Edgar Filing: RANGE RESOURCES CORP

rrc-10q_20190331.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended March 31, 2019

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

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code

(817) 870-2601

Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

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

Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit such files).

Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☑	Accelerated Filer	☐

Non-Accelerated Filer	☐	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 ☑

251,148,010 Common Shares were outstanding on April 19, 2019

RANGE RESOURCES CORPORATION

FORM 10-Q

Quarter Ended March 31, 2019

Unless the context otherwise indicates, all references in this report to “Range Resources,” “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries. For certain industry specific terms used in the Form 10-Q, please see “Glossary of Certain Defined Terms” in our 2018 Annual Report on Form 10-K.

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Financial Statements	3
	Consolidated Balance Sheets (Unaudited)	3
	Consolidated Statements of Operations (Unaudited)	4
	Consolidated Statements of Comprehensive Income (Unaudited)	5
	Consolidated Statements of Cash Flows (Unaudited)	6
	Consolidated Statements of Stockholders’ Equity (Unaudited)	7
	Selected Notes to Consolidated Financial Statements (Unaudited)	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	41
ITEM 4.	Controls and Procedures	44
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings	44
ITEM 1A.	Risk Factors	44
ITEM 6.	Exhibits	45

	SIGNATURES	46

PART I – FINANCIAL INFORMATION

ITEM 1. Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

	March 31,			December 31,
	2019			2018
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	488		$	545
Accounts receivable, less allowance for doubtful accounts of $6,118 and $6,118		356,716			490,723
Derivative assets		6,146			87,953
Inventory and other		25,128			22,964
Total current assets		388,478			602,185
Derivative assets		8,406			4,842
Natural gas and oil properties, successful efforts method		13,300,145			13,085,206
Accumulated depletion and depreciation		(4,194,876	)		(4,062,021	)
		9,105,269			9,023,185
Other property and equipment		112,373			111,908
Accumulated depreciation and amortization		(103,548	)		(102,132	)
		8,825			9,776
Operating lease right-of-use assets		49,329			—
Other assets		74,757			68,166
Total assets	$	9,635,064		$	9,708,154

Liabilities
Current liabilities:
Accounts payable	$	215,073		$	227,344
Asset retirement obligations		5,485			5,485
Accrued liabilities		399,822			475,848
Accrued interest		37,051			41,990
Derivative liabilities		13,369			4,144
Total current liabilities		670,800			754,811
Bank debt		884,652			932,018
Senior notes		2,857,297			2,856,166
Senior subordinated notes		48,700			48,677
Deferred tax liabilities		672,376			666,668
Derivative liabilities		2,559			3,462
Deferred compensation liabilities		75,179			67,542
Operating lease liabilities		41,759			—
Asset retirement obligations and other liabilities		319,079			319,379
Total liabilities		5,572,401			5,648,723
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 251,147,799 issued at March 31, 2019 and 249,519,687 issued at December 31, 2018		2,512			2,495
Common stock held in treasury, 9,665 shares at March 31, 2019 and 9,665 shares at December 31, 2018		(391	)		(391	)
Additional paid-in capital		5,635,210			5,628,447
Accumulated other comprehensive loss		(598	)		(658	)
Retained deficit		(1,574,070	)		(1,570,462	)
Total stockholders’ equity		4,062,663			4,059,431
Total liabilities and stockholders’ equity	$	9,635,064		$	9,708,154

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

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share data)

	Three Months Ended March 31,
	2019			2018

Revenues and other income:
Natural gas, NGLs and oil sales	$	671,654		$	696,629
Derivative fair value loss		(61,731	)		(14,009	)
Brokered natural gas, marketing and other		138,214			59,979
Total revenues and other income		748,137			742,599
Costs and expenses:
Direct operating		33,227			38,122
Transportation, gathering, processing and compression		302,655			244,628
Production and ad valorem taxes		11,310			9,926
Brokered natural gas and marketing		132,305			55,594
Exploration		8,211			7,719
Abandonment and impairment of unproved properties		12,659			11,773
General and administrative		46,638			68,417
Termination costs		—			(37	)
Deferred compensation plan		3,581			(7,397	)
Interest		51,537			52,385
Depletion, depreciation and amortization		138,718			162,266
Impairment of proved properties		—			7,312
Loss (gain) on the sale of assets		189			(23	)
Total costs and expenses		741,030			650,685
Income before income taxes		7,107			91,914
Income tax expense:
Current		—			—
Deferred		5,688			42,676
		5,688			42,676
Net income	$	1,419		$	49,238
Net income per common share:
Basic	$	0.01		$	0.20
Diluted	$	0.01		$	0.20
Dividends paid per common share	$	0.02		$	0.02
Weighted average common shares outstanding:
Basic		247,776			245,709
Diluted		249,154			246,594

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

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited, in thousands)

	Three Months Ended March 31,
	2019			2018

Net income	$	1,419		$	49,238
Other comprehensive income:
Postretirement benefits
Prior service cost		92			92
Actuarial gain		(12	)		—
Income tax expense		(20	)		(23	)
Total comprehensive income	$	1,479		$	49,307

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

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Three Months Ended March 31,
	2019			2018

Operating activities:
Net income	$	1,419		$	49,238
Adjustments to reconcile net income to net cash provided from operating activities:
Deferred income tax expense		5,688			42,676
Depletion, depreciation and amortization and impairment		138,718			169,578
Exploration dry hole costs		—			2
Abandonment and impairment of unproved properties		12,659			11,773
Derivative fair value loss		61,731			14,009
Cash settlements on derivative financial instruments		24,834			8,925
Amortization of deferred financing costs and other		1,807			1,312
Deferred and stock-based compensation		14,112			18,527
Loss (gain) on the sale of assets		189			(23	)
Changes in working capital:
Accounts receivable		134,006			53,913
Inventory and other		(4,763	)		(5,294	)
Accounts payable		(30,431	)		47,453
Accrued liabilities and other		(99,275	)		(41,517	)
Net cash provided from operating activities		260,694			370,572
Investing activities:
Additions to natural gas and oil properties		(190,014	)		(308,641	)
Additions to field service assets		(576	)		(239	)
Acreage purchases		(23,646	)		(25,355	)
Proceeds from disposal of assets		332			40
Purchases of marketable securities held by the deferred compensation plan		(4,259	)		(13,153	)
Proceeds from the sales of marketable securities held by the deferred compensation plan		6,204			11,928
Net cash used in investing activities		(211,959	)		(335,420	)
Financing activities:
Borrowings on credit facilities		566,000			528,000
Repayments on credit facilities		(614,000	)		(557,000	)
Dividends paid		(5,023	)		(4,971	)
Taxes paid for shares withheld		(3,161	)		(2,659	)
Change in cash overdrafts		7,218			922
Proceeds from the sales of common stock held by the deferred compensation plan		174			635
Net cash used in financing activities		(48,792	)		(35,073	)
(Decrease) increase in cash and cash equivalents		(57	)		79
Cash and cash equivalents at beginning of period		545			448
Cash and cash equivalents at end of period	$	488		$	527

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

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except per share data)

														Accumulated
					Common stock									other
	Common stock				held in			Additional paid-			Retained			comprehensive
	Shares		Par value		treasury			in capital			(deficit)/earnings			(loss) income			Total
Balance as of December 31, 2018		249,520	$	2,495	$	(391	)	$	5,628,447		$	(1,570,462	)	$	(658	)	$	4,059,431
Issuance of common stock		1,628		17		—			(2,396	)		—			—			(2,379	)
Issuance of common stock upon vesting of PSUs		—		—		—			4			(4	)		—			—
Stock-based compensation expense		—		—		—			9,155			—			—			9,155
Cash dividends paid ($0.02 per share)		—		—		—			—			(5,023	)		—			(5,023	)
Other comprehensive income		—		—		—			—			—			60			60
Net income		—		—		—			—			1,419			—			1,419
Balance as of March 31, 2019		251,148	$	2,512	$	(391	)	$	5,635,210		$	(1,574,070	)	$	(598	)	$	4,062,663


														Accumulated
					Common stock									other
	Common stock				held in			Additional paid-			Retained			comprehensive
	Shares		Par value		treasury			in capital			(deficit)/earnings			(loss) income			Total
Balance as of December 31, 2017		248,144	$	2,481	$	(599	)	$	5,577,732		$	195,990		$	(1,332	)	$	5,774,272
Issuance of common stock		1,092		11		—			(1,228	)		—			—			(1,217	)
Stock-based compensation expense		—		—		—			17,201			—			—			17,201
Cash dividends paid ($0.02 per share)		—		—		—			—			(4,971	)		—			(4,971	)
Treasury stock issuance		—		—		30			(30	)		—			—			—
Other comprehensive income		—		—		—			—			—			69			69
Net income		—		—		—			—			49,238			—			49,238
Balance as of March 31, 2018		249,236	$	2,492	$	(569	)	$	5,593,675		$	240,257		$	(1,263	)	$	5,834,592

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

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation is a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and the North Louisiana regions of the United States. Our objective is to build stockholder value through consistent returns focused development, on a per share debt-adjusted basis, of both reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC”.

(2) BASIS OF PRESENTATION

These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2018 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on February 25, 2019. The results of operations for the first quarter ended March 31, 2019 are not necessarily indicative of the results to be expected for the full year.

Inventory. As of March 31, 2019, we had $7.4 million of material and supplies inventory compared to $8.0 million at December 31, 2018. Material and supplies inventory consists of primarily tubular goods and equipment used in our operations and is stated at lower of specific cost of each inventory item or net realized value, on a first-in, first-out basis. At March 31, 2019, we also had commodity inventory of $253,000 compared to $965,000 at December 31, 2018. Commodity inventory as of March 31, 2019 consists of NGLs held in storage or as line fill in pipelines.

(3) NEW ACCOUNTING STANDARDS

Not Yet Adopted

Financial Instruments – Credit Losses

In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position and financial disclosures.

Fair Value Measurement

In August 2018, an accounting standards update was issued which provides additional disclosure requirements for fair value measurements. This new standards update eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for us in first quarter 2020 and will be adopted on a prospective or retrospective basis depending on the changes that apply. We are evaluating the provisions of this standards update and assessing the impact, if any, it may have on our financial disclosures.

Recently Adopted

Lease Accounting Standard

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use (“ROU”) asset and lease liability for all leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.

The new standard was effective for us in first quarter 2019 and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized a ROU asset (or operating lease right-of-use asset) and a lease liability with no retained earnings impact. We are applying the following practical expedients as provided in the standards update which provide elections to:

•

not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option);

•

not reassess whether a contract contains a lease, lease classification and initial direct costs; and

•

not reassess certain land easements in existence prior to January 1, 2019.

Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standards update. Our adoption did not have a material impact on our consolidated balance sheet as of January 1, 2019, with the primary impact relating to the recognition of ROU assets and operating lease liabilities for operating leases which represents approximately a 1% change to total assets and total liabilities. The impact of adoption of this new standards update is as follows (in thousands):


	January 1, 2019
		Adoption			Reclassification ⁽¹⁾			Total Adjustment
Balance Sheet:
Operating lease right-of-use assets	$	59,300		$	(7,925	)	$	51,375
Accrued liabilities – current	$	(14,811	)	$	—		$	(14,811	)
Operating lease liabilities – long-term	$	(44,489	)	$	—		$	(44,489	)
Asset retirement obligations and other liabilities	$	—		$	7,925		$	7,925

⁽¹⁾

As of December 31, 2018, we had $7.9 million primarily related to operating lease liabilities recorded as part of purchase price accounting related to building leases acquired because we did not expect to occupy the space or receive payments from our subleases. Lease incentives related to other buildings are also included. Upon adoption of the new standards update, these leases were included as part of our adoption but the ROU asset is reduced because we do not expect to use the asset.

Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update.

Pension Accounting Standard

In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers will present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs arising from services rendered during the period. This new standards update was effective for annual reporting periods in first quarter 2018 and must be applied retrospectively. We adopted this standards update in first quarter 2018. The adoption did not impact our consolidated results of operations, financial position, cash flows or disclosures. In 2018 and 2019, our service cost is recorded in general and administrative expense.

Modification of Share – Based Awards

In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update is intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. We adopted this standards update in first quarter 2018. The adoption of this standard did not have a material impact on our consolidated financial position or results of operations.

Revenue Recognition Standard

In May 2014, an accounting standards update was issued that superseded the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. This standard was effective for us in first quarter 2018 and we adopted the new standards update using the modified retrospective method to all open contracts as of January 1, 2018. Our implementation of this standard did not result in a cumulative-effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts changed. Based on previous accounting guidance, certain of our gas processing contracts were reported in revenue at the net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts are now reported as a gross price received at a delivery point and separate transportation, marketing and processing expense.

(4) DISPOSITIONS

We recognized a pretax net loss of $189,000 on the sale of assets in first quarter 2019 compared to a pretax net gain of $23,000 in the same period of the prior year.

2019 Dispositions

Other. In first quarter 2019, we sold miscellaneous inventory and other assets for proceeds of $332,000, resulting in a pretax loss of $189,000.

2018 Dispositions

Other. In first quarter 2018, we sold miscellaneous inventory and other assets for proceeds of $40,000, resulting in a pretax gain of $23,000.

(5) REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

Natural gas, NGLs and oil sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured.

Disaggregation of Revenue

We have three material revenue streams in our business: natural gas sales, NGLs sales and oil sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Our net brokered margin was a gain of $5.6 million in first quarter 2019 compared to a gain of $3.1 million in first quarter 2018. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration. Accounts receivable attributable to our revenue contracts with customers was $315.2 million at March 31, 2019 and $438.3 million at December 31, 2018. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

	Three Months Ended March 31,
		2019		2018
Natural gas sales ^(a)	$	572,510	$	491,248
NGLs sales ^(b)		198,237		202,831
Oil sales		39,121		62,529
Total	$	809,868	$	756,608

^(a)	Natural gas sales revenue reported above for first quarter 2019 includes $134.8 million of brokered revenues and $3.0 million of marketing revenue. First quarter 2018 includes $55.9 million of brokered revenues and $3.8 million of marketing revenue.

^(b)	NGLs sales revenue reported above for the first quarter 2019 includes $424,000 of brokered revenues and first quarter 2018 includes $304,000 of brokered revenues.

(6) INCOME TAXES

Income tax expense was as follows (in thousands):

		Three Months Ended March 31,
		2019			2018
Income tax expense	$	5,688		$	42,676
Effective tax rate		80.0	%		46.4	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For first quarter 2019 and 2018, our overall effective tax rate was different than the federal statutory rate due primarily to state income taxes (including adjustments to state income tax valuation allowances), equity compensation and other tax items which are detailed below (in thousands).

		Three Months Ended March 31,
		2019			2018
Total income before income taxes	$	7,107		$	91,914
U.S. federal statutory rate		21	%		21	%
Total tax expense at statutory rate		1,492			19,302

State and local income taxes, net of federal benefit		818			4,494
Equity compensation		3,391			664
Change in valuation allowances:
State net operating loss carryforwards & other		352			15,678
Other		231			1,381
Permanent differences and other		(596	)		1,157
Total expense for income taxes	$	5,688		$	42,676
Effective tax rate		80.0	%		46.4	%

(7) INCOME (LOSS) PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (1) income or loss attributable to common shareholders (2) less income allocable to participating securities (3) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common shareholders is computed as (1) basic income or loss attributable to common shareholders (2) plus diluted adjustments to income allocable to participating securities (3) divided by weighted average diluted shares outstanding. The following sets forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders to diluted income or loss attributable to common shareholders (in thousands, except per share amounts):

		Three Months Ended March 31,
		2019			2018
Net income, as reported	$	1,419		$	49,238
Participating earnings ^(a)		(14	)		(568	)
Basic net income attributed to common shareholders		1,405			48,670
Reallocation of participating earnings ^(a)		—			2
Diluted net income attributed to common shareholders	$	1,405		$	48,672
Net income per common share:
Basic	$	0.01		$	0.20
Diluted	$	0.01		$	0.20

^(a)

Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

The following provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):

	Three Months Ended March 31,
	2019	2018
Weighted average common shares outstanding – basic	247,776	245,709
Effect of dilutive securities:
Director and employee restricted stock and performance based equity awards	1,378	885
Weighted average common shares outstanding – diluted	249,154	246,594

Weighted average common shares outstanding-basic for first quarter 2019 excludes 2.5 million shares of restricted stock held in our deferred compensation plan compared to 2.9 million shares in first quarter 2018 (although all awards are issued and outstanding upon grant). For first quarter 2019, equity grants of 1.6 million were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of our common shares and would be anti-dilutive to the computations compared to equity grants of 1.5 million in first quarter 2018. For purposes of calculating diluted weighted average common shares, non-vested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

(8) LEASES

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheet through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized but are disclosed below. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Our operating leases are reflected as operating lease ROU assets, accrued liabilities-current and operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement

less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

We lease certain office space, field equipment, vehicles and other equipment under cancelable and non-cancelable leases to support our operations. A more detailed description of our significant lease types is included below.

Office Agreements and Subleases

We rent office space from third parties for our corporate and field locations. Our office agreements are typically structured with non-cancelable terms of one to fifteen years. We have concluded our office agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

We also sublease some of our office space to third parties. All of our subleases have terms that end in 2020 or 2022. The sublease agreements are non-cancelable through the end of the term and both parties have substantive rights to terminate the lease when the term is complete. Our sublease agreements are not capitalized and are recorded as sublease income (as a component of lease costs) in the period the rent is received.

Field Equipment

We rent compressors and coolers from third parties in order to facilitate the downstream movement of our production from our drilling operations to market. Our compressor and cooler arrangements are typically structured with a non-cancelable primary term of one to two years and continue thereafter on a month-to-month basis subject to termination by either party with thirty days notice. We have concluded that our compressor and cooler rental agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreement subsequent to the primary term.

We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent short-term operating leases. The accounting guidance requires us to make an assessment at contract commencement if we are reasonably certain that we will exercise the option to extend the term. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig by rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the successful efforts method of accounting, these costs are capitalized as part of natural gas and oil properties on our balance sheet when paid. See also short-term lease costs below.

Vehicles

We rent our vehicle fleet from a third party for our drilling and operations personnel. Our vehicle agreements are non-cancelable for a minimum of one year and a maximum term of four to eight years depending on the type of vehicle. However, we have assumed a term of three years based on the period covered by options to terminate that we are reasonably certain to exercise. We have concluded our vehicle commitments are operating leases.

Significant Judgments

Transportation, Gathering and Processing Arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset. However, in limited circumstances, we do utilize substantially all of the capacity of a portion of the midstream system under our transportation gathering and/or processing service contract. These arrangements require judgment to determine whether our capacity of the underlying midstream asset represents a lease. Under all of these arrangements, we have concluded that (i) the midstream entity maintains control of and has the ability to optimize and/or expand the underlying system throughout the duration of the

contract term and (ii) the portion of the system or facility we utilize is highly integrated and interconnected to a broader system servicing a diverse set of customers. Consequently, the transportation, gathering and/or processing contract does not represent a lease of the underlying portion of the midstream system or facilities. We currently have not identified any of these commitments as leases.

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our incremental borrowing rate reflects the estimated rate of interest that we would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. We use the implicit rate in the limited circumstances in which that rate is readily determinable.

Practical Expedients and Accounting Policy Elections

Certain of our lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the practical expedient that exempts us from separating lease components from non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component.

In addition, for all of our existing asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases (that is, a lease that, at commencement, has a lease term of 12 months or less and does not include an option to purchase the underlying asset that we are reasonably certain to exercise). Accordingly, we recognize lease payments related to our short-term leases in our statement of operations on a straight-line basis over the lease term which has not changed from our prior recognition. To the extent that there are variable lease payments, we recognize those payments in our statement of operations in the period in which the obligation for those payments is incurred. Refer to “Nature of Leases” above for further information regarding those asset classes that include material short-term leases.

The components of our total lease expense for the three months ended March 31, 2019, the majority of which is included in general and administrative expense, are as follows (in thousands):

		Three Months Ended March 31, 2019
Operating lease cost	$	3,080
Variable lease expense ⁽¹⁾		1,151
Short-term lease expense ⁽²⁾		92
Sublease income		(875	)
Total lease expense	$	3,448

Short-term lease costs ⁽³⁾	$	9,164

⁽¹⁾

Variable lease payments that are not dependent on an index or rate are not included in the lease liability or ROU assets.

⁽²⁾

Short-term lease expense represents expense related to leases with a contract term of one year or less.

⁽³⁾

These short-term lease costs are related to leases with a contract term of one year or less and the majority of which are related to drilling rigs and are capitalized as part of natural gas and oil properties on our balance sheets.

Supplemental cash flow information related to our operating leases is included in the table below (in thousands):

Three Months Ended

March 31,

2019

Cash paid for amounts included in the measurement of lease liabilities

3,003

ROU assets added in exchange for lease obligations (since adoption)

187

Supplemental balance sheet information related to our operating leases is included in the table below (in thousands):

		March 31, 2019
Operating lease ROU assets	$	49,329
Accrued liabilities – current	$	(14,872	)
Operating lease liabilities – long-term	$	(41,759	)

Our weighted average remaining lease term and weighted average discount rate for our operating leases are as follows (in thousands):

March 31,

2019

Weighted Average Remaining Lease Term

6.4 Years

Weighted Average Discount Rate

6.1%

Our lease liabilities with enforceable contract terms that are greater than one year mature as follows (in thousands):

		Operating Leases
Remainder of 2019	$	14,872
2020		12,491
2021		9,618
2022		6,551
2023		6,479
Thereafter		20,113
Total lease payments	$	70,124
Less imputed interest		(13,493	)
Total lease liability	$	56,631

(9) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization ^(a)

	March 31, 2019			December 31, 2018
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	11,193,577		$	10,974,929
Unproved properties		2,106,568			2,110,277
Total		13,300,145			13,085,206
Accumulated depreciation, depletion and amortization		(4,194,876	)		(4,062,021	)
Net capitalized costs	$	9,105,269		$	9,023,185

^(a)	Includes capitalized asset retirement costs and the associated accumulated amortization.

(10) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at March 31, 2019 is shown parenthetically). No interest was capitalized during the three months ended March 31, 2019 or the year ended December 31, 2018 (in thousands).


		March 31, 2019			December 31, 2018
Bank debt (4.0%)	$	895,000		$	943,000
Senior notes:
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,531			741,531
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022		329,244			329,244
Other senior notes due 2022		590			590
Total senior notes		2,877,349			2,877,349
Senior subordinated notes:
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		3,821,329			3,869,329
Unamortized premium		4,408			4,741
Unamortized debt issuance costs		(35,088	)		(37,209	)
Total debt net of debt issuance costs	$	3,790,649		$	3,836,861

Bank Debt

In April 2018, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets and has a maturity date of April 13, 2023. The bank credit facility provides for a maximum facility amount of $4.0 billion and an initial borrowing base of $3.0 billion. The bank credit facility also provides for a borrowing base subject to redeterminations annually by May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 27, 2019, our borrowing base was reaffirmed for $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. As of March 31, 2019, our bank group was composed of twenty-seven financial institutions with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. On March 31, 2019, bank commitments totaled $2.0 billion and the outstanding balance under our bank credit facility was $895.0 million, before deducting debt issuance costs. Additionally, we had $279.8 million of undrawn letters of credit leaving $825.2 million of committed borrowing capacity available under the facility. During a non-investment grade period, borrowings under the bank credit facility can either be at the alternate base rate (“ABR,” as defined in the bank credit facility agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 4.0% for first quarter 2019 compared to 3.4% for first quarter 2018. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At March 31, 2019, the commitment fee was 0.30% and the interest rate margin was 1.50% on our LIBOR loans and 0.50% on our base rate loans.

At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants, will cease to apply and an additional financial covenant (as defined in the bank credit facility) will be imposed. During the investment grade period, borrowings under the credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or at the LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance would range from 0.15% to 0.30%. We currently do not have an investment grade debt rating.

Senior Notes and Senior Subordinated Notes

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior notes and senior subordinated notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and are subordinated to existing and future senior debt that we or our subsidiary guarantors are permitted to incur.

Guarantees

Range is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries, which are directly or indirectly owned by Range, of our senior notes, senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

•

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

•

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

Debt Covenants

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at March 31, 2019.

(11) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the three months ended March 31, 2019 is as follows (in thousands):

	Three Months Ended March 31, 2019
Beginning of period	$	312,754
Liabilities incurred		1,719
Liabilities settled		(896	)
Accretion expense		4,217
Change in estimate		(187	)
End of period		317,607
Less current portion		(5,485	)
Long-term asset retirement obligations	$	312,122

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

(12) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We utilize commodity swaps, collars, calls or swaptions to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. The fair value of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (“NYMEX”) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net gain of $3.0 million at March 31, 2019. These contracts expire monthly through December 2020. The following table sets forth our commodity-based derivative volumes by year as of March 31, 2019, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2019	Swaps	1,246,873 Mmbtu/day		$ 2.80
2020	Swaps	190,000 Mmbtu/day		$ 2.75
2019	Swaptions	150,000 Mmbtu/day		$ 2.81 ⁽¹⁾
2020	Swaptions	140,000 Mmbtu/day		$ 2.78 ⁽¹⁾
November – December 2019	Swaptions	20,000 Mmbtu/day		$ 3.20 ⁽¹⁾
January – March 2020	Swaptions	20,000 Mmbtu/day		$ 3.20 ⁽¹⁾

Crude Oil
2019	Swaps	7,472 bbls/day		$ 55.47
2020	Swaps	2,557 bbls/day		$ 60.53
2019	Collars	1,000 bbls/day		$ 63.00 − $ 73.02

NGLs (C2-Ethane)
April – June 2019	Swaps	500 bbls/day		$0.35/gallon

NGLs (C3-Propane)
April – June 2019	Swaps	8,500 bbls/day		$ 0.88/gallon
April – June 2019	Collars	1,000 bbls/day		$ 0.90 − $ 0.96

NGLs (C5-Natural Gasoline)
2019	Swaps	2,658 bbls/day		$ 1.39/gallon

⁽¹⁾

Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volumes. We have swaps in place for 2019 for 150,000 Mmbtu/day on which the counterparty can elect to extend the contract through December 2020 at a weighted average price of $2.81. In addition, we have swaps in place for November and December 2019 where, if the counterparty elects to double the volume, we would have additional swaps in place for 20,000 Mmbtu/day at a weighted average price of $3.20. In 2020, if the counterparty elects to double the volume, we would have additional swaps in place for 140,000 Mmbtu/day at a weighted average price of $2.78. In addition, for January through March 2020, we have additional swaps in place, if the counterparty elects to double the volume, we would have an additional 20,000 Mmbtu/day at a weighted average price of $3.20.

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. We recognize all changes in fair value of these derivatives as earnings in derivative fair value income or loss in the periods in which they occur.

Basis Swap Contracts

In addition to the swaps, collars and swaptions described above, at March 31, 2019, we had natural gas basis swap contracts which lock in the differential between NYMEX Henry Hub and certain of our physical pricing indices. These contracts settle monthly through October 2021 and include a total volume of 69,775,000 Mmbtu. The fair value of these contracts was a loss of $3.4 million at March 31, 2019.

At March 31, 2019, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly in April through June and October through December of 2019 and monthly in 2020 and include a total volume of 1,875,000 barrels. The fair value of these contracts was a loss of $809,000 at March 31, 2019.

Freight Swap Contracts

In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at March 31, 2019, we had freight swap contracts on the Baltic Exchange which lock in the freight rate for a specific trade route. These contracts settle monthly through December 2019 and cover 10,000 metric tons per month with a fair value loss of $103,000 at March 31, 2019.

Derivative Assets and Liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of March 31, 2019 and December 31, 2018 is summarized below. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. The tables below provide additional information relating to our master netting arrangements with our derivative counterparties (in thousands):

		March 31, 2019
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	15,883	$	(7,441	)	$	8,442
	–swaptions		6,487		(4,634	)		1,853
	–basis swaps		838		(838	)		—
Crude oil	–swaps		2,871		(4,648	)		(1,777	)
	−collars		1,252		(750	)		502
NGLs	−C2 ethane swaps		216		(216	)		—
	–C3 propane swaps		7,471		(3,108	)		4,363
	−C3 propane collars		967		(967	)		—
	–C3 propane spread swaps		3,425		(3,425	)		—
	−C5 natural gasoline swaps		4,643		(3,474	)		1,169
Freight	−swaps		37		(37	)		—
		$	44,090	$	(29,538	)	$	14,552

		March 31, 2019
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(13,030	)	$	7,441	$	(5,589	)
	–swaptions		(12,550	)		4,634		(7,916	)
	–basis swaps		(4,278	)		838		(3,440	)
Crude oil	–swaps		(11,197	)		4,648		(6,549	)
	−collars		—			750		750
NGLs	−C2 ethane swaps		—			216		216
	–C3 propane swaps		—			3,108		3,108
	–C3 propane collars		—			967		967
	–C3 propane spread swaps		(4,234	)		3,425		(809	)
	–C5 natural gasoline swaps		(37	)		3,474		3,437
Freight	–swaps		(140	)		37		(103	)
		$	(45,466	)	$	29,538	$	(15,928	)

		December 31, 2018
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	20,834	$	(11,748	)	$	9,086
	–swaptions		5,200		(3,883	)		1,317
	–basis swaps		6,468		(2,822	)		3,646
Crude oil	–swaps		26,481		(651	)		25,830
	–collars		5,945		(707	)		5,238
NGLs	–C3 propane swaps		18,719		(589	)		18,130
	–C3 propane collars		8,538		—			8,538
	–C3 propane spread swaps		8,984		(8,868	)		116
	–NC4 butane swaps		4,084		—			4,084
	–C5 natural gasoline swaps		17,371		—			17,371
Freight	–swaps		—		(561	)		(561	)
		$	122,624	$	(29,829	)	$	92,795

		December 31, 2018
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(18,332	)	$	11,748	$	(6,584	)
	–swaptions		(7,972	)		3,883		(4,089	)
	–basis swaps		(1,702	)		2,822		1,120
Crude oil	–swaps		—			651		651
	–collars		—			707		707
NGLs	–C3 propane swaps		—			589		589
	–C3 propane spread swaps		(8,868	)		8,868		—
Freight	–swaps		(561	)		561		—
		$	(37,435	)	$	29,829	$	(7,606	)

The effects of our derivatives on our consolidated statements of operations are summarized below (in thousands):


		Derivative Fair Value (Loss) Income
		Three Months Ended March 31,
		2019			2018
Commodity swaps	$	(57,418	)	$	(16,536	)
Swaptions		(3,291	)		3,599
Collars		(4,524	)		(77	)
Calls		—			177
Basis swaps		3,415			(864	)
Freight swaps		87			(308	)
Total	$	(61,731	)	$	(14,009	)

(13) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

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, which are either directly or indirectly observable as of the reporting date.

•

Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Significant uses of fair value measurements include:

•

impairment assessments of long-lived assets; and

•

recorded value of derivative instruments and trading securities.

The need to test long-lived assets can be based on several indicators, including a significant reduction in prices of natural gas, oil and condensate, NGLs, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located.

Fair Values – Recurring

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

	Fair Value Measurements at March 31, 2019 using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Carrying Value as of March 31, 2019
Trading securities held in the deferred compensation plans	$	63,774	$	—		$	—			$	63,774

Derivatives –swaps		—		6,820			—				6,820
–collars		—		1,252			967				2,219
–basis swaps		—		(4,249	)		—				(4,249	)
–freight swaps		—		(103	)		—				(103	)
–swaptions		—		—			(6,063	)			(6,063	)

	Fair Value Measurements at December 31, 2018 using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Carrying Value as of December 31, 2018
Trading securities held in the deferred compensation plans	$	57,293	$	—		$	—		$	57,293
Derivatives –swaps		—		69,156			—			69,156
–collars		—		5,945			8,538			14,483
–basis swaps		—		4,883			—			4,883
–freight swaps		—		(561	)		—			(561	)
–swaptions		—		—			(2,772	)		(2,772	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. As of March 31, 2019, a portion of our natural gas derivative instruments contains swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a pre-determined date. Derivatives in Level 3 are measured at fair value with a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	As of March 31, 2019
Balance at December 31, 2018	$	5,766
Total losses:
Included in earnings		(3,442	)
Settlements		(7,420	)
Balance at March 31, 2019	$	(5,096	)

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For first quarter 2019, interest and dividends were $179,000 and the mark-to-market adjustment was a gain of $5.1 million compared to interest and dividends of $168,000 and a mark-to-market loss of $7.5 million in first quarter 2018.

Fair Values – Non-recurring

Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. In first quarter 2018, there were indicators that the carrying value of certain of our oil gas properties in Oklahoma may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their remaining fair value was measured using a market approach based upon the potential sale of these Oklahoma properties, which is a Level 3 input. We recorded non-cash charges in first quarter 2018 of $7.3 million related to these properties of which the fair value was determined to be $32.5 million. There were no impairment charges in first quarter 2019.

Fair Values – Reported

The following presents the carrying amounts and the fair values of our financial instruments as of March 31, 2019 and December 31, 2018 (in thousands):

	March 31, 2019						December 31, 2018
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	14,552		$	14,552		$	92,795		$	92,795
Marketable securities ^(a)		63,774			63,774			57,293			57,293
(Liabilities):
Commodity swaps, options and basis swaps		(15,928	)		(15,928	)		(7,606	)		(7,606	)
Bank credit facility ^(b)		(895,000	)		(895,000	)		(943,000	)		(943,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(486,042	)		(475,952	)		(455,972	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(574,139	)		(580,032	)		(519,343	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(333,020	)		(329,244	)		(305,989	)
Other senior notes due 2022 ^(b)		(590	)		(593	)		(590	)		(581	)
5.00% senior notes due 2023 ^(b)		(741,531	)		(718,996	)		(741,531	)		(654,683	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(696,983	)		(750,000	)		(616,313	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,539	)		(22,214	)		(21,638	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,811	)		(19,054	)		(17,072	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,085	)		(7,712	)		(6,690	)
Deferred compensation plan ^(c)		(88,334	)		(88,334	)		(80,092	)		(80,092	)

^(a)	Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges.

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs.

^(c)	The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input.

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payable. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical and expected incurrence of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations and operating lease liabilities. For additional information, see Note 11.

Concentrations of Credit Risk

As of March 31, 2019, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate securities are obtained as deemed necessary to limit our risk of loss. Our allowance for uncollectable receivables was $6.1 million at both March 31, 2019 and December 31, 2018. Our derivative exposure to credit risk is diversified primarily among major investment grade financial institutions, where we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. At March 31, 2019, our derivative counterparties include twenty financial institutions, of which all but four are secured lenders in our bank credit facility. At March 31, 2019, our net derivative liability includes a net payable of $3.9 million to these four counterparties that are not participants in our bank credit facility.

(14) STOCK-BASED COMPENSATION PLANS

Stock-Based Awards

We have one active equity-based stock plan, our Amended and Restated 2005 Equity-Based Incentive Compensation Plan, which we refer to as the 2005 Plan. Under this plan, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock and performance units. Unlike the other forms of stock-based compensation, the mark-to-market adjustment of the liability related to the vested restricted stock held in our deferred compensation plan is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The following details the allocation of stock-based compensation to functional expense categories (in thousands):

		Three Months Ended March 31,
		2019		2018
Direct operating expense	$	591	$	591
Brokered natural gas and marketing expense		385		285
Exploration expense		373		751
General and administrative expense		8,815		23,911
Total stock-based compensation	$	10,164	$	25,538

Stock-Based Awards

Restricted Stock Awards. We grant restricted stock units under our equity-based stock compensation plan. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three year period, contingent on the recipient’s continued employment. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also utilize treasury shares when available.

Stock-Based Performance Units. We grant three types of performance share awards: two based on performance conditions measured against internal performance metrics (Production Growth Awards or “PG-PSUs” and Reserve Growth

Awards or “RG-PSUs”) and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Awards or “TSR-PSUs”).

Each unit granted represents one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can be from zero to 200% based on performance achieved and (2) the value of our common stock on the vesting date which is determined by the Compensation Committee. Dividend equivalents may accrue during the performance period and are paid in stock at the end of the performance period. The performance period for the TSR-PSUs is three years. The performance period for the PG/RG-PSUs is based on annual performance targets earned over a three-year period.

SARs. At March 31, 2019, there were no SARs outstanding.

Restricted Stock – Equity Awards

In first three months 2019, we granted 2.8 million restricted stock Equity Awards to employees at an average price of $10.59 which generally vest over a three-year period compared to 1.8 million at an average price of $17.00 in first three months 2018. We recorded compensation expense for these awards of $7.1 million in first three months 2019 compared to $6.5 million in the same period of 2018. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash.

Restricted Stock – Liability Awards

In first three months 2019, we granted 1.0 million shares of restricted stock Liability Awards as compensation to employees at an average price of $10.46 which vests generally over a three-year period. In first three months 2018, we granted 674,000 shares of restricted stock Liability Awards as compensation to employees at an average price of $15.21 with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $1.0 million in first three months 2019 compared to $8.1 million in first three months 2018. The majority of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The following is a summary of the status of our non-vested restricted stock outstanding at March 31, 2019:

	Restricted Stock Equity Awards					Restricted Stock Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2018		1,386,088		$	20.04		184,579		$	15.65
Granted		2,792,438			10.59		1,009,653			10.46
Vested		(447,405	)		16.10		(134,573	)		11.71
Forfeited		(103,093	)		13.56		—			—
Outstanding at March 31, 2019		3,628,028		$	13.44		1,059,659		$	11.21

Stock-Based Performance Units

Production Growth and Reserve Growth Awards. The PG-PSUs and RG-PSUs vest at the end of the three-year performance period. The performance metrics for each year are set by the Compensation Committee no later than March 31 of such year. If the performance metric for the applicable period is not met, then the portion is considered forfeited. The following is a summary of our non-vested PG/RG-PSUs awards outstanding at March 31, 2019:


	Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2018	536,798	$	15.61
Units granted ^(a)	345,202		10.32
Forfeited	—		—
Outstanding at March 31, 2019	882,000	$	11.70

^(a)	Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 200% depending on achievement of specifically identified performance targets.

We recorded PG/RG-PSUs compensation expense of $1.6 million in first three months 2019 compared to $5.3 million in first three months 2018.

TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three-year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of PSUs granted during first three months 2019 and 2018:

	Three Months Ended March 31,
	2019			2018
Risk-free interest rate		2.4	%		2.4	%
Expected annual volatility		46	%		47	%
Grant date fair value per unit	$	11.34		$	18.51

The following is a summary of our non-vested TSR – PSUs award activities:

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2018		1,067,886		$	27.81
Units granted ^(a)		314,152			11.34
Vested and issued ^(b)		(12,283	)		30.47
Forfeited		(79,058	)		30.47
Outstanding at March 31, 2019		1,290,697		$	23.62

^(a)	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 200% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.

^(b)	Includes 12,283 TSR-PSUs awards issued related to the 2016 performance period where the return on our common stock was in the 20^th percentile for the February 2016 grant. The remaining February 2016 awards are considered to be forfeited.

We recorded TSR-PSUs compensation expense of $443,000 in first three months 2019 compared to $5.4 million in the same period of 2018.

SARs

Information with respect to our SARs activity is summarized below.

	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2018	1,104		$	81.74
Expired	(1,104	)		81.74
Outstanding at March 31, 2019	—		$	—

Other Postretirement Benefits

Effective fourth quarter 2017, as part of our officer succession plan, we implemented a postretirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features. There were $92,000 of estimated prior service costs amortized from accumulated other comprehensive income into general and administrative expense in both the three months ended March 31, 2019 and 2018. Those employees that qualify for the new postretirement health care plan were also fully vested in all equity grants. Effective October 2018, officers who qualify for the plan are required to provide reasonable notice of retirement and beginning in 2019 are fully vested after providing one year of service after the grant date.

Deferred Compensation Plan

Our deferred compensation plan gives non-employee directors and officers the ability to defer all or a portion of their salaries, bonuses or director fees and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution to officers which vests over three years. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected as deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value as other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market loss of $3.6 million in first quarter 2019 compared to mark-to-market gain of $7.4 million in first quarter 2018. The Rabbi Trust held 3.5 million shares (2.4 million of which were vested) of Range stock at March 31, 2019 compared to 2.6 million shares (2.4 million of which were vested) at December 31, 2018.

(15) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have no preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2018:

	Three Months Ended March 31, 2019		Year Ended December 31, 2018
Beginning balance		249,510,022		248,129,430
Restricted stock grants		981,905		865,095
Restricted stock units vested		633,460		434,046
Performance stock units issued		12,283		73,985
Performance stock dividends		464		2,164
Treasury shares issued		—		5,302
Ending balance		251,138,134		249,510,022

(16) SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Net cash provided from operating activities included:
Income taxes refunded from taxing authorities	$	—		$	7,518
Interest paid		(54,632	)		(57,536	)
Non-cash investing and financing activities included:
Increase in asset retirement costs capitalized		1,532			5,063
Increase (decrease) in accrued capital expenditures		22,764			(77,365	)

(17) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions, administrative proceedings and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these actions, proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. We will continue to evaluate our litigation and regulatory proceedings quarterly and will establish and adjust any estimated liability as appropriate to reflect our assessment of the then current status of litigation and regulatory proceedings. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.

(18) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are included in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. We do not have any suspended exploratory well costs as of March 31, 2019 or December 31, 2018.

(19) Costs Incurred for Property Acquisition, Exploration and Development ^(a)

	Three Months Ended March 31, 2019		Year Ended December 31, 2018
	(in thousands)
Acquisitions:
Acreage purchases	$	14,634	$	62,390
Oil and gas properties		—		1,683
Development		209,827		834,552
Exploration:
Drilling		542		1,380
Expense		7,837		32,196
Stock-based compensation expense		373		1,921
Gas gathering facilities:
Development		1,063		10,218
Subtotal		234,276		944,340
Asset retirement obligations		1,532		28,826
Total costs incurred	$	235,808	$	973,166

^(a)	Includes costs incurred whether capitalized or expensed.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company engaged in the exploration, development and acquisition of natural gas and crude oil properties primarily in the Appalachian and North Louisiana regions of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or an area-by-area basis.

Our overarching business objective is to build stockholder value through returns focused development, measured on a per share debt-adjusted basis, for both reserves and production. Our strategy to achieve our business objective is to increase reserves and production through internally generated drilling projects coupled with occasional acquisitions and divestitures of non-core assets. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire, produce and market natural gas, NGLs and crude oil reserves. Looking to the future, our goal is to target annual production growth within operating cash flows. The price risk on a portion of our production is mitigated using commodity derivative contracts. However, these derivative contracts are limited in duration. Prices for natural gas, NGLs and oil fluctuate widely and affect:

•

revenues, profitability and cash flow;

•

the quantity of natural gas, NGLs and oil we can economically produce;

•

the quantity of natural gas, NGLs and oil shown as proved reserves;

•

the amount of cash flows available for capital expenditures; and

•

our ability to borrow and raise additional capital.

We prepare our financial statements in conformity with U.S. GAAP which requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenue, net income and cash flow. Natural gas, NGLs and oil are commodities and prices for these commodities are inherently volatile. The following table lists related benchmarks for natural gas, oil and NGLs for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change			%
Benchmarks:
Average NYMEX prices ^(a)
Natural gas (per mcf)	$	3.14	$	2.99	$	0.15		5	%
Oil (per bbl)		54.86		62.88		(8.02	)	(13	%)
Mont Belvieu NGLs composite (per gallon) ^(b)		0.54		0.62		(0.08	)	(13	%)

^(a)	Based on weighted average of bid week prompt month prices on the New York Mercantile Exchange (“NYMEX”).

^(b)	Based on our estimated NGLs product composition per barrel.

Our price realizations may differ from the benchmarks for many reasons, including quality, location or production being sold at different indices.

Consolidated Results of Operations

Overview of First Quarter 2019 Results

Our financial results are significantly impacted by commodity prices. For first quarter 2019, we experienced a decrease in revenue from the sale of natural gas, NGLs and oil due to a 17% decrease in net realized prices (average prices including all derivative settlements and third party transportation costs paid by us) partially offset by 3% higher production volumes when compared to the same quarter of 2018. Daily production in first quarter 2019 averaged 2.3 Bcfe compared to 2.2 Bcfe in the same period of the prior year with the increase due to our successful Marcellus horizontal drilling program. Average natural gas differentials per mcf were below NYMEX while operating costs were lower when compared to the same period of 2018.

During first quarter 2019, we recognized net income of $1.4 million, or $0.01 per diluted common share compared to net income of $49.2 million, or $0.20 per diluted common share, during first quarter 2018. The decrease in net income for first quarter 2019 from first quarter 2018 is primarily due to an unfavorable derivative fair value loss (or the non-cash fair value adjustments related to our derivatives) and lower net realized prices which were partially offset by lower operating costs and higher production volumes.

Our first quarter 2019 financial and operating performance included the following results:

•

3% production growth over the same period of 2018 (despite our 2018 asset sales);

•

revenue from the sale of natural gas, NGLs and oil decreased 4% from the same period of 2018 with a 6% decrease in average realized prices (before cash settlements on our derivatives) and an increase in production volumes;

•

revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 1% from the same period of 2018;

•

reduced direct operating expenses per mcfe 16% from the same period of 2018 (see discussion on page 35);

•

reduced general and administrative expense per mcfe 34% from the same period of 2018 (see discussion on page 35);

•

reduced interest expense per mcfe 7% from the same period of 2018;

•

reduced our depletion, depreciation and amortization (“DD&A”) rate per mcfe by 17% from the same period of 2018;

•

entered into additional derivative contracts for 2019, 2020 and 2021;

•

reduced borrowings on our bank credit facility $47.4 million from December 2018; and

•

realized $260.7 million of cash flow from operating activities.

We generated $260.7 million of cash flow from operating activities in first quarter 2019, a decrease of $109.9 million from first quarter 2018, which reflects lower net realized prices, the impact of our 2018 asset sales and lower comparative working capital inflows ($463,000 outflow during first quarter 2019 compared to $54.6 million inflow in first quarter 2018), somewhat offset by higher production volumes.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. Our revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. In first quarter 2019, natural gas, NGLs and oil sales decreased 4% compared to first quarter 2018 with a 6% decrease in average realized prices (before cash settlements on our derivatives) partially offset by a 3% increase in average daily production. The following table illustrates the primary components of natural gas, NGLs, oil and condensate sales for the three months ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018		Change			%
Natural gas, NGLs and oil sales
Natural gas	$	434,720	$	431,573	$	3,147		1	%
NGLs		197,813		202,527		(4,714	)	(2	%)
Oil		39,121		62,529		(23,408	)	(37	%)
Total natural gas, NGLs and oil sales	$	671,654	$	696,629	$	(24,975	)	(4	%)

Our production continues to grow through drilling success and additional NGLs extraction, which is partially offset by the natural production decline of our wells and asset sales. First quarter 2019 production volumes from the Marcellus Shale were 2.0 Bcfe per day, an increase of 12% when compared to the same period of 2018. First quarter 2019 production volumes from our North Louisiana properties were approximately 228.6 Mmcfe per day, a decline of 38% when compared to the same period of the prior year. Our production for the three months ended March 31, 2019 and 2018 is set forth in the following table:

	Three Months Ended March 31,
	2019		2018		Change			%
Production ^(a)
Natural gas (mcf)		140,521,663		134,954,095		5,567,568		4	%
NGLs (bbls)		9,612,547		9,270,031		342,516		4	%
Crude oil (bbls)		805,550		1,063,434		(257,884	)	(24	%)
Total (mcfe) ^(b)		203,030,245		196,954,885		6,075,360		3	%

Average daily production ^(a)
Natural gas (mcf)		1,561,352		1,499,490		61,862		4	%
NGLs (bbls)		106,806		103,000		3,806		4	%
Crude oil (bbls)		8,951		11,816		(2,865	)	(24	%)
Total (mcfe) ^(b)		2,255,892		2,188,388		67,504		3	%

^(a)	Represents volumes sold regardless of when produced.

^(b)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Our average realized price received (including all derivative settlements and third-party transportation costs) during first quarter 2019 was $1.94 per mcfe compared to $2.34 per mcfe in first quarter 2018. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Average realized prices (excluding derivative settlements) do not include derivative settlements or third party transportation costs which are reported in transportation, gathering, processing and compression expense on the accompanying consolidated statements of operations. Average realized prices (excluding derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers.

	Three Months Ended March 31,
	2019		2018		Change			%
Average Prices:
Average realized prices (excluding derivative settlements):
Natural gas (per mcf)	$	3.09	$	3.20	$	(0.11	)	(3	%)
NGLs (per bbl)		20.58		21.85		(1.27	)	(6	%)
Crude oil and condensate (per bbl)		48.56		58.80		(10.24	)	(17	%)
Total (per mcfe) ^(a)		3.31		3.54		(0.23	)	(6	%)
Average realized prices (including all derivative settlements):
Natural gas (per mcf)	$	3.09	$	3.44	$	(0.35	)	(10	%)
NGLs (per bbl)		23.17		20.20		2.97		15	%
Crude oil and condensate (per bbl)		49.61		50.98		(1.37	)	(3	%)
Total (per mcfe) ^(a)		3.43		3.58		(0.15	)	(4	%)
Average realized prices (including all derivative settlements and third-party transportation costs paid by Range):
Natural gas (per mcf)	$	1.74	$	2.27	$	(0.53	)	(23	%)
NGLs (per bbl)		11.35		10.77		0.58		5	%
Crude oil and condensate (per bbl)		49.61		50.98		(1.37	)	(3	%)
Total (per mcfe) ^(a)		1.94		2.34		(0.40	)	(17	%)

^(a)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis:

		Three Months Ended March 31,
		2019			2018
Average natural gas differentials above or (below) NYMEX	$	(0.05	)	$	0.21
Realized gains (losses) on basis hedging	$	0.09		$	(0.08	)

The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third party transportation costs paid by Range) (in thousands, except prices):

		Three Months Ended March 31,
		2018		Price Variance			Volume Variance		2019
Natural gas
Price (per mcf)	$	3.20	$	(0.11	)	$	—	$	3.09
Production (Mmcf)		134,954		—			5,567		140,521
Natural gas sales	$	431,573	$	(14,658	)	$	17,805	$	434,720

		Three Months Ended March 31,
		2018		Price Variance			Volume Variance		2019
NGLs
Price (per bbl)	$	21.85	$	(1.27	)	$	—	$	20.58
Production (Mbbls)		9,270		—			343		9,613
NGLs sales	$	202,527	$	(12,197	)	$	7,483	$	197,813

		Three Months Ended March 31,
		2018		Price Variance			Volume Variance			2019
Crude oil
Price (per bbl)	$	58.80	$	(10.24	)	$	—		$	48.56
Production (Mbbls)		1,063		—			(257	)		806
Crude oil sales	$	62,529	$	(8,245	)	$	(15,163	)	$	39,121

		Three Months Ended March 31,
		2018		Price Variance			Volume Variance		2019
Consolidated
Price (per mcfe)	$	3.54	$	(0.23	)	$	—	$	3.31
Production (Mmcfe)		196,955		—			6,075		203,030
Total natural gas, NGLs and oil sales	$	696,629	$	(46,464	)	$	21,489	$	671,654

Transportation, gathering, processing and compression expense was $302.7 million in first quarter 2019 compared to $244.6 million in first quarter 2018. These third-party costs are higher in first quarter 2019 when compared to first quarter 2018 due to our production growth in the Marcellus Shale where we have third-party transportation, gathering, processing and compression agreements. We also have new in-service pipelines, higher NGLs costs due to higher production and prices and higher NGLs expense in North Louisiana due to fully utilizing amounts that were previously accrued for as capacity commitments. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three months ended March 31, 2019 and 2018 on a per mcf and per barrel basis (in thousands, except for costs per unit):

	Three Months Ended March 31,
		2019		2018		Change	%
Natural gas	$	189,082	$	157,234	$	31,848	20	%
NGLs		113,573		87,394		26,179	30	%
Total	$	302,655	$	244,628	$	58,027	24	%

Natural gas (per mcf)	$	1.35	$	1.17	$	0.18	15	%
NGLs (per bbl)	$	11.82	$	9.43	$	2.39	25	%

Derivative fair value loss was $61.7 million in first quarter 2019 compared to $14.0 million in first quarter 2018. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three months ended March 31, 2019 and 2018 (in thousands):

		Three Months Ended March 31,
		2019			2018
Derivative fair value loss per consolidated statements of operations	$	(61,731	)	$	(14,009	)

Non-cash fair value (loss) gain: ⁽¹⁾
Natural gas derivatives	$	(11,146	)	$	(41,097	)
Oil derivatives		(39,499	)		(9,342	)
NGLs derivatives		(36,378	)		27,815
Freight derivatives		458			(310	)
Total non-cash fair value loss ⁽¹⁾	$	(86,565	)	$	(22,934	)

Net cash (payment) receipt on derivative settlements:
Natural gas derivatives	$	(872	)	$	32,508
Oil derivatives		842			(8,315	)
NGL derivatives		24,864			(15,268	)
Total net cash receipt	$	24,834		$	8,925

⁽¹⁾

Non-cash fair value adjustments on commodity derivatives is a non-U.S. GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under U.S. GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of operations.

Brokered natural gas, marketing and other revenue in first quarter 2019 was $138.2 million compared to $60.0 million in first quarter 2018 with significantly higher brokered sales volumes and prices as we continue to optimize our transportation portfolio.

Operating Costs per Mcfe

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change			%
Direct operating expense	$	0.16	$	0.19	$	(0.03	)	(16	%)
Production and ad valorem tax expense		0.06		0.05		0.01		20	%
General and administrative expense		0.23		0.35		(0.12	)	(34	%)
Interest expense		0.25		0.27		(0.02	)	(7	%)
Depletion, depreciation and amortization expense		0.68		0.82		(0.14	)	(17	%)

Direct operating expense was $33.2 million in first quarter 2019 compared to $38.1 million in first quarter 2018. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our direct operating costs decreased in first quarter 2019 primarily due to lower water handling costs and the impact of the sale of our Northern Oklahoma properties in the prior year partially offset by higher workover costs. Our production volumes increased 3% in first quarter 2019. We incurred $4.5 million ($0.02 per mcfe) of workover costs in first quarter 2019 compared to $3.3 million ($0.02 per mcfe) in first quarter 2018. On a per mcfe basis, direct operating expense in first quarter 2019 decreased 16% to $0.16 from $0.19 in the same period of 2018 with the decrease resulting from lower water handling costs and the sale of our Northern Oklahoma properties, which occurred in third quarter 2018. The following table summarizes direct operating expense per mcfe for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change			%
Lease operating expense	$	0.14	$	0.17	$	(0.03	)	(18	%)
Workovers		0.02		0.02		—		—	%
Stock-based compensation (non-cash)		—		—		—		—	%
Total direct operating expense	$	0.16	$	0.19	$	(0.03	)	(16	%)

Production and ad valorem taxes are paid based on market prices rather than hedged prices. This expense category also includes the Pennsylvania impact fee. Production and ad valorem taxes (excluding the impact fee) were $2.8 million in first quarter 2019 compared to $3.3 million in first quarter 2018 due to lower prices and an increase in volumes not subject to production taxes. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania. Included in first quarter 2019 is an $8.5 million impact fee compared to $6.6 million in first quarter 2018. The following table summarizes production and ad valorem taxes per mcfe for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change		%
Production taxes	$	0.01	$	0.01	$	—	—	%
Ad valorem taxes		—		—		—	—	%
Impact fee		0.05		0.04		0.01	25	%
Total production and ad valorem taxes	$	0.06	$	0.05	$	0.01	20	%

General and administrative (“G&A”) expense was $46.6 million in first quarter 2019 compared to $68.4 million in first quarter 2018. The first quarter 2019 decrease of $21.8 million when compared to the same period of 2018 is primarily due to lower stock-based compensation of $15.1 million, lower legal costs, lower consulting fees, lower salaries and wages and lower technology costs. At March 31, 2019, the number of G&A employees decreased 4% when compared to March 31, 2018. On a per mcfe basis, first quarter 2019 G&A expense decreased 34% from first quarter 2018 due to lower stock-based

compensation costs, lower legal costs, lower consulting fees, lower technology costs and the impact of higher production volumes.

The following table summarizes G&A expenses per mcfe for the three months March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change			%
General and administrative	$	0.19	$	0.23	$	(0.04	)	(17	%)
Stock-based compensation (non-cash)		0.04		0.12		(0.08	)	(67	%)
Total general and administrative expense	$	0.23	$	0.35	$	(0.12	)	(34	%)

Interest expense was $51.5 million in first quarter 2019 compared to $52.4 million in first quarter 2018. The following table presents information about interest expense per mcfe for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019			2018			Change			%
Bank credit facility	$	0.06		$	0.07		$	(0.01	)	(14	%)
Senior notes		0.18			0.19			(0.01	)	(5	%)
Subordinated notes		—			—			—		—	%
Amortization of deferred financing costs and other		0.01			0.01			—		—	%
Total interest expense	$	0.25		$	0.27		$	(0.02	)	(7	%)
Average debt outstanding (in thousands)	$	3,917,596		$	4,220,796		$	(303,200	)	(7	%)
Average interest rate ^(a)		5.1	%		4.9	%		0.2	%	4	%

^(a) Includes commitment fees but excludes debt issue costs and amortization of discounts.

On an absolute basis, the decrease in interest expense for first quarter 2019 from the same period of 2018 was primarily due to lower average outstanding debt balances partially offset by slightly higher average interest rates. Average debt outstanding on the bank credit facility for first quarter 2019 was $991.4 million compared to $1.3 billion in first quarter 2018 and the weighted average interest rate on the bank credit facility was 4.0% in first quarter 2019 compared to 3.4% in first quarter 2018.

Depletion, depreciation and amortization expense was $138.7 million in first quarter 2019 compared to $162.3 million in first quarter 2018. This decrease is due to a 16% decrease in depletion rates somewhat offset by a 3% increase in production volumes. Depletion expense, the largest component of DD&A expense, was $0.66 per mcfe in first quarter 2019 compared to $0.79 per mcfe in first quarter 2018. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. Our depletion rate per mcfe continues to decline due to the mix of production from our properties with lower depletion rates and asset sales. The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change			%
Depletion and amortization	$	0.66	$	0.79	$	(0.13	)	(16	%)
Depreciation		0.01		0.01		—		—	%
Accretion and other		0.01		0.02		(0.01	)	(50	%)
Total DD&A expense	$	0.68	$	0.82	$	(0.14	)	(17	%)

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, termination costs, deferred compensation plan expenses, impairment of proved properties and gain or loss on sale of assets. Stock-based compensation includes the amortization of restricted stock grants and PSUs. The

following table details the allocation of stock-based compensation to functional expense categories for the three months ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018
Direct operating expense	$	591	$	591
Brokered natural gas and marketing expense		385		285
Exploration expense		373		751
General and administrative expense		8,815		23,911
Total stock-based compensation	$	10,164	$	25,538

Brokered natural gas and marketing expense was $132.3 million in first quarter 2019 compared to $55.6 million in first quarter 2018. The increase reflects significantly higher broker purchase volumes, purchase prices and transportation costs resulting from the optimization of our transportation portfolio compared to the prior year. The following table details our brokered natural gas, marketing and other net margin for the three months ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019			2018			Change			%
Brokered natural gas sales	$	134,801		$	55,861		$	78,940		141	%
Brokered NGLs sales		424			304			120		39	%
Other marketing revenue		2,989			3,814			(825	)	(22	%)
Brokered natural gas purchases ⁽¹⁾		(129,510	)		(52,787	)		(76,723	)	145	%
Brokered NGLs purchases		(134	)		(304	)		170		(56	%)
Other marketing expense		(2,661	)		(2,503	)		(158	)	6	%
Net brokered natural gas and marketing net margin	$	5,909		$	4,385		$	1,524		35	%

⁽¹⁾

Includes transportation costs.

Exploration expense was $8.2 million in first quarter 2019 compared to $7.7 million in first quarter 2018 due to higher delay rentals expenses partially offset by lower seismic and personnel costs. The following table details our exploration expense for the three months ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018		Change			%
Seismic	$	—	$	462	$	(462	)	(100	%)
Delay rentals and other		6,059		4,111		1,948		47	%
Personnel expense		1,779		2,393		(614	)	(26	%)
Dry hole expense		—		2		(2	)	(100	%)
Stock-based compensation expense		373		751		(378	)	(50	%)
Total exploration expense	$	8,211	$	7,719	$	492		6	%

Abandonment and impairment of unproved properties was $12.7 million in first quarter 2019 compared to $11.8 million in first quarter 2018. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. In certain circumstances, our future plans to develop acreage may accelerate our impairment. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Termination costs were a reduction of $37,000 in first quarter 2018. There were no termination costs in first quarter 2019.

Deferred compensation plan expense was a loss of $3.6 million in first quarter 2019 compared to a gain of $7.4 million in first quarter 2018. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Our stock price increased from $9.57 at December 31, 2018 to $11.24 at March 31, 2019. In the same period of the prior year, our stock price decreased from $17.06 at December 31, 2017 to $14.54 at March 31, 2018.

Impairment of proved properties was $7.3 million in first quarter 2018. In first quarter 2018, we recorded impairment expense related to certain of our oil and gas properties in Oklahoma. These Oklahoma assets were evaluated for impairment due to the possibility of sale. There were no proved property impairments in first quarter 2019.

Loss (gain) on the sale of assets was a loss of $189,000 in first quarter 2019 compared to a gain of $23,000 in first quarter 2018.

Income tax expense was $5.7 million in first quarter 2019 compared to $42.7 million in first quarter 2018. For first quarter 2019, the effective tax rate was 80.0% compared to 46.4% in 2018. The 2019 and 2018 effective tax rates were different than the statutory tax rate due to state income taxes (including adjustments to state income tax valuation allowances), equity compensation and other discrete tax items which are detailed below. We expect our effective tax rate to be approximately 25% for the remainder of 2019, before any discrete tax items (dollars in thousands).

	Three Months Ended March 31,
	2019			2018
Total income before income taxes	$	7,107		$	91,914
U.S. federal statutory rate		21	%		21	%
Total tax expense at statutory rate		1,492			19,302

State and local income taxes, net of federal benefit		818			4,494
Equity compensation		3,391			664
Change in valuation allowances:
State net operating loss carryforwards & other		352			15,678
Other		231			1,381
Permanent differences and other		(596	)		1,157
Total expense for income taxes	$	5,688		$	42,676
Effective tax rate		80.0	%		46.4	%

Forward-Looking Statements

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2018, as filed with the SEC on February 25, 2019.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Cash Flow

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity

needs are satisfied by borrowings under our bank credit facility. Because of this, and because our principal source of operating cash flows (proved reserves to be produced in future years) cannot be reported as working capital, we often have low or negative working capital. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. As of March 31, 2019, we have entered into derivative agreements covering 409.2 Bcfe for the remainder of 2019 and 128.2 Bcfe for 2020, not including our basis swaps.

The following table presents sources and uses of cash and cash equivalents for the three months ended March 31, 2019 and 2018 (in thousands):


	Three Months Ended March 31,
		2019			2018
Sources of cash and cash equivalents
Operating activities	$	260,694		$	370,572
Disposal of assets		332			40
Borrowing on credit facility		566,000			528,000
Other		13,596			13,485
Total sources of cash and cash equivalents	$	840,622		$	912,097

Uses of cash and cash equivalents
Additions to natural gas and oil properties	$	(190,014	)	$	(308,641	)
Repayment on credit facility		(614,000	)		(557,000	)
Acreage purchases		(23,646	)		(25,355	)
Additions to field service assets		(576	)		(239	)
Dividends paid		(5,023	)		(4,971	)
Other		(7,420	)		(15,812	)
Total uses of cash and cash equivalents	$	(840,679	)	$	(912,018	)

Net cash provided from operating activities in first three months 2019 was $260.7 million compared to $370.6 million in first three months 2018. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2018 to 2019 reflects lower net realized prices (a decrease of 17%), the impact of our 2018 asset sales and lower working capital cash inflow somewhat offset by higher production volumes. As of March 31, 2019, we have hedged more than 65% of our projected total production for the remainder of 2019, with more than 80% of our projected natural gas production hedged. Net cash provided from operating activities is affected by a 3% increase in production and working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for first three months 2019 were negative $463,000 compared to positive $54.6 million for first three months 2018.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operating activities, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales. We must find new reserves and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which require substantial capital expenditures. We continue to take steps to ensure we have adequate capital resources and liquidity to fund our capital expenditure program. In first three months 2019, we entered into additional commodity derivative contracts for 2019, 2020 and 2021 to protect future cash flows.

During first three months 2019, our net cash provided from operating activities of $260.7 million was used to fund approximately $214.2 million of capital expenditures (including acreage acquisitions). At March 31, 2019, we had $488,000 in cash and total assets of $9.6 billion.

Long-term debt at March 31, 2019 totaled $3.8 billion, including $895.0 million outstanding on our bank credit facility, $2.9 billion of senior notes and $49.0 million of senior subordinated notes. Our available committed borrowing capacity at March 31, 2019 was $825.2 million, with an additional $1.0 billion in borrowing base capacity available for increased liquidity potential. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash

generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives contracts currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. While our expectation is to operate within our internally generated cash flow, to the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity securities may be issued to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A material decline in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and operate profitably. We establish a capital budget at the beginning of each calendar year and review it during the course of the year, taking into account various factors including the commodity price environment. Our 2019 capital budget is currently $756.0 million.

Commodity prices have remained volatile and have declined during first quarter 2019 compared to fourth quarter 2018. We have adjusted and must continue to adjust our business through efficiencies and cost reductions to compete in the current price environment which also requires reductions in overall debt levels over time. We plan to continue to work towards profitable growth within cash flows. We would expect to monitor the market and look for opportunities to refinance or reduce debt based on market conditions. We believe we are well-positioned to manage the challenges presented in a low commodity price environment and that we can endure continued volatility in current and future commodity prices by:

•

exercising discipline in our capital program with the expectation of funding our capital expenditures with operating cash flow and, if required, with borrowings under our bank credit facility;

•

continuing to optimize our drilling, completion and operational efficiencies; and

•

continuing to manage price risk by hedging our production volumes.

Credit Arrangements

As of March 31, 2019, we maintained a revolving credit facility with a borrowing base of $3.0 billion and aggregate lender commitments of $2.0 billion, which we refer to as our bank credit facility. The bank credit facility, during a non-investment grade period, is secured by substantially all of our assets and has a maturity date of April 13, 2023. See Note 10 to our unaudited consolidated financial statements for additional information regarding our bank debt. Availability under the bank credit facility is subject to a borrowing base set by the lenders annually with an option to set more often in certain circumstances. Availability under the bank credit facility, during an investment grade period, is limited to aggregate lender commitments. As of March 31, 2019, the outstanding balance under our credit facility was $895.0 million. Additionally, we had $279.8 million of undrawn letters of credit leaving $825.2 million of committed borrowing capacity available under the facility at the end of first quarter 2019, with an additional $1.0 billion in borrowing base capacity for potential increases in lender commitments.

Our bank credit facility imposes limitations on the payment of dividends and other restricted payments (as defined under our bank credit facility). The bank credit facility also contains customary covenants relating to debt incurrence, liens, investments and financial ratios. We were in compliance with all covenants at March 31, 2019. See Note 10 to our unaudited consolidated financial statements for additional information regarding our bank debt.

Cash Dividend Payments

On February 28, 2019, our Board of Directors declared a dividend of two cents per share ($5.0 million) on our outstanding common stock, which was paid on March 29, 2019 to stockholders of record at the close of business on March 15, 2019. The amount of future dividends is subject to discretionary declaration by the Board of Directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments. As of March 31, 2019, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of March 31, 2019, we had a total of $279.8 million of undrawn letters of credit under our bank credit facility.

Since December 31, 2018, there have been no material changes to our contractual obligations other than a $47.4 million decrease in our outstanding bank credit facility balance.

Interest Rates

At March 31, 2019, we had approximately $3.8 billion of debt outstanding. Of this amount, $2.9 billion bore interest at fixed rates averaging 5.2%. Bank debt totaling $895.0 million bears interest at floating rates, which was 4.0% at March 31, 2019. The 30-day LIBOR Rate on March 31, 2019 was approximately 2.5%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2019 would cost us approximately $9.0 million in additional annual interest expense.

Off-Balance Sheet Arrangements

We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under cash contractual obligations.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. We expect costs for the remainder of 2019 to continue to be a function of supply.

Certain New Accounting Standards Not Yet Adopted

The effects of certain new accounting standards that have not been adopted yet are discussed in Note 3 to the consolidated financial statements.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Changes in natural gas prices affect us more than changes in oil prices because approximately 67% of our December 31, 2018 proved reserves are natural gas. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2018 to March 31, 2019.

Commodity Price Risk

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (referred to as a swaption in the table below). At March 31, 2019, our derivative program includes swaps, collars and swaptions. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation as of March 31, 2019, approximated a net unrealized pretax gain of $3.0 million. These contracts expire monthly through December 2020. At March 31, 2019, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price	Fair Market Value
Natural Gas				(in thousands)
2019	Swaps	1,246,873 Mmbtu/day	$ 2.80	$	2,247
2020	Swaps	190,000 Mmbtu/day	$ 2.75	$	606
2019	Swaptions	150,000 Mmbtu/day	$ 2.81 ⁽¹⁾	$	(8,803)
2020	Swaptions	140,000 Mmbtu/day	$ 2.78 ⁽¹⁾	$	2,210
November – December 2019	Swaptions	20,000 Mmbtu/day	$ 3.20 ⁽¹⁾	$	198
January – March 2020	Swaptions	20,000 Mmbtu/day	$ 3.20 ⁽¹⁾	$	332

Crude Oil
2019	Swaps	7,472 bbls/day	$ 55.47	$	(9,817)
2020	Swaps	2,557 bbls/day	$ 60.53	$	1,492
2019	Collars	1,000 bbls/day	$ 63.00 − $ 73.02	$	1,252

NGLs (C2-Ethane)
April – June 2019	Swaps	500 bbls/day	$0.35/gallon	$	216

NGLs (C3-Propane)
April – June 2019	Swaps	8,500 bbls/day	$ 0.88/gallon	$	7,471
April – June 2019	Collars	1,000 bbls/day	$ 0.90 − $ 0.96	$	967

NGLs (C5-Natural Gasoline)
2019	Swaps	2,658 bbls/day	$ 1.39/gallon	$	4,605

⁽¹⁾

Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volumes. We have swaps in place for 2019 for 150,000 Mmbtu/day on which the counterparty can elect to extend the contract through December 2020 at a weighted average price of $2.81. In addition, we have swaps in place for November and December 2019, where, if the counterparty elects to double the volume, we would have an additional 20,000 Mmbtu/day at a weighted average price of $3.20. In 2020, if the counterparty elects to double the volume, we would have additional swaps in place for 140,000 Mmbtu/day at a weighted average price of $2.78. In addition, for January through March 2020, we have swaps in place where, if the counterparty elects to double the volume, we would have an additional 20,000 Mmbtu/day at a weighted average price of $3.20.

In the future, we expect our NGLs production to continue to increase. We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.

Currently, the Appalachian region has limited local demand and infrastructure to accommodate ethane. We have agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot assure you that these facilities will remain available. Mariner East has been shut-down for most of 2019 due to subsidence issues. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our rich residue gas.

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. Therefore, in addition to the swaps discussed above, we have entered into natural gas basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX Henry Hub price because of basis adjustments, relative quality and other factors. Basis swap agreements effectively fix the basis adjustments. The fair value of the natural gas basis swaps was a loss of $3.4 million at March 31, 2019 and they settle monthly through October 2021.

At March 31, 2019, we also had propane basis contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly in April through June and October through December of 2019 and monthly in 2020 and include a total volume of 1,875,000 barrels. The fair value of these contracts was a loss of $809,000 on March 31, 2019.

The following table shows the fair value of our swaps and basis swaps and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at March 31, 2019. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

				Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
				Increase of						Decrease of
	Fair Value			10%			25%			10%			25%
Swaps	$	6,820		$	(135,063	)	$	(337,310	)	$	136,893		$	342,252
Collars		2,219			(1,202	)		(3,114	)		1,529			4,226
Swaptions		(6,063	)		(42,597	)		(120,315	)		33,002			73,439
Basis swaps		(4,249	)		(5,688	)		(14,238	)		5,757			14,392
Freight swaps		(103	)		359			896			(361	)		(903	)

Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At March 31, 2019, our derivative counterparties include twenty financial institutions, of which all but four are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial. Our propane sales from the Marcus Hook facility near Philadelphia are short-term and are to a single purchaser. Our ethane sales from Marcus Hook are to a single international customer bearing a credit rating similar to Range.

Interest Rate Risk

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior and senior subordinated debt and variable rate bank debt. At March 31, 2019, we had $3.8 billion of debt outstanding. Of this amount, $2.9 billion bears interest at fixed rates averaging 5.2%. Bank debt totaling $895.0 million bears interest at floating rates, which was 4.0% on March 31, 2019. On March 31, 2019, the 30-day LIBOR Rate was approximately 2.5%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2019, would cost us approximately $9.0 million in additional annual interest expense.

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. 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 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 effective as of March 31, 2019 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

See Note 17 to our unaudited consolidated financial statements entitled “Commitments and Contingencies” included in Part I Item 1 above for a summary of our legal proceedings, such information being incorporated herein by reference.

Environmental Proceedings

Our subsidiary, Range Resources – Appalachia, LLC, was notified by the Pennsylvania Department of Environmental Protection (“DEP”), in second quarter 2015, that it intends to assess a civil penalty under the Clean Streams Law and the 2012 Oil and Gas Act in connection with one well in Lycoming County. The DEP has directed us to prevent methane and other substances from escaping from this gas well into groundwater and a stream. We have considerable evidence that this well is not leaking and pre-drill testing of surrounding water wells showed the presence of methane in the water before commencement of our operations. While we intend to vigorously assert this position with the DEP, resolution of this matter may nonetheless result in monetary sanctions of more than $100,000.

ITEM 1A.

RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2018. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

ITEM 6.

EXHIBITS

Exhibit index

Exhibit Number		Exhibit Description

	3.1	Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

	3.2	Amended and Restated By-laws of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2016)

	10.1	Sixth Amended and Restated Credit Agreement, dated April 13, 2018 among Range Resources Corporation (as borrower) and JPMorgan Chase Bank, N.A. as administrative agent and the other lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 16, 2018)

	10.2	Voting Support and Nomination Agreement, dated as of July 9, 2018, by and among Range Resources Corporation, SailingStone Capital Partners LLC and SailingStone Holdings LLC (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 001-12209) as filed with the SEC on July 10, 2018)

	31.1*	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2*	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1**	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2**	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	101. INS*	XBRL Instance Document – the XBRL Instance Document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document

	101. SCH*	XBRL Taxonomy Extension Schema

	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

**	furnished herewith

SIGNATURES

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

Date: April 22, 2019

RANGE RESOURCES CORPORATION

By:		/s/ MARK S. SCUCCHI
		Mark S. Scucchi
		Senior Vice President and Chief Financial Officer

Date: April 22, 2019

RANGE RESOURCES CORPORATION

By:		/s/ DORI A. GINN
		Dori A. Ginn
		Senior Vice President – Controller and Principal Accounting Officer