Montage Resources Corp (Form: 10-Q, Received: 05/09/2019 16:10:42)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended 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: 001-36511

Montage Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	46-4812998
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

122 West John Carpenter Freeway, Suite 300 Irving, TX	75039
(Address of principal executive offices)	(Zip code)

(469) 444-1647

(Registrant’s telephone number, including area code)

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 such 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.

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Trading Symbol(s)		Name of each exchange on which registered
Common Stock, Par Value $0.01 Per Share		MR		New York Stock Exchange

Number of shares of the registrant’s common stock outstanding at May 6, 2019: 35,617,374 shares

MONTAGE RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

TABLE OF CONTENTS

		Page

Cautionary Statement Regarding Forward-Looking Statements		3

PART I - Financial Information		5
Item 1.	Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45

PART II - Other Information		46
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 6.	Exhibits	47

Index to Exhibits		47
Signatures		49

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (the “Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and income or losses, projected costs and capital expenditures, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “will,” “plan,” “would,” “could,” “endeavor,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are or were, when made, based on our current expectations and assumptions about future events and are or were, when made, based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the Securities and Exchange Commission (the “SEC”) on March 15, 2019.

Forward-looking statements may include statements about, among other things:

•

realized prices for natural gas, natural gas liquids (“NGLs”) and oil and the volatility of those prices;

•

write-downs of our natural gas and oil asset values due to declines in commodity prices;

•

our business strategy;

•

our reserves, including the impact of current commodity prices on our estimated year end reserves;

•

general economic conditions;

•

our financial strategy, liquidity and capital required for developing our properties and the timing related thereto;

•

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

•

our hedging strategy and results;

•

future drilling plans;

•

competition and government regulations, including those related to hydraulic fracturing;

•

the anticipated benefits under our commercial agreements;

•

marketing of natural gas, NGLs and oil;

•

leasehold and business acquisitions, including our acquisition of Blue Ridge Mountain Resources, Inc., and joint ventures;

•

leasehold terms expiring before production can be established and our costs to extend such terms;

•

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

•

credit markets;

•

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

•

plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, legal and environmental risks, drilling and other operating risks, regulatory changes, commodity price volatility and the significant decline of the price of natural gas, NGLs and oil from historic highs, inflation, lack of availability of drilling, production and processing equipment and services, counterparty credit risk, the uncertainty inherent in estimating natural gas, NGLs and oil reserves and in projecting future rates of production, cash flow and access to capital, risks associated with our level of indebtedness, the timing of development expenditures, and the other risks described in “Item 1A. Risk Factors” of our Annual Report on Form 10-K, filed with the SEC on March 15, 2019.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect new information obtained or events or circumstances that occur after the date of this Quarterly Report.

PART I - FINANCIAL INFORMATION

Item 1.

Financial Statements

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

(Unaudited)

	March 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7,592		$	5,959
Accounts receivable		120,802			119,332
Assets held for sale		2,294			—
Other current assets		6,347			8,639
Total current assets		137,035			133,930

PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method:
Unproved properties		557,583			482,475
Proved oil and gas properties, net		1,101,772			807,583
Other property and equipment, net		13,146			6,300
Total property and equipment, net		1,672,501			1,296,358

OTHER NONCURRENT ASSETS
Other assets		8,182			3,481
Operating lease right-of-use asset		44,222			—
Assets held for sale		8,514			—
TOTAL ASSETS	$	1,870,454		$	1,433,769

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	141,410		$	116,735
Accrued capital expenditures		25,116			12,979
Accrued liabilities		61,960			56,909
Accrued interest payable		10,876			21,661
Liabilities associated with assets held for sale		8,212			—
Operating lease liability		19,787			—
Total current liabilities		267,361			208,284

NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		498,469			497,778
Revolving credit facility		97,500			32,500
Asset retirement obligations		24,148			7,110
Other liabilities		1,021			611
Operating lease liability		25,592			—
Liabilities associated with assets held for sale		6,639			—
Total liabilities		920,730			746,283
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, 50,000,000 authorized, no shares issued and outstanding		—			—
Common stock, $0.01 par value, 1,000,000,000 authorized, 35,682,480 and 20,169,063 shares issued and outstanding, respectively		382			3,043
Additional paid in capital		2,349,527			2,065,119
Treasury stock, shares at cost; 2,478,798 and 1,747,624 shares, respectively		(8,768	)		(3,357	)
Accumulated deficit		(1,391,417	)		(1,377,319	)
Total stockholders' equity		949,724			687,486
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,870,454		$	1,433,769

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

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share data)

(Unaudited)

	For the Three Months Ended March 31,
	2019			2018
REVENUES
Natural gas, oil and natural gas liquids sales	$	131,828		$	110,184
Brokered natural gas and marketing revenue		9,530			8
Other revenue		139			—
Total revenues		141,497			110,192

OPERATING EXPENSES
Lease operating		7,525			9,390
Transportation, gathering and compression		41,168			27,689
Production and ad valorem taxes		2,848			2,445
Brokered natural gas and marketing expense		9,459			48
Depreciation, depletion, amortization and accretion		29,897			31,311
Exploration		16,789			15,278
General and administrative		28,930			9,757
(Gain) loss on sale of assets		2			(267	)
Other expense		24			—
Total operating expenses		136,642			95,651
OPERATING INCOME		4,855			14,541
OTHER INCOME (EXPENSE)
Loss on derivative instruments		(4,931	)		(4,215	)
Interest expense, net		(13,840	)		(12,952	)
Total other income (expense), net		(18,771	)		(17,167	)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(13,916	)		(2,626	)
Income tax benefit (expense)		—			—
LOSS FROM CONTINUING OPERATIONS		(13,916	)		(2,626	)
Loss from discontinued operations, net of income tax		(182	)		—
NET LOSS	$	(14,098	)	$	(2,626	)

NET LOSS PER COMMON SHARE
Basic	$	(0.55	)	$	(0.13	)
Diluted	$	(0.55	)	$	(0.13	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		25,564			19,563
Diluted		25,564			19,563

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

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Number of Shares		Common Stock ($0.01 Par)		Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2017		17,516,024	$	2,637	$	1,967,958		$	(2,096	)	$	(1,396,145	)	$	572,354
Stock-based compensation		—		—		1,981			—			—			1,981
Equity issuance costs		—		—		(145	)		—			—			(145	)
Shares of common stock issued in asset acquisition, net of equity issuance costs		2,521,573		378		89,642			—			—			90,020
Issuance of common stock upon vesting of equity- based compensation awards, net of shares withheld for income tax withholdings		80,477		18		(18	)		(935	)		—			(935	)
Net loss		—		—		—			—			(2,626	)		(2,626	)
Balances, March 31, 2018		20,118,074	$	3,033	$	2,059,418		$	(3,031	)	$	(1,398,771	)	$	660,649

	Number of Shares		Common Stock ($0.01 Par)			Additional Paid-in- Capital			Treasury Stock			Accumulated Deficit			Total
Balances, December 31, 2018		20,169,063	$	3,043		$	2,065,119		$	(3,357	)	$	(1,377,319	)	$	687,486
Stock-based compensation		—		—			6,001			—			—			6,001
Equity issuance costs		—		—			(30	)		—			—			(30	)
Shares of common stock issued in merger, net of equity issuance costs		15,013,520		150			275,609			—			—			275,759
Reverse split 1:15		—		(2,833	)		2,833			—			—			—
Issuance of common stock upon vesting of equity- based compensation awards, net of shares withheld for income tax withholdings		499,897		22			(5	)		(5,411	)		—			(5,394	)
Net loss		—		—			—			—			(14,098	)		(14,098	)
Balances, March 31, 2019		35,682,480	$	382		$	2,349,527		$	(8,768	)	$	(1,391,417	)	$	949,724

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

MONTAGE RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	For the Three Months Ended March 31,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(14,098	)	$	(2,626	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion, amortization and accretion		29,950			31,311
Exploration expense		9,600			6,790
Stock-based compensation		6,001			1,981
Net cash for plugging wells		(48	)		—
Loss on derivative instruments		4,931			4,215
Net cash receipts (payments) on settled derivatives		(3,186	)		141
(Gain) loss on sale of assets		2			(267	)
Amortization of deferred financing costs		629			554
Amortization of debt discount		333			332
Changes in operating assets and liabilities:
Accounts receivable		25,812			(35,499	)
Other assets		(188	)		(459	)
Accounts payable and accrued liabilities		(68,643	)		(3,179	)
Net cash provided by (used in) operating activities		(8,905	)		3,294
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(58,530	)		(66,441	)
Capital expenditures for other property and equipment		(184	)		(155	)
Proceeds from sale of assets		1			4,099
Cash proceeds from merger		12,894			—
Change in deposits and other long term assets		(3	)		—
Net cash used in investing activities		(45,822	)		(62,497	)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs		(3,102	)		(48	)
Repayments of long-term debt		(98	)		(92	)
Proceeds (repayments) from revolving credit facility		65,000			65,000
Equity issuance costs		(30	)		(145	)
Employee tax withholding for settlement of equity compensation awards		(5,410	)		(935	)
Net cash provided by financing activities		56,360			63,780
Net increase in cash and cash equivalents		1,633			4,577
Cash and cash equivalents at beginning of period		5,959			17,224
Cash and cash equivalents at end of period	$	7,592		$	21,801
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	24,198		$	23,638
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	16,691		$	85
Additions of other property through debt financing	$	—		$	174
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$	45,287		$	8,864
Asset acquisition through stock issuance	$	—		$	90,020
BRMR Merger consideration	$	275,759		$	—

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

MONTAGE RESOURCES CORPORATION

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Nature of Operations

Montage Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale, Indian Castle/Flat Creek Shales and Marcellus Shale prospective areas.

Note 2—Basis of Presentation

The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2018, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. All such adjustments are of a normal recurring nature. These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 15, 2019.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2019 or any other future periods.

Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3—Summary of Significant Accounting Policies describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the condensed consolidated financial statements are the following:

•

estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion, amortization and accretion and impairment of capitalized costs of oil and natural gas properties;

•

estimates of asset retirement obligations;

•

estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;

•

impairment of undeveloped properties and other assets; and

•

depreciation and depletion of property and equipment.

Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions.

Note 3—Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits.

(b) Accounts Receivable

Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of March 31, 2019 or December 31, 2018.

The Company accrues revenue due to timing differences between the delivery of natural gas, NGLs, and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $83.2 million and $94.1 million of accrued revenues, net of certain expenses, at March 31, 2019 and December 31, 2018, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

Oil and Natural Gas Properties

The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion, amortization and accretion expense (see “Depreciation, Depletion, Amortization and Accretion” below).

Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs.

Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.

A summary of property and equipment including oil and natural gas properties is as follows (in thousands):

	March 31, 2019			December 31, 2018
Oil and natural gas properties:
Unproved	$	557,583		$	482,475
Proved		2,511,575			2,188,233
Gross oil and natural gas properties		3,069,158			2,670,708
Less accumulated depreciation, depletion and amortization		(1,409,803	)		(1,380,650	)
Oil and natural gas properties, net		1,659,355			1,290,058
Other property and equipment		21,662			14,460
Less accumulated depreciation		(8,516	)		(8,160	)
Other property and equipment, net		13,146			6,300
Property and equipment, net	$	1,672,501		$	1,296,358

Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves.

The Company capitalized interest expense totaling $0.7 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively.

Other Property and Equipment

Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition.

(d) Revenue Recognition

Product Revenue

The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received one month after the sale has occurred.

Natural Gas

Under the Company’s natural gas sales contracts, the Company delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellhead to delivery points specified under sales contracts. To deliver natural gas to these points, the Company uses third parties to gather, compress, process and transport the natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receive a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as transportation, gathering and compression expense.

NGLs

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company deliver the product to the purchaser at an agreed upon delivery point and that the Company receives a specific index price adjusted for pricing differentials and certain downstream costs incurred by third parties. The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs to further process and transport NGLs are recorded as transportation, gathering and compression expense.

Oil

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks at central stabilization facilities and well pads and collects a contractually agreed upon index price, net of pricing differentials. The Company transfers control of the product from the central stabilization facilities and well pads to the purchaser and recognizes revenue based on the contract price.

Marketing Revenue

Brokered natural gas and marketing revenues are derived from activities to purchase and sell third-party natural gas and to market excess firm transportation capacity to third parties. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore the Company recognizes revenue on a gross basis, with costs to purchase and transport natural gas presented as brokered natural gas and marketing expense. Contracts to sell third party natural gas are generally subject to similar terms as contracts to sell the Company’s produced natural gas and NGLs. The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the price received from the purchaser.

Disaggregation of Revenue

The following table illustrates the revenue disaggregated by type for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
Revenues (in thousands)
Natural gas sales	$	81,825	$	58,483
NGL sales		21,248		19,743
Oil sales		28,755		31,958
Brokered natural gas and marketing revenue		9,530		8
Other revenue		139		—
Total revenues	$	141,497	$	110,192

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient allowed in the revenue accounting standard that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligations are part of a contract that has an original expected duration of one year or less.

For any product sales that have a contract term greater than one year, the Company has also utilized the practical expedient that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, any product sales that have a contractual term greater than one year have no long-term fixed considerations.

Contract Balances

Under the Company’s sales contracts, customers are invoiced once performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers was $83.2 million and $94.1 million at March 31, 2019 and December 31, 2018, respectively.

(e) Concentration of Credit Risk

The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances (if any), by product or service as of March 31, 2019 and December 31, 2018 (in thousands):

	March 31, 2019		December 31, 2018
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	83,188	$	94,107
Joint interest owners		35,559		24,830
Derivatives		1,878		372
Other		177		23
Total	$	120,802	$	119,332

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the States of Ohio, Pennsylvania and West Virginia. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($3.3) million and a net asset position of $5.7 million at March 31, 2019 and December 31, 2018, respectively. Other than as provided by its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of March 31, 2019 and December 31, 2018, the Company did not have past-due receivables from or payables to any of such counterparties.

(f) Depreciation, Depletion, Amortization, and Accretion

Oil and Natural Gas Properties

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $29.5 million and $30.9 million for the three months ended March 31, 2019 and 2018, respectively and is included in Depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations.

Other Property and Equipment

Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.4 million and $0.5 million for the three months ended March 31, 2019 and 2018, respectively. This amount is included in Depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations.

(g) Impairment of Long-Lived Assets

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. There were no impairments of proved properties for the three months ended March 31, 2019 or the three months ended March 31, 2018.

When an impairment charge is recognized it represents a significant Level 3 measurement in the fair value hierarchy. The primary input used is the Company’s forecasted discount net cash flows.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

Unproved oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $9.6 million and $6.7 million for the three months ended March 31, 2019 and 2018, respectively. These costs are included in exploration expense in the condensed consolidated statements of operations.

(h) Income Taxes

The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not (i.e. a likelihood greater than 50 percent) that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date.

The Company applies Topic 740’s intra-period income tax allocation rules using the with and without approach, to allocate income tax expense (benefit) among continuing operations, discontinued operations, other comprehensive income (loss), and additional paid-in capital as required.

(i) Fair Value of Financial Instruments

The Company has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1—Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3—Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

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.

(j) Derivative Financial Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells.

Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities.

The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy.

(k) Asset Retirement Obligation

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “Asset Retirement and Environmental Obligations,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate.

Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

The following table sets forth the changes in the Company’s ARO liability for the three months ended March 31, 2019 (in thousands):

	Three Months Ended March 31, 2019
Asset retirement obligations, beginning of period	$	7,110
Accretion		347
Additional liabilities incurred		49
Obligation for wells acquired		20,188
Liabilities settled via plugging		(26	)
Less: current ARO portion (accrued liabilities)		(3,520	)
Asset retirement obligations, end of period	$	24,148

The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement.

(l) Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

(m) Segment Reporting

The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.

(n) Debt Issuance Costs

The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

(o) Recent Accounting Pronouncements

Recently Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases’ classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period with early adoption permitted. In July 2018, the FASB issued ASU 2018-11, “Leases: Targeted Improvements”. The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, “Leases: Codification Improvements”, which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.

The Company adopted these standards effective January 1, 2019 using the optional transition method of adoption. The Company implemented a third party sponsored lease accounting information system to facilitate the accounting and financial reporting requirements, and implemented processes and controls to review new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment. See “Note 7 – Leases” for the disclosures required by the standards.

Note 4—Acquisitions

Eclipse Resources-PA, LP Acquisition

On January 18, 2018, Eclipse Resources-PA, LP, a wholly owned subsidiary of the Company, completed its acquisition of certain oil and gas leases, one producing well and other oil and gas rights and interests covering approximately 44,500 net acres located in Tioga and Potter Counties, Pennsylvania from Travis Peak Resources, LLC for an aggregate adjusted purchase price of $90 million, which was paid entirely with approximately 2.5 million shares of the Company’s common stock (the “Flat Castle Acquisition”). The transaction was accounted for as an asset acquisition. Approximately $86 million of the purchase price was allocated to unproved oil and natural gas properties and approximately $4 million was allocated to proved oil and gas properties associated with the producing well acquired. In addition, the Company capitalized approximately $1 million of transaction costs related to the acquisition.

During the year ended December 31, 2018, the Company assigned its option to purchase all of the outstanding equity interests of Cardinal NE Holdings, LLC (“Cardinal”), a wholly owned subsidiary of Cardinal Midstream II, LLC which owns midstream infrastructure with associated gathering rights on acreage in the Indian Castle and Flat Creek Shales, to a third party. The third party exercised its option to purchase all of the outstanding equity interests of Cardinal in July 2018.

Merger with Blue Ridge Mountain Resources

On February 28, 2019, the Company completed its previously announced business combination transaction with Blue Ridge Mountain Resources, Inc. (“BRMR”) pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company (the “BRMR Merger”).

As a result of the BRMR Merger, each share of common stock, par value $0.01 per share, of BRMR issued and outstanding immediately prior to the effective time of the BRMR Merger (the “Effective Time”), excluding certain Excluded Shares (as such term is defined in the Merger Agreement), was converted into the right to receive from the Company 0.29506 of a validly issued, fully-paid, and nonassessable share of common stock, par value $0.01 per share, of the Company. The exchange ratio reflects an adjustment to account for the 15-to-1 reverse stock split (See Note 13— Earnings (Loss) Per Share). Former stockholders of BRMR received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the BRMR Merger. In addition, upon completion of the BRMR Merger, all shares of BRMR restricted stock and all BRMR restricted stock units and performance interest awards were converted into the right to receive shares of common stock of the Company or cash, in each case as specified in the Merger Agreement.

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

Purchase Price	February 28, 2019
Fair value of Montage common stock issued	$	263,487
Fair value of BRMR share-based and other compensation		12,272
Total Fair Value of Consideration	$	275,759

Cash and cash equivalents		12,894
Accounts receivable		25,884
Assets held for sale - current		2,296
Other current assets		1,702
Unproved properties		84,742
Proved oil and gas properties		218,866
Other property and equipment		7,059
Other assets		2,461
Operating lease right-of-use asset		7,900
Assets held for sale - long-term		8,505
Total assets acquired	$	372,309
Accounts payable		(16,571	)
Accrued capital expenditures		(5,807	)
Accrued liabilities		(31,619	)
Operating lease liability - current		(1,977	)
Liabilities associated with assets held for sale - current		(7,683	)
Asset retirement obligations		(20,188	)
Operating lease liability - noncurrent		(5,923	)
Liabilities associated with assets held for sale - long-term		(6,782	)
Total liabilities assumed	$	(96,550	)

Net identifiable assets	$	275,759

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighed average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgements and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

The following unaudited pro forma financial information represents the combined results for the Company as though the BRMR Merger had been completed on January 1, 2018. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the BRMR Merger taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.

	For the Three Months Ended March 31,
(in thousands, except per share data) (unaudited)	2019			2018
Pro forma total revenues	$	184,155		$	133,900
Pro forma net loss from continuing operations	$	(26,760	)	$	(4,731	)
Pro forma loss per share (basic and diluted)	$	(0.78	)	$	(0.28	)

Note 5—Sale of Oil and Natural Gas Property Interests

During the three months ended March 31, 2018, the Company received approximately $3.8 million from a completed asset sale of approximately 400 acres to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties.

During the three months ended March 31, 2018, the Company received approximately $0.3 million from an additional completed asset sale of approximately 50 acres to a third party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

Note 6—Assets Held for Sale and Discontinued Operations

Assets Held for Sale

As a result of the BRMR Merger, the Company acquired certain assets that met the criteria for assets held for sale at the acquisition date, comprised of the net assets of Magnum Hunter Production, Inc. (“MHP”), a wholly-owned subsidiary of BRMR located primarily in Kentucky and Tennessee.

The following summarizes assets and liabilities held for sale at March 31, 2019:

(in thousands)	March 31, 2019
Accounts receivable	$	1,797
Other current assets		497
Total current assets held for sale	$	2,294

Proved oil and gas properties, net	$	8,270
Other noncurrent assets		244
Total noncurrent assets held for sale	$	8,514

Accounts payable	$	2,583
Accrued liabilities		5,312
Other current liabilities		317
Total current liabilities associated with assets held for sale	$	8,212

Asset retirement obligations	$	6,029
Other liabilities		610
Total noncurrent liabilities associated with assets held for sale	$	6,639

Discontinued Operations

The Company determined that the planned divestiture of MHP met the assets held for sale criteria and the criteria for classification as discontinued operations as of March 31, 2019. The Company included the results of operations for MHP for the period from March 1, 2019 through March 31, 2019 presented in discontinued operations as follows:

	For the Three Months Ended March 31,
(in thousands)	2019
Revenues	$	949
Depreciation, depletion, amortization and accretion		(52	)
Other operating expenses		(1,079	)
Loss from discontinued operations, net of tax		(182	)
Gain on disposal of discontinued operations, net of tax		—
Loss from discontinued operations, net of tax	$	(182	)

Total operating and investing cash flows of discontinued operations for the period from March 1, 2019 through March 31, 2019 were as follows:

	For the Three Months Ended March 31,
(in thousands)	2019
Net cash provided by operating activities	$	1,046
Net cash provided by investing activities	$	1

Note 7—Leases

The Company leases drilling rigs, compressors, vehicles, office space, and other equipment under non-cancelable operating leases expiring through 2036. Certain lease agreements may include options to renew the lease, terminate the lease early, or may purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including the options to extend or terminate the lease when such an option is reasonably certain to be exercised.

As discussed in Note 3—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 “Leases (Topic 842)” on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients for all asset classes: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and recognition of variable nonlease payments as variable lease expense.

On January 1, 2019, the Company recorded a total of $10.4 million in right-of-use assets and corresponding new lease liabilities on its Condensed Consolidated Balance Sheets representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less, taking into account extensions if reasonably certain to be exercised, are considered short-term leases and are not recorded on the balance sheet.

The Company incurred $2.3 million in operating lease cost during the three months ended March 31, 2019. The operating lease right-of-use assets were reported in other noncurrent assets and the current and noncurrent portions of the operating lease liabilities were reported in other current liabilities and other liabilities, respectively, on the Condensed Consolidated Balance Sheets. As of March 31, 2019, the operating right-of-use assets were $44.2 million and operating lease liabilities were $45.4 million, of which $19.8 million was classified as current. As of March 31, 2019, the weighted average remaining lease term was 3.5 years and the weighted average discount rate was 5.6%.

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

	For the Three Months Ended March 31,
	2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	870
Investing cash flows from operating leases	$	1,452
ROU assets added in exchange for lease obligations (upon adoption)	$	10,434
ROU assets and lease obligations acquired in BRMR Merger	$	7,900
ROU assets added in exchange for lease obligations (since adoption)	$	27,169

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

	Operating Leases
Remainder of 2019	$	16,362
2020		15,132
2021		6,574
2022		4,630
2023		2,467
Thereafter		4,438
Total lease payments	$	49,603
Less imputed interest		(4,224	)
Total lease liability	$	45,379

Note 8—Derivative Instruments

Commodity Derivatives

The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes.

The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of March 31, 2019, the Company’s derivative instruments were with Bank of Montreal, J Aron, Morgan Stanley, Capital One N.A., BP Energy Company, KeyBank N.A, NextEra Energy, Inc., Shell Oil Company and EDF Energy. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of March 31, 2019, for future production periods:

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		90,000	April 2019 – December 2019	$	2.84
		15,000	April 2019 – September 2019	$	2.79
Natural Gas Collars:
Floor purchase price (put)		55,000	April 2019 – June 2019	$	2.51
Ceiling sold price (call)		55,000	April 2019 – June 2019	$	2.81
Floor purchase price (put)		75,000	July 2019 – September 2019	$	2.50
Ceiling sold price (call)		75,000	July 2019 – September 2019	$	2.87
Floor purchase price (put)		65,000	October 2019 – December 2019	$	2.65
Ceiling sold price (call)		65,000	October 2019 – December 2019	$	2.96
Floor purchase price (put)		30,000	January 2020 – March 2020	$	2.72
Ceiling sold price (call)		30,000	January 2020 – March 2020	$	3.15
Floor purchase price (put)		15,000	April 2020 – June 2020	$	2.50
Ceiling sold price (call)		15,000	April 2020 – June 2020	$	2.80
Natural Gas Three-way Collars:
Floor purchase price (put)		77,500	April 2019 – December 2019	$	2.72
Ceiling sold price (call)		77,500	April 2019 – December 2019	$	3.04
Floor sold price (put)		77,500	April 2019 – December 2019	$	2.30
Floor purchase price (put)		40,000	April 2019 – June 2019	$	2.65
Ceiling sold price (call)		40,000	April 2019 – June 2019	$	2.84
Floor sold price (put)		40,000	April 2019 – June 2019	$	2.30
Floor purchase price (put)		70,000	January 2020 – June 2020	$	2.70
Ceiling sold price (call)		70,000	January 2020 – June 2020	$	2.98
Floor sold price (put)		70,000	January 2020 – June 2020	$	2.25
Floor purchase price (put)		30,000	October 2019 – June 2020	$	2.90
Ceiling sold price (call)		30,000	October 2019 – June 2020	$	3.15
Floor sold price (put)		30,000	October 2019 – June 2020	$	2.50
Natural Gas Call/Put Options:
Call sold		40,000	April 2019 – December 2019	$	3.44
Basis Swaps:
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)
Appalachia - Dominion		20,000	January 2020 – December 2020	$	(0.59	)
Appalachia - Dominion		17,500	April 2019 – December 2019	$	(0.50	)
Appalachia - Dominion		20,000	April 2019 – March 2020	$	(0.39	)

Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		1,500	July 2019 – December 2019	$	59.18
		1,000	January 2020 – December 2020	$	58.60
Oil Collars:
Floor purchase price (put)		1,500	July 2019 – December 2019	$	51.67
Ceiling sold price (call)		1,500	July 2019 – December 2019	$	65.92
Floor purchase price (put)		500	January 2020 – December 2020	$	50.00
Ceiling sold price (call)		500	January 2020 – December 2020	$	64.00
Oil Three-way Collars:
Floor purchase price (put)		2,000	April 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	April 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	April 2019 – December 2019	$	40.00
Floor purchase price (put)		2,000	January 2020 – June 2020	$	62.50
Ceiling sold price (call)		2,000	January 2020 – June 2020	$	74.00
Floor sold price (put)		2,000	January 2020 – June 2020	$	55.00

NGL Derivatives:

Description

Volume

(Bbls/d)

Production Period

Weighted Average

Price ($/Bbl)

Propane Swaps:

350

April 2019 – December 2019

39.90

Fair Values and Gains (Losses)

The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes.

As of March 31, 2019	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	2,416		$	(2,154	)	$	262		Other current assets
Commodity derivatives - noncurrent		1,510			(176	)		1,334		Other assets
Total assets	$	3,926		$	(2,330	)	$	1,596

Liabilities
Commodity derivatives - current	$	(6,234	)	$	2,154		$	(4,080	)	Accrued liabilities
Commodity derivatives - noncurrent		(972	)		176			(796	)	Other liabilities
Total liabilities	$	(7,206	)	$	2,330		$	(4,876	)

As of December 31, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	4,960		$	(845	)	$	4,115		Other current assets
Commodity derivatives - noncurrent		1,910			—			1,910		Other assets
Total assets	$	6,870		$	(845	)	$	6,025

Liabilities
Commodity derivatives - current	$	(845	)	$	845		$	—		Accrued liabilities
Commodity derivatives - noncurrent		(326	)		—			(326	)	Other liabilities
Total liabilities	$	(1,171	)	$	845		$	(326	)

(a)	The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands):

		Amount of Gain (Loss) Recognized in Income
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss) Recognized in Income	Three Months Ended March 31,
		2019			2018
Commodity derivatives	Gain (loss) on derivative instruments	$	(4,931	)	$	(4,215	)

Note 9—Fair Value Measurements

Fair Value Measurement on a Recurring Basis

The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the condensed consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models, which utilize inputs that are readily available in the public market, such as natural gas and crude oil forward curves. These values are compared to the values given by counterparties for reasonableness. Since the Company’s derivative instruments do not include optionality, and therefore, generally have no unobservable inputs, they are classified as Level 2.

	Level 1		Level 2			Level 3		Total Fair Value
As of March 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	(3,280	)	$	—	$	(3,280	)
Total	$	—	$	(3,280	)	$	—	$	(3,280	)
As of December 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	5,699		$	—	$	5,699
Total	$	—	$	5,699		$	—	$	5,699

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3—Summary of Significant Accounting Policies).

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See Note 10—Debt).

Note 10—Debt

8.875% Senior Unsecured Notes Due 2023

On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior unsecured notes due 2023 at an issue price of 97.903% of the principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding senior PIK notes. The Company used the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes.

During the three months ended March 31, 2019 and 2018, the Company amortized $1.0 million and $0.9 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method.

The indenture governing the senior unsecured notes contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at March 31, 2019.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, 2019 was $486.6 million.

Revolving Credit Facility

During the first quarter of 2014, the Eclipse Resources I, LP, a wholly owned subsidiary of the Company (“Eclipse I”) entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that was scheduled to mature in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October).

The credit agreement governing the revolving credit facility (as amended and restated, the “Credit Agreement”) was amended and restated on January 12, 2015. The primary change effected by such amendment was to add Montage Resources Corporation as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Montage Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit Agreement to, among other things; adjust the quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to permit the sale of certain conventional properties. The amendment to the Credit Agreement also increased the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and required the Company to, within 60 days of the effectiveness of such amendment, execute and deliver additional mortgages on the Company’s oil and gas properties that include at least 90% of its proved reserves.

On February 24, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $125 million to $175 million, while extending the maturity of the revolving credit facility to February 2020. In addition, this amendment modified the minimum interest coverage ratio covenant to a net leverage covenant of Net Debt to EBITDAX. On August 1, 2017, the Company entered into an additional amendment to the Credit Agreement that increased the borrowing base from $175 million to $225 million.

On February 28, 2019, the Company amended and restated the Credit Agreement to increase its revolving credit facility from $500 million to $1 billion. Further, the amended and restated Credit Agreement, among other things, increases the borrowing base from $225 million to $375 million (subject to scheduled and interim redeterminations based on the Company’s oil and natural gas reserves and other adjustments described therein) and extends the maturity date thereof to February 2024 (subject to earlier maturity in certain circumstances specified therein). The amended and restated Credit Agreement also adjusted the ratio of Consolidated Total Funded Net Debt to EBITDAX (as such terms are defined in the Credit Agreement) to provide that the Company will not, as of the last day of any fiscal quarter (commencing with the fiscal quarter ending March 31, 2019), permit its ratio of Consolidated Total Funded Net Debt to EBITDAX for the four previous fiscal quarters to be greater than 4.00 to 1.00.

At March 31, 2019, the borrowing base was $375 million and the Company had $97.5 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling $13.5 million and the outstanding borrowings of $97.5 million, the Company had available borrowing capacity under the revolving credit facility of $264.0 million at March 31, 2019.

Subsequent to March 31, 2019, the Company borrowed an incremental $25 million under its revolving credit facility and issued an additional $15.7 million in outstanding letters of credit. Further, on May 6, 2019, the Company entered into an amendment to the Credit Agreement that increased the borrowing base from $375 million to $400 million. As of May 9, 2019 the available borrowing capacity under the revolving credit facility was $248.3 million.

The revolving credit facility is secured by mortgages on 85% of the value of the Company’s proved reserves and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of March 31, 2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.375%-0.500% of the unused facility based on utilization.

Note 11—Benefit Plans

Defined Contribution Plan

The Company currently maintains a retirement plan intended to provide benefits under section 401(k) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(k) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense related to matching contributions, classified under general and administrative, of $0.2 million and $0.2 million for the three months ended March 31, 2019 and 2018, respectively.

Note 12—Stock-Based Compensation

The Company is authorized to grant up to 1,666,667 shares of common stock under its 2014 Long-Term Incentive Plan (as amended, the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 430,656 shares were available for future grants under the Plan as of March 31, 2019.

Our stock-based compensation expense was as follows for the three months ended March 31, 2019 and 2018 (in thousands):

	Three Months Ended March 31,
	2019		2018
Restricted stock units	$	3,147	$	1,164
Performance units		2,759		728
Restricted stock issued to directors		95		89
Total expense	$	6,001	$	1,981

Restricted Stock Units

Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of March 31, 2019, there was $0.8 million of total unrecognized compensation cost related to outstanding restricted stock units. The weighted average period for the shares to vest is approximately 2 years. A summary of employee restricted stock unit awards activity during the three months ended March 31, 2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		233,960		$	29.27	$	3,685
Granted		70,409			17.55
Vested		(198,279	)		29.28
Forfeited		(485	)		31.78
Total awarded and unvested, March 31, 2019		105,605		$	21.42	$	1,588

Performance Units

Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return, as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of March 31, 2019, there was $2.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately 1 year. A summary of performance stock unit awards activity during the three months ended March 31, 2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2018		346,589		$	27.68	$	716
Granted		—			—
Vested		(265,311	)		27.54
Forfeited		(16,001	)		24.47
Total awarded and unvested, March 31, 2019		65,277		$	29.02	$	1,201

The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s stock price. Prior to 2018, the volatility estimate was tied to the Company’s public peer group. The following table presents the assumptions used to determine the fair value for performance stock units granted during the three months ended March 31, 2018:

	Three Months Ended March 31,
	2018
Volatility		89.70	%
Risk-free interest rate		2.37	%

Restricted Stock

On May 17, 2017, the Company issued an aggregate of 10,212 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which became fully vested on May 17, 2018. For the three months ended March 31, 2018, the Company recognized expense of approximately $0.1 million related to these awards.

On May 16, 2018, the Company issued an aggregate of 15,476 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 16, 2019. For the three months ended March 31, 2019, the Company recognized expense of approximately $0.1 million related to these awards. As of March 31, 2019, there was approximately less than $0.1 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s directors.

Note 13—Earnings (Loss) Per Share

Earnings (Loss) Per Share

Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive.

Reverse Stock Split

Effective immediately prior to the Effective Time on February 28, 2019 (See Note 4— Acquisitions), the Company effected a 15-to-1 reverse stock split of its common stock. Holders of shares of the Company’s common stock immediately prior to the Effective Time received cash for any fractional shares of the Company’s common stock to which they might otherwise have been entitled as a result of the reverse stock split. The reverse stock split lowered the par value to reflect the reduced shares with the offset to additional paid-in-capital. The table below retroactively reflects, in accordance with ASC 505 “Equity”, the reverse stock split that occurred on February 28, 2019 for the three months ended March 31, 2018. The following is a calculation of the basic and diluted weighted-average number of shares of common stock and EPS for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
(in thousands, except per share data)	2019								2018
	Loss			Shares		Per Share			Loss			Shares		Per Share
Basic:
Net loss, shares, basic	$	(14,098	)		25,564	$	(0.55	)	$	(2,626	)		19,563	$	(0.13	)
Weighted-average number of shares of common stock-diluted:
Restricted stock and performance unit awards		—			—					—			—
Diluted:
Net loss, shares, diluted	$	(14,098	)		25,564	$	(0.55	)	$	(2,626	)		19,563	$	(0.13	)

Note 14—Related Party Transactions

During the three months ended March 31, 2019 and 2018, the Company incurred approximately less than $0.1 and $0.2 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which were owned by the Company’s former Chairman, President and Chief Executive Officer. The fees were paid in accordance with a standard service contract that did not obligate the Company to any minimum terms. The Company no longer utilizes any flight charter services under this arrangement.

Travis Peak Resources, LLC, the seller from whom the Company acquired assets in the Flat Castle Acquisition, is an affiliate of EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own approximately 40% of the outstanding shares of the Company’s common stock. (See Note 4—Acquisitions).

Note 15—Commitments and Contingencies

(a) Legal Matters

From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings.

(b) Environmental Matters

The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

As a result of the BRMR Merger, the Company assumed commitments related to certain gas gathering and processing agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR as shown below (in thousands):

	Firm transportation⁽ⁱ⁾		Gas processing, gathering, and compression services⁽ⁱⁱ⁾		Total
Year Ending December 31:
2019	$	14,562	$	12,873	$	27,435
2020		19,416		17,133	$	36,549
2021		19,416		17,087	$	36,503
2022		19,416		17,087	$	36,503
2023		18,047		16,561	$	34,608
Thereafter		92,395		139,545	$	231,940
Total	$	183,252	$	220,286	$	403,538

(i)

Firm transportation -The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest.

(ii)

Gas processing, gathering, and compression services -Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest.

Note 16—Income Tax

For the year ending December 31, 2019, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur book income but a tax loss in fiscal year 2019, and thus, no current federal income taxes are anticipated to be paid. The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to the Company’s year-to-date loss. On December 22, 2017, the Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, resulted in the reduction in the U.S. statutory rate from 35% to 21%. The Company’s interest expense deduction has the potential to be limited as a result of the enactment of the Tax Cuts and Jobs Act; however, the impact is anticipated to be minimal as a result of its full valuation allowance.

In forecasting the 2019 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book income such that no net deferred tax asset is recorded in 2019. Management reached this conclusion considering several factors such as: (i) the lack of carryback potential resulting in a tax refund, and (ii) in light of current

commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in the Company’s balance sheet.

The Company is forecasting positive pre-tax book income for the year ending December 31, 2019. Management expects that income tax expense attributable to current year operations will be offset by a release of the valuation allowance on hand at the beginning of the year. As a result, no net income tax expense or benefit is allocable to either income from continuing operations or to discontinued operations.

As a result of the BRMR Merger, the Company may undergo an ownership change as described in Code section 382. This may limit the future annual availability of the use of the Company’s NOLs that accrued prior to the ownership change date as well as future tax depreciation, depletion and amortization amounts. The Company is still evaluating the impacts that Code section 382 will have on its tax attributes.

Note 17—Subsidiary Guarantors

Each subsidiary of the Company that guarantees the Company’s revolving credit facility is required to fully and unconditionally, joint and severally, guarantee the Company’s 8.875% senior unsecured notes. Each such subsidiary of the Company in existence immediately prior to the BRMR Merger guaranteed the Company’s 8.875% senior unsecured notes. As a result of the BRMR Merger, and within the timeframe required by the indenture governing the Company’s 8.875% senior unsecured notes, the Company caused BRMR and each of its subsidiaries that guaranteed the Company’s revolving credit facility to guarantee the Company’s 8.875% senior unsecured notes (See Note 10—Debt). Montage Resources Corporation, standing alone, has no independent assets or operations. The Company’s wholly owned subsidiaries are not restricted from transferring funds to Montage Resources Corporation or other wholly owned subsidiaries. The Company’s wholly owned subsidiaries do not have any restricted net assets.

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 by way of merger, consolidation, or otherwise; or

•

if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture governing the senior unsecured notes.

Note 18—Subsequent Events

Management has evaluated subsequent events and believes there are no events that would have a material impact on the aforementioned financial statements and related disclosures, other than the redetermination on the credit facility, new letters of credit and the midstream agreements disclosed in the accompanying notes to the condensed consolidated financial statements (See Note 10—Debt and Note 15—Commitments and Contingencies).

Item 2.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018 and our condensed consolidated financial statements and related notes appearing elsewhere in this Quarterly Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Statement Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

We are an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin. On February 28, 2019, we completed a business combination (the “BRMR Merger”) with Blue Ridge Mountain Resources, Inc. (“BRMR”), and immediately thereafter, we changed our legal name from “Eclipse Resources Corporation” to “Montage Resources Corporation”. Except where the context indicates otherwise, the terms “we”, “us”, “our” or the “Company” as used herein refer, for periods prior to the completion of the BRMR Merger, to Eclipse Resources Corporation and its subsidiaries and, for periods following the completion of the BRMR Merger, to Montage Resources Corporation (“Montage”) and its subsidiaries.

As of March 31, 2019, we had assembled an acreage position approximating 243,500 net acres in Eastern Ohio, 45,000 net acres in Pennsylvania, and 45,800 net acres in West Virginia, which excludes any acreage currently pending title.

Approximately 204,800 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately 89,300 net acres of stacked pay opportunity are also prospective for the highly liquids rich area of the Marcellus Shale in Eastern Ohio and West Virginia within what we refer to as our Marcellus Area. We are the operator of approximately 97% of our net acreage within the Utica Core Area and our Marcellus Area. We intend to focus on developing our substantial inventory of horizontal drilling locations during commodity price environments that will allow us to generate attractive returns and will continue to opportunistically add to this acreage position where we can acquire acreage at attractive prices.

As of March 31, 2019, we were operating 2 horizontal rigs in the Utica Core Area. We had average daily production for the three months ended March 31, 2019 of approximately 407.5 MMcfe comprised of approximately 74% natural gas, 16% NGLs and 10% oil.

We have reclassified our interests in the net assets of our subsidiary, Magnum Hunter Production, Inc. (“MHP”), to assets held for sale and liabilities associated with assets held for sale as of March 31, 2019. All operations of MHP have been reclassified to discontinued operations for all periods presented.

How We Evaluate Our Operations

In evaluating our current and future financial results, we focus on production and revenue growth, lease operating expense, general and administrative expense (both before and after non-cash stock compensation expense) and operating margin per unit of production. In addition to these metrics, we use Adjusted EBITDAX, a non-GAAP measure, to evaluate our financial results. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization (“DD&A”); amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles in United States, or “U.S. GAAP.”

In addition to the operating metrics above, as we grow our reserve base, we will assess our capital spending by calculating our operated proved developed reserves and our operated proved developed finding costs and development costs. We believe that operated proved developed finding and development costs are one of the key measurements of the performance of an oil and gas exploration and production company. We will focus on our operated properties as we control the location, spending and operations associated with drilling these properties. In determining our proved developed finding and development costs, only cash costs incurred in connection with exploration and development will be used in the calculation, while the costs of acquisitions will be excluded because our board approves each material acquisition. In evaluating our proved developed reserve additions, any reserve revisions for changes in commodity prices between years will be excluded from the assessment, but any performance related reserve revisions are included.

We also continually evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our acreage in the Utica Core Area and our Marcellus Area. We review changes in drilling and completion costs; lease operating costs; natural gas, NGLs and oil prices; well productivity; and other factors in order to focus our drilling on the highest rate of return areas within our acreage on a per well basis.

As a result of the closing of the BRMR Merger on February 28, 2019, BRMR’s assets and liabilities are included in the Unaudited Condensed Consolidated Balance Sheet as of March 31, 2019 and BRMR’s revenues and expenses are included in the Unaudited Condensed Consolidated Statement of Operations and Comprehensive Income (Loss) for the period from March 1, 2019 to March 31, 2019 (See Note 4— Acquisitions).

Overview of Results for the Three Months Ended March 31, 2019

During the three months ended March 31, 2019, we achieved the following financial and operating results:

•

our average daily net production for the three months ended March 31, 2019 was 407.5 MMcfe per day representing an increase of 29% over the comparable period of the prior year;

•

commenced drilling 10 gross (8.0 net) operated Utica and Marcellus Shale wells, commenced completions of 9 gross (6.3 net) operated Utica Shale wells and turned-to-sales 3 gross (2.1 net) operated Utica Shale wells;

•

recognized net loss of ($14.1) million for the three months ended March 31, 2019 compared to net loss of ($2.6) million for the three months ended March 31, 2018; and

•

realized Adjusted EBITDAX of $68.9 million for the three months ended March 31, 2019 compared to $63.0 million for three months ended March 31, 2018. Adjusted EBITDAX is a non-GAAP financial measure. See “—Non-GAAP Financial Measure” for more information.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists the high, low and average daily and monthly settled NYMEX Henry Hub prices for natural gas and the high, low and average daily NYMEX WTI prices for oil for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
NYMEX Henry Hub High ($/MMBtu)	$	4.25	$	6.24
NYMEX Henry Hub Low ($/MMBtu)		2.54		2.49
Average Daily NYMEX Henry Hub ($/MMBtu)		2.92		3.08
Average Monthly Settled NYMEX Henry Hub ($/MMBtu)		3.15		3.00

NYMEX WTI High ($/Bbl)	$	60.19	$	66.27
NYMEX WTI Low ($/Bbl)		46.31		59.20
Average Daily NYMEX WTI ($/Bbl)		54.82		62.91

Historically, commodity prices have been extremely volatile, and we expect this volatility to continue for the foreseeable future. A decline in commodity prices could materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

The Company is committed to profitably developing its natural gas, NGLs and condensate reserves through an environmentally responsible and cost-effective operational plan. The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves. Despite the continued low price commodity environment, the Company believes the long-term outlook for its business is favorable due to the Company’s resource base, low cost structure, risk management strategies, and disciplined investment of capital.

It is difficult to quantify the impact of changes in future commodity prices on our reported estimated net proved reserves with any degree of certainty because of the various components and assumptions used in the process. However, to demonstrate the sensitivity of our estimates of natural gas, NGLs and oil reserves to changes in commodity prices, we provided an analysis in our Annual Report on Form 10-K for the year ended December 31, 2018. Further, if we recalculated our reserves using the unweighted arithmetic average first-day-of-the-month price for each of the twelve months in the period ended March 31, 2019 and held all other factors constant, then our estimated net proved reserves at December 31, 2018 would have increased by approximately 0.1% from our previously reported estimated net proved reserves at such time, including a 0.2% addition of proved developed reserves and a 0.0% addition of proved undeveloped reserves. The foregoing estimate is based upon an average SEC price of $3.07 per MMBtu for natural gas and $63.06 per Bbl for NGLs and oil. This calculation only isolates the potential impact of commodity prices on our estimated proved reserves and does not account for other factors impacting our estimated proved reserves, such as anticipated drilling and completion costs and our production results since December 31, 2018. There are also numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. As such, this calculation is provided for illustrative purposes only and should not be construed as indicative of our final year-end reserve estimation process.

We consider future commodity prices when determining our development plan, but many other factors are also considered. To the extent there is a significant increase or decrease in commodity prices in the future, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan. We plan to fund our development budget with a portion of the cash on hand at March 31, 2019, cash flows from operations, borrowings under our revolving credit facility, and proceeds from asset sales.

Results of Operations

The following discussion pertains to our results of operations, including analysis of our continuing operations regarding natural gas, NGLs and oil revenues, production, average product prices and average production costs and expenses for the three months ended March 31, 2019 and 2018. The results of operations of MHP are reflected as discontinued operations for all periods presented.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

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

The following table illustrates the revenue attributable to our operations for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change
Revenues (in thousands)
Natural gas sales	$	81,825	$	58,483	$	23,342
NGL sales		21,248		19,743		1,505
Oil sales		28,755		31,958		(3,203	)
Brokered natural gas and marketing revenue		9,530		8		9,522
Other revenue		139		—		139
Total revenues	$	141,497	$	110,192	$	31,305

Our production increased by approximately 8.3 Bcfe for the three months ended March 31, 2019 over the same period in 2018 due to increased drilling activity and from wells acquired as part of the BRMR Merger. 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:
Natural gas (MMcf)		27,205.0		20,343.3		6,861.7
NGLs (Mbbls)		980.5		772.7		207.8
Oil (Mbbls)		598.0		565.4		32.6
Total (MMcfe)		36,676.0		28,371.9		8,304.1

Average daily production volume:
Natural gas (Mcf/d)		302,278		226,037		76,241
NGLs (Bbls/d)		10,894		8,586		2,308
Oil (Bbls/d)		6,644		6,282		362
Total (Mcfe/d)		407,506		315,243		92,263

Our average realized price (including cash settled derivatives and firm transportation) received during the three months ended March 31, 2019 was $3.10 per Mcfe compared to $3.62 per Mcfe during the three months ended March 31, 2018. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices of production volumes should include the total impact of firm transportation expense. Our average realized price (including all cash settled settlements and firm transportation) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled derivatives and firm transportation) does not include derivative settlements or firm transportation, which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price (including firm transportation and excluding cash settled derivatives) does include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended March 31, 2019 and 2018 are shown below:

	Three Months Ended March 31,
	2019		2018		Change
Average realized price (excluding cash settled derivatives and firm transportation)
Natural gas ($/Mcf)	$	3.01	$	2.87	$	0.14
NGLs ($/Bbl)		21.67		25.55		(3.88	)
Oil ($/Bbl)		48.09		56.52		(8.43	)
Total average prices ($/Mcfe)		3.59		3.88		(0.29	)

Average realized price (including cash settled derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	2.85	$	3.05	$	(0.20	)
NGLs ($/Bbl)		21.89		24.33		(2.44	)
Oil ($/Bbl)		49.66		52.30		(2.64	)
Total average prices ($/Mcfe)		3.52		3.89		(0.37	)

Average realized price (including firm transportation, excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.45	$	2.49	$	(0.04	)
NGLs ($/Bbl)		21.67		25.55		(3.88	)
Oil ($/Bbl)		48.09		56.52		(8.43	)
Total average prices ($/Mcfe)		3.18		3.61		(0.43	)

Average realized price (including cash settled derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.30	$	2.67	$	(0.37	)
NGLs ($/Bbl)		21.89		24.33		(2.44	)
Oil ($/Bbl)		49.66		52.30		(2.64	)
Total average prices ($/Mcfe)		3.10		3.62		(0.52	)

Brokered natural gas and marketing revenue was $9.5 million for the three months ended March 31, 2019 compared to less than $0.1 million for the three months ended March 31, 2018. Brokered natural gas and marketing revenue includes revenue received from selling natural gas not related to production and from the release of firm transportation capacity. The increase from the three months ended March 31, 2018 to the three months ended March 31, 2019 was due to an increase in the amount of firm transportation that was available for brokered gas transactions or release to third parties.

Costs and Expenses

We believe some of our expense fluctuations are most accurately analyzed on a unit-of-production, or per Mcfe, basis. The following table presents these expenses for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change
Operating expenses (in thousands):
Lease operating	$	7,525	$	9,390	$	(1,865	)
Transportation, gathering and compression		41,168		27,689		13,479
Production and ad valorem taxes		2,848		2,445		403
Depreciation, depletion, amortization and accretion		29,897		31,311		(1,414	)
General and administrative		28,930		9,757		19,173
Operating expenses per Mcfe:
Lease operating	$	0.21	$	0.33	$	(0.12	)
Transportation, gathering and compression		1.12		0.97		0.15
Production and ad valorem taxes		0.08		0.09		(0.01	)
Depreciation, depletion, amortization and accretion		0.82		1.10		(0.28	)
General and administrative		0.79		0.34		0.45

Lease operating expense was $7.5 million in the three months ended March 31, 2019 compared to $9.4 million in the three months ended March 31, 2018. Lease operating expense per Mcfe was $0.21 in the three months ended March 31, 2019 compared to $0.33 in the three months ended March 31, 2018. The decrease of ($1.9) million and $(0.12) per Mcfe was primarily attributable to a reduction of non-recurring workovers for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018. Lease operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs.

Transportation, gathering and compression expense was $41.2 million during the three months ended March 31, 2019 compared to $27.7 million during the three months ended March 31, 2018. Transportation, gathering and compression expense per Mcfe was $1.12 in the three months ended March 31, 2019 compared to $0.97 in the three months ended March 31, 2018. The following table details our transportation, gathering and compression expenses for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	12,325	$	9,661	$	2,664
Processing and fractionation		11,978		8,501		3,477
Liquids transportation and stabilization		1,744		1,783		(39	)
Marketing		72		7		65
Firm transportation		15,049		7,737		7,312
	$	41,168	$	27,689	$	13,479
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.33	$	0.34	$	(0.01	)
Processing and fractionation		0.33		0.30		0.03
Liquids transportation and stabilization		0.05		0.06		(0.01	)
Marketing		—		—		—
Firm transportation		0.41		0.27		0.14
	$	1.12	$	0.97	$	0.15

The increase of $13.5 million to transportation, gathering and compression expenses during the three months ended March 31, 2019 was primarily due to increased firm transportation capacity and increased production during the three months ended March 31, 2019. The increase of $0.15 per Mcfe was primarily due to increased firm transportation capacity and increased liquids production during the three months ended March 31, 2019.

Production and ad valorem taxes are paid based on market prices and applicable tax rates. Production and ad valorem taxes were $2.8 million in the three months ended March 31, 2019 compared to $2.4 million in the three months ended March 31, 2018. Production and ad valorem taxes per Mcfe was $0.08 and $0.09 for the three months ended March 31, 2019 and 2018, respectively. The increase in aggregate for production and ad valorem taxes was primarily due to increased well count for the three months ended March 31, 2019.

Depreciation, depletion, amortization and accretion was approximately $29.9 million in the three months ended March 31, 2019 compared to $31.3 million in the three months ended March 31, 2018. DD&A per Mcfe was $0.82 for the three months ended March 31, 2019 compared to $1.10 for the three months ended March 31, 2018. DD&A decreased on an aggregate and per Mcfe basis which was predominantly driven by the lower depletion rate resulting from reserves increasing at a higher rate than capital costs for the three months ended March 31, 2019.

General and administrative expense was $28.9 million for the three months ended March 31, 2019 compared to $9.8 million for the three months ended March 31, 2018. General and administrative expense per Mcfe was $0.79 in the three months ended March 31, 2019 compared to $0.34 in the three months ended March 31, 2018. The increase of $19.2 million and $0.45 per Mcfe was primarily related to approximately $14.6 million of expenses related to the BRMR Merger as well as the increase in stock-based compensation incurred in the three months ended March 31, 2019. General and administrative expense included $6.0 million and $2.0 million of stock-based compensation expense for the three months ended March 31, 2019 and 2018, respectively.

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. The following table details our other operating expenses for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	9,459	$	48		$	9,411
Exploration		16,789		15,278			1,511
(Gain) loss on sale of assets		2		(267	)		269

Brokered natural gas and marketing expense was $9.5 million for the three months ended March 31, 2019 compared to less than $0.1 million for the three months ended March 31, 2018. Brokered natural gas and marketing expenses relate to gas purchases that we buy and sell not relating to production and firm transportation capacity that is marketed to third parties. The increase from the three months ended March 31, 2018 to the three months ended March 31, 2019 was due to an increase in the amount of brokered gas transactions.

Exploration expense was $16.8 million for the three months ended March 31, 2019 compared to $15.3 million for the three months ended March 31, 2018. The following table details our exploration-related expenses for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018		Change
Exploration expenses (in thousands):
Geological and geophysical	$	206	$	665	$	(459	)
Delay rentals		6,983		7,823		(840	)
Impairment of unproved properties		9,600		6,696		2,904
Dry hole and other		—		94		(94	)
	$	16,789	$	15,278	$	1,511

Delay rentals were $7.0 million for the three months ended March 31, 2019 compared to $7.8 million for the three months ended March 31, 2018. The decrease in delay rental expenses related to the reduction of converting future lump-sum extension payments into annual delay rentals during the three months ended March 31, 2019.

Impairment of unproved properties was $9.6 million for the three months ended March 31, 2019 compared to $6.7 million for the three months ended March 31, 2018. The increase in impairment charges during the three months ended March 31, 2019 was the result of an increase in expected lease expirations due to our planned future drilling activity and the increase in acreage acquired in the BRMR Merger during 2019. 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.

(Gain) loss on sale of assets was less than $0.1 million for the three months ended March 31, 2019 compared to ($0.3) million for the three months ended March 31, 2018.

Other Income (Expense)

Gain (loss) on derivative instruments was ($4.9) million for the three months ended March 31, 2019 compared to ($4.2) million for the three months ended March 31, 2018, primarily due to changes in commodity prices during each period. Cash (payments) receipts were approximately ($3.2) million and $0.1 million for derivative instruments that settled during the three months ended March 31, 2019 and 2018, respectively.

Interest expense, net was $13.8 million for the three months ended March 31, 2019 compared to $13.0 million for three months ended March 31, 2018. Interest expense increased primarily due to our increased borrowings under our revolving credit facility during the three months ended March 31, 2019.

Income tax benefit (expense) was not recognized for the three months ended March 31, 2019 and 2018 due to the Company recording a higher valuation allowance related to its pre-tax losses and reducing the valuation allowance to the extent of pre-tax income, respectively.

Cash Flows, Capital Resources and Liquidity

Cash Flows

Cash flows from operations are primarily affected by production volumes and commodity prices. Our cash flows from operations also are impacted by changes in working capital. Short-term liquidity needs are satisfied by our operating cash flow, proceeds from asset sales, borrowings under our revolving credit facility, proceeds from our drilling joint venture, and issuances of debt and equity securities. We sell a large portion of our production at the wellhead under floating market contracts.

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Net cash provided by (used in) operations in the three months ended March 31, 2019 was ($8.9) million compared to $3.3 million in the three months ended March 31, 2018. The decrease in cash provided by operating activities reflects working capital changes, increased payments related to the BRMR Merger and timing of cash receipts and disbursements during the year-over-year comparative periods.

Net cash used in investing activities in the three months ended March 31, 2019 was $45.8 million compared to $62.5 million in the three months ended March 31, 2018.

During the three months ended March 31, 2019, we:

•

spent $58.5 million on capital expenditures for oil and natural gas properties;

•

spent $0.2 million on property and equipment; and

•

received $12.9 million from the BRMR Merger.

During the three months ended March 31, 2018, we:

•

spent $66.4 million on capital expenditures for oil and gas properties;

•

spent $0.2 million on property and equipment; and

•

received $4.1 million of proceeds relating to the sale of assets.

Net cash provided by financing activities in the three months ended March 31, 2019 was $56.4 million compared to $63.8 million in the three months ended March 31, 2018.

During the three months ended March 31, 2019, we:

•

borrowed $65 million under our revolving credit facility;

•

paid $3.1 million in debt issuance costs associated with the amended and restated Credit Agreement governing our revolving credit facility; and

•

withheld from employees shares totaling $5.4 million related to the settlement of equity compensation awards.

During the three months ended March 31, 2018, we:

•

borrowed $65 million under our revolving credit facility;

•

paid $0.1 million in equity issuance costs associated with the Flat Castle Acquisition; and

•

withheld from employees shares totaling $0.9 million related to the settlement of equity compensation awards.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, asset sales, borrowings under our revolving credit facility and access to the debt and equity capital markets. We must find new 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 periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. We believe that our existing cash on hand, operating cash flow and available borrowings under our revolving credit facility will be adequate to meet our capital and operating requirements for 2019.

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 will continue using net cash on hand, cash flows from operations and borrowings under our revolving credit facility to satisfy near-term financial obligations and liquidity needs, and as necessary, we will seek additional sources of debt or equity to fund these requirements. Longer-term cash flows are subject to a number of variables including the level of production and prices we receive for our production as well as various economic conditions that have historically affected the natural gas and oil business. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

As of March 31, 2019, we were in compliance with all of our debt covenants under the Credit Agreement governing our revolving credit facility and the indenture governing our 8.875% senior unsecured notes due 2023. Further, based on our current forecast and activity levels, we expect to remain in compliance with all such debt covenants for the next twelve months. However, if oil and natural gas prices decrease to lower levels, we are likely to generate lower operating cash flows, which would make it more difficult for us to remain in compliance with all of our debt covenants, including requirements with respect to working capital and interest coverage ratios. This could negatively impact our ability to maintain sufficient liquidity and access to capital resources.

Credit Arrangements

Long-term debt at March 31, 2019 and December 31, 2018, excluding discount, totaled $607.5 million and $542.5 million, respectively. Information related to our credit arrangements is described in “Note 10—Debt” to our consolidated financial statements and is incorporated herein by reference.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas, NGLs and oil production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas, NGLs and oil production. Pricing for natural gas, NGLs and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in natural gas, NGLs and oil prices, we may enter into financial commodity derivative contracts to ensure that we receive minimum prices for a portion of our future natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas and the WTI price for oil.

Our hedging activities are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, zero cost collars that set a floor and ceiling price for the hedged production, and puts which require us to pay a premium either up front or at settlement and allow us to receive a fixed price at our option if the put price is above the market price. As of March 31, 2019, we had entered into the following derivative contracts:

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		90,000	April 2019 – December 2019	$	2.84
		15,000	April 2019 – September 2019	$	2.79
Natural Gas Collars:
Floor purchase price (put)		55,000	April 2019 – June 2019	$	2.51
Ceiling sold price (call)		55,000	April 2019 – June 2019	$	2.81
Floor purchase price (put)		75,000	July 2019 – September 2019	$	2.50
Ceiling sold price (call)		75,000	July 2019 – September 2019	$	2.87
Floor purchase price (put)		65,000	October 2019 – December 2019	$	2.65
Ceiling sold price (call)		65,000	October 2019 – December 2019	$	2.96
Floor purchase price (put)		30,000	January 2020 – March 2020	$	2.72
Ceiling sold price (call)		30,000	January 2020 – March 2020	$	3.15
Floor purchase price (put)		15,000	April 2020 – June 2020	$	2.50
Ceiling sold price (call)		15,000	April 2020 – June 2020	$	2.80
Natural Gas Three-way Collars:
Floor purchase price (put)		77,500	April 2019 – December 2019	$	2.72
Ceiling sold price (call)		77,500	April 2019 – December 2019	$	3.04
Floor sold price (put)		77,500	April 2019 – December 2019	$	2.30
Floor purchase price (put)		40,000	April 2019 – June 2019	$	2.65
Ceiling sold price (call)		40,000	April 2019 – June 2019	$	2.84
Floor sold price (put)		40,000	April 2019 – June 2019	$	2.30
Floor purchase price (put)		70,000	January 2020 – June 2020	$	2.70
Ceiling sold price (call)		70,000	January 2020 – June 2020	$	2.98
Floor sold price (put)		70,000	January 2020 – June 2020	$	2.25
Floor purchase price (put)		30,000	October 2019 – June 2020	$	2.90
Ceiling sold price (call)		30,000	October 2019 – June 2020	$	3.15
Floor sold price (put)		30,000	October 2019 – June 2020	$	2.50
Natural Gas Call/Put Options:
Call sold		40,000	April 2019 – December 2019	$	3.44
Basis Swaps:
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)
Appalachia - Dominion		20,000	January 2020 – December 2020	$	(0.59	)
Appalachia - Dominion		17,500	April 2019 – December 2019	$	(0.50	)
Appalachia - Dominion		20,000	April 2019 – March 2020	$	(0.39	)

Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		1,500	July 2019 – December 2019	$	59.18
		1,000	January 2020 – December 2020	$	58.60
Oil Collars:
Floor purchase price (put)		1,500	July 2019 – December 2019	$	51.67
Ceiling sold price (call)		1,500	July 2019 – December 2019	$	65.92
Floor purchase price (put)		500	January 2020 – December 2020	$	50.00
Ceiling sold price (call)		500	January 2020 – December 2020	$	64.00
Oil Three-way Collars:
Floor purchase price (put)		2,000	April 2019 – December 2019	$	50.00
Ceiling sold price (call)		2,000	April 2019 – December 2019	$	60.56
Floor sold price (put)		2,000	April 2019 – December 2019	$	40.00
Floor purchase price (put)		2,000	January 2020 – June 2020	$	62.50
Ceiling sold price (call)		2,000	January 2020 – June 2020	$	74.00
Floor sold price (put)		2,000	January 2020 – June 2020	$	55.00

NGL Derivatives:

Description

Volume

(Bbls/d)

Production Period

Weighted Average

Price ($/Bbl)

Propane Swaps:

350

April 2019 – December 2019

39.90

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with Bank of Montreal, J Aron, Morgan Stanley, Capital One N.A., BP Energy Company, KeyBank N.A., NextEra Energy, Inc., Shell Oil Company and EDF Energy. We believe all of such institutions currently are an acceptable credit risk. As of March 31, 2019, we did not have any past due receivables from such counterparties.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative instruments at March 31, 2019. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $16.7 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by $18.2 million. A hypothetical 10 percent decrease in future oil prices would increase future earnings related to derivatives by $7.6 million. Similarly, a hypothetical 10 percent increase in future oil prices would decrease future earnings related to derivatives by $8.5 million.

Subsequent to March 31, 2019, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:

Natural Gas Derivatives:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Collars:
Floor purchase price (put)		30,000	January 2020 – December 2020	$	2.55
Ceiling sold price (call)		30,000	January 2020 – December 2020	$	3.00
Natural Gas Three-way Collars:
Floor purchase price (put)		30,000	January 2020 – December 2020	$	2.70
Ceiling sold price (call)		30,000	January 2020 – December 2020	$	3.05
Floor sold price (put)		30,000	January 2020 – December 2020	$	2.40

Oil Derivatives:

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Collars:
Floor purchase price (put)		500	January 2020 – December 2020	$	53.00
Ceiling sold price (call)		500	January 2020 – December 2020	$	64.50
Floor purchase price (put)		500	July 2019 – March 2020	$	60.00
Ceiling sold price (call)		500	July 2019 – March 2020	$	67.00

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt. Our Board of Directors approved an initial capital budget for 2019 of between approximately $375 - $400 million, allocated approximately 90% for drilling and completions activities and approximately 10% for land activities and other capital requirements. The 2019 capital budget is expected to be substantially funded through internally generated cash flows, the Company’s current cash balance, and borrowings under the revolving credit facility. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas, NGLs and oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas, NGLs or oil prices from current levels may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production and our proved reserves as well as our ability to maintain compliance with our debt covenants. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities, additional borrowings under our revolving credit facility or the sale of assets.

On February 28, 2019, the Company completed its previously announced business combination transaction with BRMR pursuant to that certain Agreement and Plan of Merger, dated as of August 25, 2018 and amended as of January 7, 2019 (the “Merger Agreement”), by and among the Company, Everest Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of the Company (“Merger Sub”), and BRMR. Pursuant to the Merger Agreement, Merger Sub merged with and into BRMR with BRMR continuing as the surviving corporation and a wholly owned subsidiary of the Company.

In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in the Credit Agreement governing our revolving credit facility and other factors.

Capitalization

As of March 31, 2019 and December 31, 2018, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

	March 31, 2019		December 31, 2018
Senior unsecured notes	$	510.0	$	510.0
Revolving credit facility		97.5		32.5
Stockholders' equity		949.7		687.5
Total capitalization	$	1,557.2	$	1,230.0

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, firm transportation, gas processing, gathering, and compressions services and asset retirement obligations. As of March 31, 2019 and December 31, 2018, we did not have any capital leases, any significant off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed any debt of any unrelated party. Our condensed consolidated balance sheet at March 31, 2019 reflects accrued interest payable of $10.9 million, compared to $21.7 million as of December 31, 2018.

Midstream Agreements

As a result of the BRMR Merger, we assumed commitments related to certain gas gathering and processing agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of BRMR (See Note 15—Commitments and Contingencies). See our Annual Report on Form 10-K for further discussion of our Midstream Agreements and Other Commitments.

MarkWest Gas Processing Agreement

Triad Hunter is party to a gas processing agreement with MarkWest Liberty Midstream & Resources, L.L.C. The agreement provides for minimum volume commitments of 37,500 mcf per day and expires in October 2023.

Equitrans Gas Transportation Agreement

Triad Hunter is party to a gas transportation agreement with Equitrans, L.P. Under the gas transportation agreement, which expires on October 31, 2029, Triad Hunter’s maximum daily quantities are 50,000 MMBtu per day through December 31, 2024 and are reduced to 35,000 MMBtu per day effective as of January 1, 2025.

Eureka Midstream Gas Gathering Agreement

Triad Hunter is party to a Gas Gathering Contract with Eureka Midstream. Among other things, the Gas Gathering Contract provides for minimum volume commitments to be determined on a system-wide basis with volume banking, with annual commitments of 210,000 MMBtu per day for 2019 through 2033. In addition, the agreement includes a minimum volume commitment of 50,000 Mcf per day for a compression facility.

In March 2019, the Company became party to a Rich Gas Gathering Agreement (Firm Service – Three Well Pads) with Eureka Midstream, under with the Company committed to the payment of monthly reservation fees for certain maximum daily quantities of gas delivered under this agreement. Among other things, the Rich Gas Gathering Agreement provides for minimum volume commitments with annual commitments in the table below:

Term	Natural Gas (Mcf/d)
July 2019 – June 2020		41,000
July 2020 – June 2021		40,000
July 2021 – June 2022		23,000
July 2022 – June 2023		16,500
July 2023 – June 2024		12,500
July 2024 – June 2025		10,400
July 2025 – June 2026		8,500
July 2026 – June 2027		7,250
July 2027 – June 2028		6,000
July 2028 – June 2029		5,250
July 2029 – June 2030		4,250
July 2030 – June 2031		3,500
July 2031 – June 2032		3,000
July 2032 – June 2033		2,500
July 2033 – June 2034		2,000

REX Transportation Agreement

Triad Hunter is party to certain transportation services agreements with Rockies Express Pipeline LLC (“REX”) for the delivery by Triad Hunter and the transportation by REX of natural gas produced by Triad Hunter. Under the agreements, Triad Hunter committed to purchase 50,000 MMBtu per day of firm transportation through 2031. In January 2018, Triad Hunter committed to purchase an additional 50,000 MMBtu per day of firm transportation capacity commencing October 1, 2018 and continuing through September 30, 2023. In April 2019, REX and Triad Hunter agreed to extend the term of the additional 50,000 MMBtu per day through September 30, 2027.

In connection with its transportation services agreements with REX, Triad Hunter was required to provide credit support, which as of March 31, 2019 consisted of a letter of credit of $20 million and a cash prepayment to REX of $1.4 million. Triad Hunter was also party to an Asset Management Agreement with BP Energy Company pursuant to which, among other things, BP Energy Company agreed to provide the $20 million letter of credit to REX on behalf of Triad Hunter. In April 2019, per the terms of the additional 50,000 MMBtu per day extension, REX and Triad Hunter came to an agreement to reduce the currently held letter of credit to $14.4 million from the previously held $20 million. The $20 million letter of credit posted by BP Energy Company expired on April 28, 2019, and the Company issued the reduced $14.4 million letter of credit under its revolving credit facility (See Note 10—Debt).

Other

We lease acreage that is generally subject to lease expiration if operations are not commenced within a specified period, generally five years. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Interest Rates

At March 31, 2019 and December 31, 2018, we had $510.0 million of senior unsecured notes outstanding, excluding discounts, which bore interest at a fixed cash rate of 8.875% and was due semi-annually from the date of issuance.

At March 31, 2019, we had outstanding borrowings of $97.5 million under our revolving credit facility with interest payable at a variable rate based on LIBOR or the prime rate based on our election at the time of borrowing. We had outstanding borrowings of $32.5 million under our revolving credit facility as of December 31, 2018.

Information related to our interest rates is described in “Note 10—Debt” to our consolidated financial statements and is incorporated herein by reference.

Off-Balance Sheet Arrangements

We do not currently utilize any 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 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, it does not normally have a significant effect on our business. We expect our costs in fiscal 2019 to continue to be a function of supply and demand. Further strengthening of commodity prices could stimulate demand for ancillary services causing service costs to increase. In the near term, the majority of our service costs are expected to remain flat in 2019 due to previously negotiated drilling, stimulation, and rentals contracts. Along with these contracts, we have secured quality service equipment and tenured personnel to limit our exposure to increasing service costs and improve operational efficiencies.

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; DD&A; amortization of deferred financing costs; gain (loss) on derivative instruments, net cash receipts (payments) on settled derivative instruments, and premiums (paid) received on options that settled during the period; non-cash compensation expense; gain or loss from sale of interest in gas properties; exploration expenses; and other unusual or infrequent items set forth in the table below. Adjusted EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

•

is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

•

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

•

is used by our management team for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under the Credit Agreement governing the revolving credit facility and the indenture governing the senior unsecured notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies. The following table represents a reconciliation of our net income (loss) from operations to Adjusted EBITDAX for the periods presented:

	Three Months Ended March 31,
$ thousands		2019		2018
Net loss	$	(14,098	)	$	(2,626	)
Depreciation, depletion, amortization and accretion		29,897			31,311
Exploration expense		16,789			15,278
Stock-based compensation		6,001			1,981
(Gain) loss on sale of assets		2			(267	)
Loss on derivative instruments		4,931			4,215
Net cash receipts (payments) on settled derivatives		(3,186	)		141
Interest expense, net		13,840			12,952
Merger-related expenses		14,583			—
Loss from discontinued operations		182			—
Adjusted EBITDAX	$	68,941		$	62,985

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See our Annual Report on Form 10-K for further discussion of our critical accounting policies.

Recent Accounting Pronouncements

The Company’s critical accounting policies are described in “Note 3—Summary of Significant Accounting Policies” of the consolidated financial statements for the year ended December 31, 2018 contained in the Company’s Annual Report on Form 10-K. Information related to recent accounting pronouncements is described in “Note 3—Summary of Significant Accounting Policies” to our condensed consolidated financial statements in this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 82% of our December 31, 2018 proved reserves were natural gas.

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “Note 8—Derivative Instruments.”

Interest Rate Risk

Information related to our interest rates is described in “Note 10—Debt” to our consolidated financial statements and is incorporated herein by reference.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts, the sale of our oil and gas production which we market to energy companies, end users and refineries, and joint interest receivables.

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of March 31, 2019, we had economic hedges in place with nine counterparties. The fair value of our commodity derivative contracts of approximately ($3.3) million at March 31, 2019 includes the following values by bank counterparty: Bank of Montreal $0.6 million; KeyBank N.A. ($1.5) million; Morgan Stanley ($1.2) million; Capital One N.A. ($0.1) million; BP Energy Company ($0.1) million; J Aron ($0.2) million; NextEra Energy, Inc. ($0.4) million; Shell Oil Company $0.1 million; and EDF Energy ($0.5) million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at March 31, 2019 for each of the banks. We believe that all of these institutions currently are acceptable credit risks. Other than as provided by our revolving credit facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of March 31, 2019, we did not have past-due receivables from, or payables to, any of the counterparties to our derivative contracts to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas. We, generally, do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s management carried out an evaluation (as required by Rule 13a-15(b) of the Exchange Act), with the participation of the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon this evaluation, the Company’s President and Chief Executive Officer and Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q, such that the information relating to the Company and its consolidated subsidiaries required to be disclosed by the Company in the reports that it files or submits under the Exchange Act (i) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms, and (ii) is accumulated and communicated to the Company’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the period covered by this Quarterly Report that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

Information regarding the Company’s legal proceedings is set forth in “Note 15—Commitments and Contingencies,” located in the Notes to the Condensed Consolidated Financial Statements included in Part I Item 1 of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 1A.

Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Item 1A. Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 15, 2019, which could materially affect our business, financial condition, and/or future results. There have been no material changes to the risks described in our Annual Report on Form 10-K. The risks described in our Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition, or results of operations.

Item 6.

Exhibits

See the list of exhibits below in the index to exhibits to this Quarterly Report on Form 10-Q, which is incorporated herein by reference.

MONTAGE RESOURCES CORPORATION

INDEX TO EXHIBITS

Exhibit No.		Description

2.1+		Agreement and Plan of Merger, dated as of August 25, 2018, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the SEC on August 27, 2018).

2.2		Amendment No. 1 to Agreement and Plan of Merger, dated as of January 7, 2019, among Eclipse Resources Corporation, Everest Merger Sub Inc., and Blue Ridge Mountain Resources, Inc. (incorporated by reference to Exhibit 2.2 to the Company’s Current Report on Form 8-K filed with the SEC on January 7, 2019).

3.1		Second Amended and Restated Certificate of Incorporation of Montage Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

3.2		Second Amended and Restated Bylaws of Montage Resources Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

3.3		Certificate of Ownership and Merger, filed with the Secretary of State of the State of Delaware with an effective date of February 28, 2019 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

4.1		Amended and Restated Registration Rights Agreement, dated January 28, 2015, by and among Eclipse Resources Corporation, Eclipse Resources Holdings, L.P., CKH Partners II, L.P., The Hulburt Family II Limited Partnership, Kirkwood Capital, L.P, EnCap Energy Capital Fund VIII, L.P., EnCap Energy Capital Fund VIII Co-Investors, L.P., EnCap Energy Capital Fund IX, L.P., Eclipse Management, L.P., Buckeye Investors L.P., GSO Capital Opportunities Fund II (Luxembourg) S.à.r.l., Fir Tree Value Master Fund, L.P., Luxor Capital Partners, LP and Luxor Capital Partners Offshore Master Fund, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2015).

4.2		Indenture, dated as of July 6, 2015, between Eclipse Resources Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 8, 2015).

4.3		Registration Rights Agreement, dated as of January 18, 2018, by and among Eclipse Resources Corporation, Eclipse Resources-PA, LP, and Travis Peak Resources, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on January 22, 2018).

10.1		Third Amended and Restated Credit Agreement, dated as of February 28, 2019, among Montage Resources Corporation, Bank of Montreal, as administrative agent, the lenders party thereto, and BMO Capital Markets Corp., Capital One, National Association, and KeyBank National Association, as joint lead arrangers and joint bookrunners (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on March 6, 2019).

10.2†		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 2, 2014).

10.3†*		Retention Agreement, dated as of February 28, 2019, by and between Montage Resources Corporation and Oleg Tolmachev.

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certifications of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certifications of Chief Financial Officer 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 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 Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

+	Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Montage Resources Corporation agrees to furnish a copy of such schedules, or any section thereof, to the SEC upon request.

†	Management contract or compensatory plan or arrangement.

*	Filed herewith.

**	These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

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.

May 9, 2019		MONTAGE RESOURCES CORPORATION (Registrant)

		/s/ John K. Reinhart
		John K. Reinhart,
		President and Chief Executive Officer

		/s/ Michael L. Hodges
		Michael L. Hodges,
		Executive Vice President and Chief Financial Officer

Exhibit 10.3

February 28, 2019

Oleg Tolmachev

113 Forbes Field Circle Boalsburg, PA 16827

HAND DELIVERED

Re: Retention Bonus

Dear Oleg:

As you know, earlier today, Montage Resources Corporation (formerly known as Eclipse Resources Corporation) (“Montage” or the “Company”) and Blue Ridge Mountain Resources, Inc. (“BRMR”) completed the merger of a wholly owned subsidiary of Montage with and into BRMR, with BRMR surviving as a wholly owned subsidiary of Montage (the “Merger”). The Company considers your continued service and dedication to be an important part of its continuing operations. In order to induce you to remain employed for a certain period of time following the Merger, we are pleased to offer you a retention bonus arrangement pursuant to the terms and conditions outlined in this letter agreement (this “Retention Agreement”).

This Retention Agreement shall become effective on the date set forth above (the “Effective Date”), and shall continue in effect for two (2) years immediately following the Effective Date (the “Retention Period”). The expiration of the Retention Period shall not relieve either you or the Company of any obligations which accrued prior to such expiration, including, without limitation, any repayment obligations pursuant to the terms below. In addition to this Retention Agreement, it is anticipated that, following the Merger, you and Montage will enter into a new employment agreement which shall replace and supersede your existing Amended and Restated Executive Employment Agreement dated January 1, 2017 with the Company (the existing agreement referred to herein as the “Employment Agreement”).

Subject to the conditions set forth herein, the Company shall provide you a bonus totaling $1,339,770.38 (the “Retention Bonus”), payable as follows: (1) thirty percent (30%) of the Retention Bonus shall be paid to you as a lump sum cash payment, subject to applicable taxes and withholdings (the “Cash Portion”) and (2) seventy percent (70%) of the Retention Bonus shall be provided to you in the form of an award of restricted common stock of Montage under the Company’s 2014 Long-Term Incentive Plan (as amended, the “LTIP”), valued at the closing price of Montage’s common stock on the New York Stock Exchange on the Effective Date, adjusted proportionately to reflect the 15-to-1 reverse stock split of the Company’s common stock that was effected in connection with the completion of the Merger (the “Equity Portion”).

In order to be eligible for the Retention Bonus, in association with the Company’s relocation of its headquarters to Irving, Texas, you agree to relocate your principal place of employment to Irving (including moving your personal residence consistent with the terms of the Montage Resources Merger Relocation Policy, attached as “Exhibit A” to this Retention Agreement (the “Relocation Policy”)) on a timeline acceptable to the Company. You will be entitled to the relocation benefits set forth in, and agree to abide by the terms of, the Relocation Policy. The Relocation Policy is subject to review and modification by the Board of Directors of Montage. You agree that, in exchange for the promises set forth in this Retention Agreement, you waive any right, pursuant to your Employment Agreement, to resign your employment with the Company for Good Reason (as defined in the Employment Agreement) and receive any benefits set forth in Section 5(c) of the Employment Agreement due to the relocation of your principal office as required by this Retention Agreement. Furthermore, in order to receive the Retention Bonus you must timely sign (and not revoke) the general release agreement attached as “Exhibit B” to this Retention Agreement (the “Release”). Provided that you timely return an executed Release, the Company shall provide you the Cash Portion of the Retention Bonus within thirty (30) days after the Release becomes effective, as set forth in the Release.

With respect to the Equity Portion, twenty-five percent (25%) of the shares of restricted common stock constituting the Equity Portion will vest, and become free of applicable restrictions on transfer and other restrictions set forth in the award agreement referenced below, on each of the dates that are six months, twelve months, eighteen months and twenty-four months after the Effective Date (each, a “Vesting Date”), provided that you continue to be employed by Montage on the applicable Vesting Date. Provided that you timely return an executed Release, the Company shall deliver to you a restricted stock award agreement within sixty (60) days after the Release becomes effective, as set forth in the Release. The restricted stock award agreement will memorialize the vesting and restrictions and contain such other terms as provided therein in accordance with the LTIP.

As you vest, the fair market value of Montage common stock which becomes unrestricted will be taxable ordinary income and subject to tax withholding; provided, however, that if you timely make and file an election under Section 83(b) of the Internal Revenue Code of 1986, as amended (the “Code”), within thirty (30) days of the grant date of the Equity Portion, then one hundred percent (100%) of the grant date fair market value of the Montage common stock will be taxable ordinary income and subject to tax withholding. In either case, any subsequent gain or loss recognized by you upon disposition of the Montage common stock will be capital gain or loss. You are strongly advised to consult with your professional tax advisor regarding the tax consequences of the Equity Portion and the advisability of making an election under Section 83(b).

In the event that either (1) you resign from employment with the Company, for any reason, prior to the last day of the Retention Period or (2) the Company terminates your employment with the Company with Cause (as defined in the Employment Agreement, or any superseding employment agreement) prior to the last day of the Retention Period, you agree to repay to the Company the Cash Portion in a pro-rata amount reflecting the number of days you were employed by the Company during the Retention Period (i.e., [unemployed days remaining in Retention Period/730] x Cash Portion = repayment amount owed). You agree to repay any such amount owed within thirty (30) days after your last day of employment with the Company.

This Retention Agreement is intended to comply with, or be exempt from, Section 409A of the Code (“Section 409A”) and shall be construed and administered in accordance with Section 409A. This Retention Agreement does not create a contract of employment between you and the Company for any specific term.

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This Retention Agreement contains all of the understandings and representations relating to the Retention Bonus and supersedes all prior and contemporaneous understandings, discussions, agreements, representations and warranties, both written and oral, with respect to any retention bonus. This Retention Agreement may not be amended or modified unless in writing signed by both you and an authorized representative of the Company. This Retention Agreement shall be construed in accordance with the laws of Texas without regard to conflicts-of-law principles. Venue shall lie in the courts of competent jurisdiction in Texas.

The invalidity or unenforceability of any provision of this Retention Agreement shall not affect the validity or enforceability of any other provision of this Retention Agreement, which shall remain in full force and effect. This Retention Agreement may be executed in multiple counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

We look forward to your continued employment with the Company following the Merger.

[Signature Page Follows]

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Very truly yours,

MONTAGE RESOURCES CORPORATION


By:		/s/ John K. Reinhart
Name:		John K. Reinhart
Title:		President and Chief Executive Officer

Agreed to and accepted as of the date first written above:



Oleg Tolmachev

Exhibit A

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MERGER RELOCATION POLICY

Purpose and Eligibility

To establish a policy for providing relocation assistance to Eclipse Resources Employees (as defined below) who, at the request of Montage Resources Corporation (the “Company”), are permanently transferred from one Company work location to another in connection with the Merger (as defined below).

The term “Eclipse Resources Employees” means employees of Eclipse Resources Corporation or its subsidiaries who were such employees immediately prior to the consummation of the Merger.

The term “Merger” means the merger between Blue Ridge Mountain Resources, Inc. and a subsidiary of Eclipse Resources Corporation contemplated by the Agreement and Plan of Merger dated August 25, 2018 among Eclipse Resources Corporation, such subsidiary and Blue Ridge Mountain Resources, Inc.

The term “Eligible Employees” means Eclipse Resources Employees who (i) are requested by the Company in an offer letter to such employee to permanently transfer his or her place of employment from one Company work location to another in connection with the Merger and (ii) sign such offer letter accepting such transfer.

This policy does not apply to new Company hires. Relocation benefits are provided to new Company hires only to the extent set forth in the terms and conditions outlined in their Company employment offer letter.

Relocation Coordination

To help ensure a seamless relocation process for Eligible Employees and their immediate family members (spouse/partner and dependent household members), the Company has secured Signature Relocation to coordinate all aspects of such employees’ transfer to the new work location. Signature Relocation will guide such employees through the moving process, assisting with real estate agents, moving companies, mortgage brokers, temporary housing and payment/reimbursement for the approved benefits outlined in this policy. For additional information regarding Signature Relocation, as well as the Dallas/Fort Worth area, Eligible Employees can access Signature Relocation’s customized website at http://www.signaturerelo.com/montage-resources/.

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Approved Relocation Expenses and Limitations

Relocation assistance shall be provided to Eligible Employees in accordance with the following:

Moving of Household Goods (*taxable): Normal family household goods and furnishings moved to the Eligible Employee’s new living location via Company partner moving company, with full replacement insurance coverage, and storage‐in‐transit for up to 30 days. Maximum payment by the Company of $20,000, with any exceptions requiring the written approval of an Executive Vice President of the Company.

Auto Shipment (*taxable): When relocation distance exceeds 500 miles, one (1) family automobile may be shipped to the Eligible Employee’s new living location via Company partner moving company. Maximum payment by the Company of $1,200.

Home Sale Assistance (*taxable): Reimbursement of standard realtor commissions associated with the sale of the Eligible Employee’s current residence up to 6%. Maximum reimbursement by the Company of $25,000, with any exceptions requiring the written approval of an Executive Vice President of the Company.

Temporary Living Expenses (*taxable): The Company will reimburse the reasonable costs to temporarily house the Eligible Employee and his or her immediate family (lodging and associated utilities only) for a period of up to ninety (90) days. Meals are excluded from temporary living expense reimbursement eligibility. Maximum reimbursement by the Company of $10,000, with any exceptions requiring the written approval of an Executive Vice President of the Company.

Area Visit/House Hunting Trips (*taxable): The Eligible Employee will have the opportunity to make new work location and local area visits, as well as house hunting trips. The Company will reimburse the reasonable costs of transportation, lodging and meals for the Eligible Employee and his or her immediate family for such visits and trips, up to a cumulative maximum of $2,500.

Lease Buyout Reimbursement (*taxable): The Company will provide reimbursement for any fees or penalties incurred by the Eligible Employee under his or her primary housing lease agreement as a result of the early termination or breakage of the lease agreement. Maximum reimbursement by the Company of $8,000, with any exceptions requiring the written approval of an Executive Vice President of the Company.

Final Move Trip (*taxable): Reimbursement of actual and reasonable en‐route travel expenses incurred by the Eligible Employee and his or her immediate family for their final move trip to the new work location. Allowable expenses include transportation/airfare, mileage, overnight lodging and meals. Maximum reimbursement by the Company of

$2,500.

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Miscellaneous Allowance (*taxable): Payment will be made to the Eligible Employee for miscellaneous expenses incurred by the Eligible Employee in connection with his or her relocation upon receipt by the Company of confirmation of the Eligible Employee’s final contract for his or her new permanent living location. Allowance amount of $4,000.

Expense Reimbursement/Documentation: Reimbursable expenses will only be reimbursed to the extent evidenced by valid written records/receipts submitted in accordance with this policy. The Eligible Employee is responsible for (i) maintaining records/receipts for all temporary living, area visit, house hunting trip and other expenses incurred and (ii) submitting expenses for reimbursement and/or requests for payment through the Company’s approved relocation partner, Signature Relocation. For Signature Relocation’s reimbursement/payment procedures, please visit http://www.signaturerelo.com/montage-resources/. All personal expenses and/or requests for payment must be submitted via Signature Relocation for tracking, taxation and reimbursement/payment purposes. Eligible Employees shall not submit any relocation expenses via the Company expense report process. An Eligible Employee shall be responsible for all expenses incurred by him or her in excess of the maximum amounts specified above or not otherwise approved as provided above, and the Company may, to the extent permitted by law, deduct any such excess or unapproved amounts incurred by the Company from the Eligible Employee’s compensation. Expenses incurred after termination of employment will not be reimbursed or paid under this policy.

10.

Company Credit Cards: Eligible Employees shall not use Company credit cards for personal relocation expenses.

Taxes

The Company will gross up an Eligible Employee’s wages in an amount reasonably determined by the Company to provide tax assistance for all taxable relocation expenses and payments reimbursed or made, as outlined in this policy. Any gross‐up payments to the Eligible Employee to cover applicable taxes will be processed and made by Signature Relocation. When tax assistance is provided, these additional wages will be included on the Eligible Employee’s W‐2 for the applicable calendar year. Such tax assistance will be determined and calculated by the Company in its reasonable discretion and made at such time or times, and in as uniform a manner, as the Company reasonably determines. Unless otherwise determined by the Company, tax gross‐up payments will only be made to Eligible Employees who continue to be employed by the Company (or applicable subsidiary) at the time of the gross‐up payment.

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Completion of Relocation

Eligible Employees must complete their relocation to their new living location within six (6) months of their designated work transfer date. All relocation expenses and/or requests for payment must be submitted within this time frame for reimbursement/payment. Any expenses submitted for reimbursement or requests for payment made after this six (6) month period will be subject to approval by the Company’s Chief Financial Officer in his sole discretion.

Repayment

If an Eligible Employee voluntarily leaves the employment of the Company (or applicable subsidiary), or is terminated by the Company (or applicable subsidiary) for cause, prior to, on or within 12 months after his or her designated work transfer date, the former Eligible Employee shall repay to the Company upon demand 100% of the total amounts paid or reimbursed by the Company to or on behalf of the Eligible Employee under this policy. If an Eligible Employee voluntarily leaves the employment of the Company (or applicable subsidiary), or is terminated by the Company (or applicable subsidiary) for cause, between 12 and 24 months after his or her designated work transfer date, the former Eligible Employee shall repay to the Company upon demand 50% of the total amounts paid or reimbursed by the Company to or on behalf of the Eligible Employee under this policy. The Company may, to the extent permitted by law, deduct all or any portion of such amounts owed to the Company from any compensation owed to the former Eligible Employee, but any such deduction shall not relieve the former Eligible Employee from his or her responsibility for any unpaid amounts owed to the Company.

In no event shall an Eligible Employee be entitled to any reimbursement or payment under this policy following his or her voluntary termination of employment or termination of employment for cause.

Policy Interpretation and Modifications

The Company has the sole right to modify, amend or discontinue this policy at any time. Any and all interpretations of this policy shall be made by the Company’s President and Chief Executive Officer in his reasonable discretion, and such interpretations shall be binding on all Eligible Employees. This policy does not constitute and shall not be construed as an employment contract and does not constitute a guarantee of employment for any specified or minimum period of time.

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Exhibit B

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RELEASE AGREEMENT

This confidential Release Agreement (this “Agreement”) is entered into between Montage Resources Corporation (the “Company”) and Oleg Tolmachev (“Executive”). The Company and Executive are referred to in this Agreement as the “Parties”. In consideration of the promises and mutual covenants set forth in this Agreement, and for other good and valuable consideration, the sufficiency of which is hereby acknowledged, Executive and the Company agree as follows:

1.Retention Agreement. The Company and Executive entered into a Retention Bonus letter agreement effective , 2019 (the “Retention Agreement”). In consideration for the release and waiver of any and all claims described in this Agreement the Company shall provide Executive the Retention Bonus (as defined in the Retention Agreement), pursuant to the terms of the Retention Agreement. Executive acknowledges the Company is under no obligation to provide the Retention Bonus absent Executive’s agreement to, and compliance with, the terms of this Agreement.

2.Release and Waiver by Executive. For and in consideration of the Retention Bonus, Executive KNOWINGLY AND VOLUNTARILY RELEASES, ACQUITS AND FOREVER DISCHARGES the Company and each of its past, present, and future subsidiaries, related and/or affiliated entities, including, without limitation Blue Ridge Mountain Resources, Inc. and Montage Resources Corporation, their present and former officers, directors, executives, stockholders, agents, attorneys, employees and employee benefit plans (and the fiduciaries thereof), and the successors, predecessors and assigns of each of the foregoing (collectively, the “Released Parties”) from any and all claims and/or causes of action of whatever kind or character, that have accrued or may accrue, whether known or unknown, and that are based on facts occurring at or prior to the time Executive signs this Agreement, including, but not limited to: (a) any and all claims pursuant to the labor and employment codes and statutes of the state of Texas; Title VII of the Civil Rights Act of 1964, as amended, 42 U.S.C. § 2000e et seq.; the Civil Rights Act of 1991, as amended, 42 U.S.C. § 1981a; the Equal Pay Act of 1963; the Americans with Disabilities Act, as amended, 42 U.S.C. § 12101 et seq.; the Employee Retirement Income Security Act of 1974; the Age Discrimination in Employment Act of 1967, as amended by the Older Workers Benefit Protection Act; the Fair Labor Standards Act; the Worker Adjustment Retraining and Notification Act; the Family Medical and Leave Act, as amended, 29 U.S.C. § 2601, et seq.; the Fair Credit Reporting Act, COBRA, and all other applicable federal, state or local laws, ordinances or regulations; (b) all tort, contract, and/or common law claims, including, but not limited to, defamation, intentional or negligent infliction of emotional distress, fraud, misrepresentation, wrongful termination, wrongful discharge in violation of public policy, and breach of the duty of good faith and fair dealing; and (c) all claims arising out of or relating in any way to Executive’s employment with the Company or any Released Party. Notwithstanding the foregoing, this Agreement will not apply to and expressly excludes: (a) vested benefits under any plan maintained by the Company or any Released Party that provides for deferred compensation, equity compensation or pension or retirement benefits; (b) any claim that cannot by law be waived or released by private agreement; (c) claims based on facts occurring after the date of this Agreement; (d) payments and benefits to be made under the Retention Agreement and the Employment Agreement (as defined in the Retention Agreement); (e) claims under any directors and officers insurance policies; and (f) rights to indemnification Executive may have under the by-laws or certificate of incorporation of the Company or any Released Party, any applicable indemnification agreements with the Company and or any Released Party or applicable law.

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3.Communication with Government Agencies. Nothing in this Agreement prevents Executive from exercising any rights that cannot be lawfully waived or restricted. Nothing in this Agreement limits Executive’s ability to file a charge or complaint with or communicate with any federal, state or local governmental agency or commission (“Government Agencies”). Further, this Agreement does not limit Executive’s ability to participate in any investigation or proceeding that may be conducted by any Government Agency, including providing documents or other information, without notice to the Company. This Agreement does not limit Executive’s right to receive an award from a Government Agency for information provided to any Government Agencies. Executive agrees that Executive has waived any right—where such right can be waived—to recover monetary damages or other personal relief from the Released Parties in any action filed by Executive or by anyone else on Executive’s behalf.

4.Non-Admission. Neither the payment of any sum of money nor the execution or delivery of this Agreement shall constitute or be construed as an admission, express or implied, by the Released Parties of liability or that the Released Parties acted wrongfully with respect to Executive. The Released Parties specifically deny and disclaim any such liability or wrongful acts. Nothing contained in this Agreement shall acknowledge or imply that the Released Parties have violated any federal, state, or local laws or regulations.

5.Twenty-One (21) Days to Consider Agreement. The Company hereby advises Executive to consult with an attorney of Executive’s choice regarding this Agreement. The Company also advises Executive that he has twenty-one (21) calendar days from the date Executive receives this Agreement within which to consider whether to accept the Retention Bonus and sign this Agreement. Executive may voluntarily choose to sign this Agreement earlier, but is not required to do so. Executive does not become entitled to receive the Retention Bonus unless Executive timely signs and returns this Agreement to Paul Johnston, Executive Vice President and General Counsel, Montage Resources Corporation, 122 W. John Carpenter Freeway, Suite 300, Irving, Texas 75039, pjohnston@brmresources.com. Executive acknowledges, represents and agrees that: (i) Executive has carefully read and fully understands all of the provisions of this Agreement; and (ii) Executive accepts the terms of this Agreement as fair and equitable under all the circumstances and acknowledges that Executive has entered into this Agreement knowingly, voluntarily, and without threat or duress.

6.Revocation Period and Effective Date. Executive has the right to revoke this Agreement within seven (7) days after Executive signs it. In order to revoke this Agreement, Executive’s notice of revocation must be in writing and delivered to Paul Johnston, Executive Vice President and General Counsel, Montage Resources Corporation, 122 W. John Carpenter Freeway, Suite 300, Irving, Texas 75039, pjohnston@brmresources.com, no later than the seventh (7th) calendar day after Executive signed this Agreement. This Agreement shall become effective on the eighth (8th) day after Executive signs it. If Executive timely revokes this Agreement, it will not become effective, and Executive will not receive the Retention Bonus.

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7.No Assignment of Claims. Executive represents and warrants that Executive has not filed or initiated any lawsuits based on claims released in this Agreement. Executive represents and warrants that Executive has not assigned to any third party any claim involving the Released Parties or authorized any third party to assert on Executive’s behalf any claim against the Released Parties. If a third party asserts a claim against the Released Parties on Executive’s behalf or includes Executive as a class member in any class action involving any claim, Executive agrees to not accept any benefits or damages relating to or arising out of such claim. Executive represents and warrants that Executive has full authority to enter into this Agreement.

8.Choice of Law and Venue. This Agreement shall be construed and enforced exclusively pursuant to the laws of the State of Texas applicable to contracts to be performed wholly within the State. The Parties also agree that the venue of any action to enforce the provisions of this Agreement, or any document executed in connection with this Agreement, shall be in Dallas, Texas. The Parties agree they will not contest the choice of law and venue provisions in this Paragraph.

9.Entire Agreement. Excepting only the Retention Agreement and the Employment Agreement, the terms described in this Agreement constitute the entire agreement between the Parties regarding the subject matter in this Agreement and may not be altered or modified other than in a writing signed by each of the Parties to this Agreement. Executive agrees that no promise, inducement or agreement not expressed in this Agreement has been made to Executive in connection with this Agreement. The Parties acknowledge and agree that this Agreement supersedes all prior arrangements, communications, commitments or obligations between Executive and the Company, except as otherwise referenced in this Agreement.

10.Severability. The Parties acknowledge and understand that, if any term of this Agreement shall be determined by a court to be illegal, invalid, unconscionable or unenforceable, the remaining provisions will remain effective and legally binding, and the illegal, invalid, unconscionable or unenforceable term will be deemed not to be a part of this Agreement.

11.Binding Effect. This Agreement and the terms, covenants, conditions, provisions, obligations, undertakings, rights and benefits of this Agreement shall be binding upon, and shall inure to the benefit of, the Parties and their respective heirs, executors, administrators, representatives, officers, directors, shareholders, predecessors, successors, parents, subsidiaries, affiliated entities, agents, attorneys, servants, employees, principals, partners, whether limited or general, and assigns, if any. The Parties each represent and warrant that each of the Parties to this Agreement has the authority to act on their respective behalf and to enter into this Agreement with the other Party.

12.No Waiver. No failure by either Party at any time to give notice of any breach by the other Party of, or to require compliance with, any condition or provision of this Agreement shall be deemed a waiver of any provision or condition of this Agreement. Any waiver of any part of this Agreement will be effective only in a written agreement signed by each of the Parties to this Agreement.

13.Attorneys’ Fees and Costs. This Agreement is intended to settle and release any and all claims that Executive may have against the Released Parties for attorneys’ fees and/or costs.

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IN WITNESS WHEREOF, the Parties represent to each other that they have reviewed and fully discussed this Agreement with counsel, and have satisfied themselves that they fully understand the terms of this Agreement and make this Agreement after such consultation.


OLEG TOLMACHEV




Date:



MONTAGE RESOURCES CORPORATION


By:
Name:		Paul Johnston
Title:		Executive Vice President and General Counsel

Date:

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Exhibit 31.1

CERTIFICATION

I, John K. Reinhart, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Montage Resources Corporation;

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

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

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

(a)

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

(b)

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

(c)

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

(d)

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

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

(a)

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

(b)

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

May 9, 2019

/s/ John K. Reinhart

John K. Reinhart

President and Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, Michael L. Hodges, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Montage Resources Corporation;

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

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

(a)

(b)

(c)

(d)

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

(a)

(b)

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

May 9, 2019

/s/ Michael L. Hodges

Michael L. Hodges

Executive Vice President and Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Montage Resources Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), John K. Reinhart, President and Chief Executive Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

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

(2)

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

May 9, 2019		/s/ John K. Reinhart
		John K. Reinhart
		President and Chief Executive Officer

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of Montage Resources Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Michael Hodges, Executive Vice President and Chief Financial Officer of the Company hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

(1)

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

(2)

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

May 9, 2019		/s/ Michael L. Hodges
		Michael L. Hodges
		Executive Vice President and Chief Financial Officer