for the nine months ended September 30, 2018 from $22.0 million for the nine months ended September 30, 2017. This increase was primarily due to the increase in production and an increase in the average sales prices received for those produced volumes, partially offset by the impact of netting transportation costs with revenue as a result of adopting ASC 606. Our NGL production increased 2,131 MBbls, or 234%, to 3,042 MBbls for the nine months ended September 30, 2018 from 911 MBbls the nine months ended September

30, 2017. The increase in production volumes was due to production associated with oil and natural gas properties contributed by Linn in August 2017 and drilling activity in the fourth quarter of 2017 and during 2018.

(Loss) gain on derivative contracts. For the nine months ended September 30, 2018, changes in oil prices had a negative impact on the fair value and settlement of our derivative contracts. We had a loss on derivative contracts of $100.9 million, including loss on settlement of derivatives contracts of $27.5 million and unfavorable change in the fair value of derivative contracts of $73.4 million. The loss on settlement of derivative contracts included $0.4 million net loss on settlement of derivative contracts prior to their maturity. We had a gain on derivative contracts of $2.4 million during the nine months ended September 30, 2017 which included $2.3 million related to the settlement of derivative contracts prior to their contractual maturity.

Operating Expenses

The following table provides information on our operating expenses:



	Nine Months Ended September 30,
	2018		2017
	(in thousands, except per Boe)
Operating Expenses
Production expenses	$	30,111	$	10,450
Gathering, transportation and processing ⁽¹⁾	—		11,360
Production taxes	10,892		2,057
Exploration expenses	30,129		4,475
Depreciation, depletion, amortization and accretion	83,630		22,176
General and administrative ⁽²⁾	40,283		22,062
Gain on sale of oil and natural gas properties	—		(838		)
Total	$	195,045	$	71,742
Average Costs per Boe
Production expenses	$	2.75	$	2.94
Gathering, transportation and processing ⁽¹⁾	—		3.20
Production taxes	0.99		0.58
Exploration expenses	2.75		1.26
Depreciation, depletion, amortization and accretion	7.63		6.25
General and administrative ⁽²⁾	3.68		6.22
Gain on sale of oil and natural gas properties	—		(0.24		)
Total	$	17.80	$	20.21

(1)

Gathering, transportation and processing for the nine months ended September 30, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard.


(2)	General and administrative expenses for the nine months ended September 30, 2018 include $8.1 million, or $0.74 per Boe, of equity-based compensation expense.

Production expenses. Production expenses were $30.1 million, or $2.75 per Boe, for the nine months ended September 30, 2018, which was an increase of $19.7 million, or 188%, from $10.5 million, or $2.94 per Boe, for the nine months ended September 30, 2017. The increase in production expenses during 2018 compared to 2017 was primarily due to increased production. Due to certain production expenses being fixed, the increased production resulted in a decrease in production expense per Boe.

Gathering, transportation and processing. Gathering, transportation, and processing costs were $11.4 million, or $3.20 per Boe, for the nine months ended September 30, 2017. As a result of adopting ASC 606 in January 2018, these costs are reflected as a deduction from revenue for the nine months ended September 30, 2018.

Production taxes. Production taxes were $10.9 million for the nine months ended September 30, 2018, an increase of $8.8 million, or 430%, from $2.1 million for the nine months ended September 30, 2017. Production taxes primarily increased due to increased revenues.

Exploration expenses. For the nine months ended September 30, 2018, exploration expenses of $30.1 million primarily consisted of amortization of unproved leasehold. For the nine months ended September 30, 2017, exploration expenses of $4.5 million consisted of impairment expense recognized related to our unproved properties. The increase in exploration expenses is due, in part, to amortization of unproved leasehold associated with the oil and natural gas properties contributed by Linn.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion was $83.6 million, or $7.63 per Boe, for the nine months ended September 30, 2018, and $22.2 million, or $6.25 per Boe, for the nine months ended September 30, 2017, which is an increase of $61.5 million or 277%. The increase in depreciation, depletion, amortization and accretion was primarily due to increased production and, to a lesser extent, an increase in the depletion rate for our oil and natural gas properties. The per Boe increase in the depletion rate is attributable to higher capital expenditures.

General and administrative. General and administrative expenses were $40.3 million, or $3.68 per Boe, for the nine months ended September 30, 2018, an increase of $18.2 million or 83% from $22.1 million, or $6.22 per Boe, for the nine months ended September 30, 2017. During the nine months ended September 30, 2018, general and administrative expenses included salaries and benefits of $13.7 million, equity-based compensation expense of $8.1 million and fees paid to Citizen and Linn under the MSAs of $10.0 million. Additionally, we incurred consulting and professional fees as part of the implementation of systems and processes and transition efforts in 2018. These expenses were offset by bonuses paid by Citizen of approximately $9.0 million and fees paid under the MSAs of $2.5 million during the nine months ended September 30, 2017. The MSAs with Citizen and Linn concluded in April 2018.

Other Expenses

Interest expense, net. Interest expense, net of capitalized interest, for the nine months ended September 30, 2018 was $5.0 million as compared to $0.4 million for the nine months ended September 30, 2017. This increase was due to increased borrowings outstanding during the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.

Income tax expense. Income tax expense for the nine months ended September 30, 2018 was $299.7 million and relates to the recognition of a deferred tax liability upon becoming a taxable entity in conjunction with the Reorganization.

Liquidity and Capital Resources

Our primary sources of liquidity have been borrowings under our credit facility and cash flows from operations. Our primary uses of capital have been for the exploration, development and acquisition of oil and natural gas properties.

Cash Flows

Our cash flows for the nine months ended September 30, 2018 and 2017 are presented below:



	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by operating activities	$	206,644		$	59,248
Net cash used in investing activities	(510,868		)	(182,571		)
Net cash provided by financing activities	306,653			117,410
Net increase (decrease) in cash and cash equivalents	$	2,429		$	(5,913	)

Cash flows provided by operating activities. Cash flows provided by operating activities for the nine months ended September 30, 2018 were $206.6 million compared to $59.2 million for the nine months ended September 30, 2017. The increase in cash flows provided by operating activities is primarily related to changes in working capital accounts and increased revenues partially offset by higher cash expenses due to increased activity in 2018.

Cash flows used in investing activities. Cash flows used in investing activities for the nine months ended September 30, 2018 were $510.9 million compared to $182.6 million for the nine months ended September 30, 2017. The increase in cash flows used in investing activities is due to the increase in capital expenditures on oil and natural gas properties resulting from the increase in drilling and completion activities in 2018 compared to 2017.

Cash flows provided by financing activities. Cash flows provided by financing activities for the nine months ended September 30, 2018 were $306.7 million compared to $117.4 million for the nine months ended September 30, 2017. The increase in cash flows provided by financing activities for the nine months ended September 30, 2018 is attributable to borrowings of $309.3 million from our credit facility. Financing activity for the nine months ended September 30, 2017 were related to capital contributions from Citizen members of $95.6 million and borrowings of $75.3 million, partially offset by distributions to Citizen members and repayments of $40.0 million on Citizen's credit facility.

Credit Facility

Our 2017 Credit Facility is a $750.0 million credit agreement with a maturity date of September 5, 2022. As of September 30, 2018, the borrowing base is set at $675.0 million. Redetermination of the borrowing base occurs semiannually on or about October 1 and April 1. As of September 30, 2018, we had $394.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility.

Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR. Either rate is adjusted upward by an applicable margin (ranging from 2.00% to 3.00% for LIBOR and 1.00% to 2.00% for ABR), based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides

for a commitment fee of 0.375% to 0.50% based on utilization, which is payable at the end of each calendar quarter.

The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, we are prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon our internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, we are required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per our most recent reserve report.

The 2017 Credit Facility also contains financial covenants requiring us to comply with a leverage ratio of consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of September 30, 2018, we were in compliance with the covenants under the 2017 Credit Facility.

Capital Expenditures

Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow and financing under our 2017 Credit Facility.

Our capital budget for the fourth quarter of 2018 is $200 million to $225 million. During the nine months ended September 30, 2018, capital expenditures were $558.0 million. Capital expenditures include expenditures related to drilling and completion costs of $474.7 million, leasehold additions of $73.5 million, and other costs of $9.8 million which includes corporate spending on other property and equipment. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for the remainder of 2018 and 2019, we believe our cash flow from operations, cash on hand, borrowings under our 2017 Credit Facility and access to capital markets will be sufficient to fund our operations for the next twelve months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties.

Working Capital

At September 30, 2018, we had a working capital deficit of $183.1 million compared to $121.2 million at December 31, 2017. Current assets and current liabilities increased by $150.7 million and $212.6 million, respectively, at September 30, 2018, compared to December 31, 2017 as a result of us taking over as operator in May 2018 on the oil and natural gas properties contributed to us by Citizen and Linn and increased drilling activity during 2018. Additionally, at the conclusion of the MSAs, we assumed certain working capital accounts associated with these properties from Citizen and Linn. Another factor contributing to the increase in the working capital deficit is the increase in the derivative contract liabilities of $54.9 million, which is due to the negative impact of higher in oil prices on the fair value of our open oil contracts with maturity dates in the next twelve months.

Off-Balance Sheet Arrangements

We enter into certain off-balance sheet arrangements and transactions, including operating lease arrangements and undrawn letters of credit. In addition, we enter 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 our liquidity or capital resource positions.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of September 30, 2018:



	Payments Due by Period
	2018		2019		2020		2021		2022		Thereafter		Total
	(in thousands)
Credit Facility	$	—	$	—	$	—	$	—	$	394,639	$	—	$	394,639
Interest expenses related to Credit Facility ⁽¹⁾	5,366		21,288		21,288		21,288		14,464		—		83,694
Pipe and equipment purchases commitments ⁽²⁾	1,925		—		—		—		—		—		1,925
Office building leases	489		1,677		2,047		2,136		2,229		627		9,205
Drilling rig commitments ⁽³⁾	8,050		15,352		—		—		—		—		23,402
Total contractual obligations and commitments	$	15,830	$	38,317	$	23,335	$	23,424	$	411,332	$	627	$	512,865

(1) Includes interest expense on our outstanding borrowings calculated using the weighted average interest rate of 5.32% at September 30, 2018.

(2) Reflects commitments to purchase specified amounts of pipe and equipment.

(3) Reflects future minimum drilling fees including early termination fees as specified by the contract.

The above table does not include liabilities related to ARO. These are costs associated with the plugging of wells and the related abandonment of oil and natural gas properties. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. 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. Although management believes they are reasonable, actual results could differ from these estimates and assumptions.

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 2 – Summary of Significant Accounting Policies in the accompanying condensed consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a number of market risks including commodity price risk, credit risk and interest rate risk. The following information provides quantitative and qualitative information about our potential risks and how we seek to manage such risks.

Commodity Price Risk

The following table reflects our open commodity contracts as of September 30, 2018:



	2018		2019		2020		Total
Oil fixed prices swaps
Volume (Bbl)	1,233,180		5,540,670		1,599,500		8,373,350
Weighted-average price	$	57.09	$	59.86	$	63.14	$	60.08
Natural gas fixed price swaps
Volume (MMBtu)	8,004,000		29,200,000		12,325,000		49,529,000
Weighted-average price	$	2.94	$	2.86	$	2.63	$	2.81
Natural gas basis swaps
Volume (MMBtu)	4,600,000		21,900,000		3,640,000		30,140,000
Weighted-average price	$	0.54	$	0.58	$	0.62	$	0.58

Our primary market risk exposure is in the price we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil and natural gas production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows. These derivatives are not designated as a hedging instrument for hedge accounting under GAAP and as such, gains or losses resulting from the change in fair value along with the gains or losses resulting from settlement of derivative contracts are reflected as gain or loss on derivative contracts included in the consolidated statement of operations.

There are a variety of hedging strategies and instruments used to hedge future price risk. We utilize fixed price swaps and basis swaps to manage the price risk associated with forecasted sale of our oil and natural gas production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential. When the referenced settlement price is less than the price specified in the contract, we receive an amount from the counterparty based on the price difference multiplied by the volume. When the referenced settlement price exceeds the price

specified in the contract, we pay the counterparty an amount based on the price difference multiplied by the volume.

At September 30, 2018, we had a net liability position of $83.0 million related to our derivative contracts. Utilizing actual derivative contractual volumes under our fixed price swaps as of September 30, 2018, an increase of 10% in the forward curves associated with the underlying commodity would have increased the net liability position to $156.2 million, while a decrease of 10% in the forward curves associated with the underlying commodity would have resulted in a net liability position of $16.0 million.

Credit Risk

Our principal exposure to credit risk is through the sale of our oil, natural gas and NGL production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties.

We are subject to credit risk resulting from the concentration of oil, natural gas and NGL receivables with two significant purchasers. We do not believe the loss of any single purchaser would materially impact our results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

Our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. We monitor on an ongoing basis the credit ratings of our derivative counterparties and consider their credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. The counterparties to our derivative contracts at September 30, 2018, are also lenders under our 2017 Credit Facility. As a result, we do not require collateral or other security from counterparties nor are we required to post collateral to support derivative instruments. We have master netting agreements with all of our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our 2017 Credit Facility. The terms of our 2017 Credit Facility provide for interest on borrowings at LIBOR or the alternate base rate, in each case adjusted upward by an applicable margin based on the utilization percentage of the credit facility.

As of September 30, 2018, we had $394.6 million in outstanding borrowings under our 2017 Credit Facility. At September 30, 2018, the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.32%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $3.9 million based on outstanding borrowings of $394.6 million under our 2017 Credit Facility as of September 30, 2018.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

As required by Rule 13a-15 and 15d-15 of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined

in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at September 30, 2018 at the reasonable assurance level because of the material weaknesses in our internal control over financial reporting as further described below.

Identification of Material Weaknesses

We have identified material weaknesses in our internal control over financial reporting in connection with the audit of our financial statements as of and for the years ended December 31, 2017 and 2016. A material weakness is a deficiency or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

We have identified five material weaknesses in our internal control over financial reporting. The material weaknesses identified relate to an overall lack of qualified personnel within the organization who possessed an appropriate level of expertise, experience and training to effectively design, implement and maintain: (i) adequate controls to monitor and assess the control environment. Specifically, internal controls were not designed or operating effectively to ensure appropriate monitoring or assessment of the control environment, including utilizing an appropriate control framework; (ii) adequate controls to establish appropriate entity level controls. Specifically, internal controls were not designed or operating effectively to ensure a sufficient amount of entity level controls were in place and operating effectively; (iii) effective controls over our period-end financial reporting processes, including controls over the preparation, analysis and review of certain significant account reconciliations required to assess the appropriateness of account balances at period-end; and controls over segregation of duties and the review of manual journal entries. Specifically, we did not design and maintain effective controls to verify that journal entries were properly prepared with sufficient supporting documentation or were reviewed and approved to ensure the accuracy and completeness of the manual journal entries. Additionally, certain key accounting personnel have the ability to prepare and post journal entries, as well as review account reconciliations, without an independent review by someone other than the preparer; and (iv) effective controls over information technology systems that are relevant to the preparation of the financial statements. Specifically, we did not design and maintain (a) user access controls to ensure appropriate segregation of duties and to adequately restrict user and privileged access to infrastructure, financial applications, programs, and data to appropriate personnel, (b) program change management controls to ensure that information technology program and data changes affecting financial IT applications and underlying accounting records are identified, tested, authorized and implemented appropriately, (c) computer operation controls to ensure all financially significant batch jobs are monitored for the completeness and accuracy of data transfer, and (d) program development controls to ensure that new software development is aligned with business and IT requirements. The deficiencies described in this clause (iv), when aggregated, could impact both maintaining effective segregation of duties and the effectiveness of IT-dependent controls (such as automated controls that address the risk of material misstatement to one or more assertions, along with the IT controls and underlying data that support the effectiveness of system-generated data and reports) that could result in misstatements potentially impacting all financial statement accounts and disclosures that would not be prevented or detected in a timely manner; and (v) a sufficient complement of resources with an appropriate level of accounting knowledge, experience and training to

develop and maintain an effective internal control environment. These material weaknesses originated with Citizen, the predecessor of Roan LLC, which had a lack of sufficient resources and inadequate control systems as it commenced operations as a private company. These material weaknesses did not result in any material misstatements of our financial statements or disclosures. The control deficiencies discussed above could result in a misstatement of account balances or disclosures that would result in a material misstatement to the annual or interim financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses.

Remediation Plan for the Material Weaknesses

We have taken and will continue to take a number of actions to remediate these material weaknesses. We are currently implementing measures designed to improve our internal control over financial reporting and remediate the control deficiencies that led to the material weaknesses, including but not limited to, (i) hiring additional IT and accounting personnel with appropriate technical skillsets, (ii) initiating design and implementation of our control environment, including the expansion of formal accounting and IT policies and procedures and financial reporting controls, (iii) conducting a company-wide assessment of our control environment, (iv) implementing appropriate review and oversight responsibilities within the accounting and financial reporting functions, and (v) evaluating controls over our information technology environment. We can give no assurance that these actions will remediate these material weaknesses in internal controls or that additional material weaknesses in our internal control over financial reporting will not be identified in the future.

Changes in Internal Control over Financial Reporting.

Except as described herein, there were no changes in our internal control over financial reporting during the quarter ended September 30, 2018, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

We are a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. There can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading "Risk Factors" included in our Current Report on Form 8-K filed on September 24, 2018, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently

deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in the Current Report, except as set forth below.

The marketability and pricing of our production is dependent upon transportation and other facilities and various market factors, which we generally do not control. If these facilities are unavailable or we become subject to adverse pricing differentials, our operations could be interrupted and our revenues reduced.

The marketability of our oil, natural gas and NGL production depends in part upon the availability, proximity and capacity of transportation and other production facilities owned by third parties. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to produce or deliver to market our oil, natural gas and NGLs, causing a significant interruption in our operations. While we believe we have reserved sufficient capacity with third-party facilities to gather, process, fractionate and transport a significant portion of our projected production, that capacity may not be sufficient to handle all of our production, or these third-party facilities may experience delays in construction, mechanical problems or become unavailable to us due to unforeseen circumstances.

Additionally, we depend on various trucking providers for our oil production and on two third-party midstream companies for substantially all of our current natural gas and NGL production. Our current natural gas and NGL arrangements provide for pricing at Mont Belvieu, Texas, but future arrangements could be tied to pricing at Conway, Kansas or other market hubs and subject us to adverse pricing differentials. In the future, we may be required to find alternative markets and gathering, processing or fractionation arrangements for our production, and such alternative arrangements may only be available on unfavorable terms, or not at all. If we are unable, for any sustained period, to access these third-party facilities or find acceptable alternative arrangements, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for gathering, processing, fractionating and delivering the oil, natural gas and NGLs produced from our fields, would materially and adversely affect our financial condition and results of operations.

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

None other than previously disclosed in the Current Report.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosure

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits



Exhibit No.		Exhibit
2.1		Linn Merger Agreement, dated September 24, 2018, by and among Linn Energy, Inc., Roan Resources, Inc. and Linn Merger Sub #2, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed on September 24, 2018)
2.2		Roan Merger Agreement, dated September 24, 2018, by and among Roan Holdings, LLC, Roan Holdings Holdco, LLC, Roan Resource, Inc. and Linn Merger Sub #3, LLC (incorporated by reference to Exhibit 2.2 to Form 8-K filed on September 24, 2018)
2.3		Master Reorganization Agreement, dated September 17, 2018, by and among Linn Energy, Inc., Roan Holdings, LLC, and Roan Resources LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on September 21, 2018)
2.4		Separation and Distribution Agreement, dated August 7, 2018, by and between Linn Energy, Inc. and Riviera Resources, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
2.5		Agreement and Plan of Merger, dated July 25, 2018, by and among Linn Energy Inc., New LINN Inc. and Linn Merger Sub #1, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K filed by Linn Energy, Inc. on July 26, 2018)
3.1		Second Amended and Restated Certificate of Incorporation of Roan Resources, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K filed on September 27, 2018)
3.2		Second Amended and Restated Bylaws of Roan Resources, Inc. (incorporated by reference to Exhibit 3.2 to Form 8-K filed on September 27, 2018)
4.1		Registration Rights Agreement, dated September 24, 2018, by and among Roan Resources, Inc. and each of the other parties listed on the signature page thereto (incorporated by reference to Exhibit 4.1 to Form 8-K filed on September 24, 2018)
4.2		Stockholders Agreement, dated September 24, 2018, by and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 4.2 to Form 8-K filed on September 24, 2018)
10.1		Credit Agreement, dated September 5, 2017, by and among Citibank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 24, 2018)
10.2		Amendment No. 1 to Credit Agreement, dated April 9, 2018 (incorporated by reference to Exhibit 10.2 to Form 8-K filed on September 24, 2018)
10.3		Amendment No. 2 to Credit Agreement, dated May 30, 2018 (incorporated by reference to Exhibit 10.3 to Form 8-K filed on September 24, 2018)
10.4		Amendment No. 3 to Credit Agreement, dated September 27, 2018 (incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 27, 2018)
10.5†		Roan Resources, Inc. Amended and Restated Management Incentive Plan, dated September 24, 2018 (incorporated by reference to Exhibit 10.4 to Form 8-K filed on September 24, 2018
10.6†		Form of Performance Share Unit Grant Notice and Performance Share Unit Award Agreement pursuant to the Roan Resources, Inc. Amended and Restated Management Incentive Plan (incorporated by reference to Exhibit 10.5 to Form 8-K filed on September 24, 2018)
10.7		Voting Agreement, dated September 24, 2018, by and among Roan Resources, Inc., the Existing LINN Owners (as defined therein), Roan Holdings, LLC and any other persons signatory thereto from time to time (incorporated by reference to Exhibit 10.6 to Form 8-K filed on September 24, 2018)
10.8		Second Amended and Restated Limited Liability Company Agreement of Roan Resources LLC (incorporated by reference to Exhibit 10.7 to Form 8-K filed on September 24, 2018)
10.9†		Amended and Restated Employment Agreement, dated November 6, 2017, between Roan Resources, Inc. and Tony Maranto (incorporated by reference to Exhibit 10.8 to Form 8-K filed on September 24, 2018)
10.10†		Employment Agreement, dated June 18, 2018, between Roan Resources LLC and David Edwards (incorporated by reference to Exhibit 10.9 to Form 8-K filed on September 24, 2018)
10.11†		Employment Agreement, dated November 6, 2017, between Roan Resources LLC and Joel Pettit (incorporated by reference to Exhibit 10.10 to Form 8-K filed on September 24, 2018)
10.12†		Employment Agreement, dated November 6, 2017, between Roan Resources LLC and Greg Condray (incorporated by reference to Exhibit 10.11 to Form 8-K filed on September 24, 2018)
10.13†		Employment Agreement, dated September 17, 2018, between Roan Resources LLC and David Treadwell (incorporated by reference to Exhibit 10.12 to Form 8-K filed on September 24, 2018)



10.14		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Tony Maranto (incorporated by reference to Exhibit 10.13 to Form 8-K filed on September 24, 2018)
10.15		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Matthew Bonanno (incorporated by reference to Exhibit 10.14 to Form 8-K filed on September 24, 2018)
10.16		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Evan Lederman (incorporated by reference to Exhibit 10.15 to Form 8-K filed on September 24, 2018)
10.17		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and John Lovoi (incorporated by reference to Exhibit 10.16 to Form 8-K filed on September 24, 2018)
10.18		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Paul B. Loyd Jr. (incorporated by reference to Exhibit 10.17 to Form 8-K filed on September 24, 2018)
10.19		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Michael Raleigh (incorporated by reference to Exhibit 10.18 to Form 8-K filed on September 24, 2018)
10.20		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Andrew Taylor (incorporated by reference to Exhibit 10.19 to Form 8-K filed on September 24, 2018)
10.21		Indemnification Agreement, dated September 24, 2018, between Roan Resources, Inc. and Anthony Tripodo (incorporated by reference to Exhibit 10.20 to Form 8-K filed on September 24, 2018)
10.22		Tax Matters Agreement, dated August 7, 2018, by and among Linn Energy, Inc., Riviera Resources, Inc. and the Riviera Resources, Inc. Subsidiaries (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
10.23		Transition Services Agreement, dated August 7, 2018, by and between Linn Energy, Inc. and Riviera Resources, Inc. (incorporated by reference to Exhibit 10.2 to Form 8-K filed by Linn Energy, Inc. on August 10, 2018)
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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
† Compensatory plan or arrangement

SIGNATURES

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

ROAN RESOURCES, INC.





Date:	November 13, 2018	/s/ Tony C. Maranto
		Tony C. Maranto
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)



Date:	November 13, 2018	/s/ David M. Edwards
		David M. Edwards
		Chief Financial Officer
		(Principal Financial Officer)