Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). ☒ Yes ☐ No

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

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

Number of shares of the registrant’s common stock outstanding at May ~~4, 2018: 302,092,885~~6, 2019: 35,617,374 shares

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 ~~2, 2018.~~15, 2019.

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 ~~2, 2018.~~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.

	March 31, 2018			December 31, 2017			March 31, 2019			December 31, 2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	21,801		$	17,224		$	7,592		$	5,959
Accounts receivable		113,208			77,609			120,802			119,332
Assets held for sale		—			206			2,294			—
Other current assets		8,350			12,023			6,347			8,639
Total current assets		143,359			107,062			137,035			133,930

PROPERTY AND EQUIPMENT AT COST
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method:
Unproved properties		537,958			459,549			557,583			482,475
Proved oil and gas properties, net		694,599			647,881			1,101,772			807,583
Other property and equipment, net		6,785			6,942			13,146			6,300
Total property and equipment, net		1,239,342			1,114,372			1,672,501			1,296,358

OTHER NONCURRENT ASSETS
Other assets		5,617			2,093			8,182			3,481
Operating lease right-of-use asset								44,222			—
Assets held for sale								8,514			—
TOTAL ASSETS	$	1,388,318		$	1,223,527		$	1,870,454		$	1,433,769

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$	96,048		$	76,174		$	141,410		$	116,735
Accrued capital expenditures		12,689			10,658			25,116			12,979
Accrued liabilities		39,423			41,662			61,960			56,909
Accrued interest payable		10,433			21,100			10,876			21,661
Liabilities associated with assets held for sale								8,212			—
Operating lease liability								19,787			—
Total current liabilities		158,593			149,594			267,361			208,284

NONCURRENT LIABILITIES
Debt, net of unamortized discount and debt issuance costs		495,707			495,021			498,469			497,778
Credit facility		65,000			—
Revolving credit facility								97,500			32,500
Asset retirement obligations		6,269			6,029			24,148			7,110
Other liabilities		2,100			529			1,021			611
Operating lease liability								25,592			—
Liabilities associated with assets held for sale								6,639			—
Total liabilities		727,669			651,173			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, 301,771,111 and 262,740,355 shares issued and outstanding, respectively		3,033			2,637
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		2,059,418			1,967,958			2,349,527			2,065,119
Treasury stock, shares at cost; 1,499,566 and 992,315 shares, respectively		(3,031	)		(2,096	)
Treasury stock, shares at cost; 2,478,798 and 1,747,624 shares, respectively								(8,768	)		(3,357	)
Accumulated deficit		(1,398,771	)		(1,396,145	)		(1,391,417	)		(1,377,319	)
Total stockholders' equity		660,649			572,354			949,724			687,486
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	1,388,318		$	1,223,527		$	1,870,454		$	1,433,769

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

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2018			2017			2019			2018
REVENUES
Natural gas, oil and natural gas liquids sales	$	110,184		$	99,432		$	131,828		$	110,184
Brokered natural gas and marketing revenue		8			2,431			9,530			8
Other revenue								139			—
Total revenues		110,192			101,863			141,497			110,192

OPERATING EXPENSES
Lease operating		9,390			2,343			7,525			9,390
Transportation, gathering and compression		27,689			32,877			41,168			27,689
Production and ad valorem taxes		2,445			1,931			2,848			2,445
Brokered natural gas and marketing expense		48			2,460			9,459			48
Depreciation, depletion and amortization		31,156			26,189
Depreciation, depletion, amortization and accretion								29,897			31,311
Exploration		15,278			11,581			16,789			15,278
General and administrative		9,757			10,132			28,930			9,757
Accretion of asset retirement obligations		155			124
(Gain) loss on sale of assets		(267	)		(5	)		2			(267	)
Other expense								24			—
Total operating expenses		95,651			87,632			136,642			95,651
OPERATING INCOME (LOSS)		14,541			14,231
OPERATING INCOME								4,855			14,541
OTHER INCOME (EXPENSE)
Gain (loss) on derivative instruments		(4,215	)		25,097
Loss on derivative instruments								(4,931	)		(4,215	)
Interest expense, net		(12,952	)		(12,462	)		(13,840	)		(12,952	)
Other income (expense)		—			(19	)
Total other income (expense), net		(17,167	)		12,616			(18,771	)		(17,167	)
INCOME (LOSS) BEFORE INCOME TAXES		(2,626	)		26,847
INCOME TAX BENEFIT (EXPENSE)		—			—
NET INCOME (LOSS)	$	(2,626	)	$	26,847
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 INCOME (LOSS) PER COMMON SHARE
NET LOSS PER COMMON SHARE
Basic	$	(0.01	)	$	0.10		$	(0.55	)	$	(0.13	)
Diluted	$	(0.01	)	$	0.10		$	(0.55	)	$	(0.13	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		293,450			261,105			25,564			19,563
Diluted		293,450			264,215			25,564			19,563

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

Number of
Shares

Common
Stock
($0.01 Par)

Additional
Paid-in-
Capital

Treasury
Stock

Accumulated
Deficit

Total

Balances, December 31,
   2017

262,740,355

$
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

37,823,596

378

89,642

—

—

90,020

Issuance of common stock
   upon vesting of  equity-
   based compensation
   awards, net of shares
   withheld for income
   tax withholdings

1,207,160

18

(18
)

(935
)

—

(935
)
Net income (loss)

—

—

—

—

(2,626
)

(2,626
)
Balances, March 31,
   2018

301,771,111

$
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, 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.

	For the Three Months Ended March 31,						For the Three Months Ended March 31,
	2018			2017			2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(2,626	)	$	26,847
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		31,156			26,189
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		6,790			4,988			9,600			6,790
Stock-based compensation		1,981			2,081			6,001			1,981
Accretion of asset retirement obligations		155			124
(Gain) loss on derivative instruments		4,215			(25,097	)
Net cash for plugging wells								(48	)		—
Loss on derivative instruments								4,931			4,215
Net cash receipts (payments) on settled derivatives		141			(3,989	)		(3,186	)		141
(Gain) loss on sale of assets		(267	)		(5	)		2			(267	)
Amortization of deferred financing costs		554			502			629			554
Amortization of debt discount		332			330			333			332
Changes in operating assets and liabilities:
Accounts receivable		(35,499	)		10,478			25,812			(35,499	)
Other assets		(459	)		943			(188	)		(459	)
Accounts payable and accrued liabilities		(3,179	)		(14,992	)		(68,643	)		(3,179	)
Net cash provided by operating activities		3,294			28,399
Net cash provided by (used in) operating activities								(8,905	)		3,294
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for oil and gas properties		(66,441	)		(66,005	)		(58,530	)		(66,441	)
Capital expenditures for other property and equipment		(155	)		(178	)		(184	)		(155	)
Proceeds from sale of assets		4,099			24			1			4,099
Cash proceeds from merger								12,894			—
Change in deposits and other long term assets								(3	)		—
Net cash used in investing activities		(62,497	)		(66,159	)		(45,822	)		(62,497	)
CASH FLOWS FROM FINANCING ACTIVITIES
Debt issuance costs		(48	)		(1,231	)		(3,102	)		(48	)
Repayments of long-term debt		(92	)		(74	)		(98	)		(92	)
Proceeds from credit facility		65,000			—
Proceeds (repayments) from revolving credit facility								65,000			65,000
Equity issuance costs		(145	)		—			(30	)		(145	)
Employee tax withholding for settlement of equity compensation awards		(935	)		(1,706	)		(5,410	)		(935	)
Net cash provided by (used in) financing activities		63,780			(3,011	)
Net increase (decrease) in cash and cash equivalents		4,577			(40,771	)
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		17,224			201,229			5,959			17,224
Cash and cash equivalents at end of period	$	21,801		$	160,458		$	7,592		$	21,801
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for interest	$	23,638		$	23,066		$	24,198		$	23,638
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES
Asset retirement obligations incurred, including changes in estimate	$	85		$	124		$	16,691		$	85
Additions of other property through debt financing	$	174		$	—		$	—		$	174
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures	$	8,864		$	13,126		$	45,287		$	8,864
Asset acquisition through stock issuance	$	90,020		$	—		$	—		$	90,020
BRMR Merger consideration							$	275,759		$	—

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

~~Eclipse~~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.

The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, ~~2017,~~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 ~~2, 2018.~~15, 2019.

Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, ~~2018~~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:

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.

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.

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, ~~2018~~2019 or December 31, ~~2017.~~2018.

The Company accrues revenue due to timing differences between the delivery of natural gas, ~~natural gas liquids (NGLs),~~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 ~~$51.3~~$83.2 million and ~~$52.9~~$94.1 million of accrued revenues, net of certain expenses, at March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets.

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 ~~amortization~~accretion expense (see “Depreciation, Depletion, Amortization and ~~Amortization~~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, 2018			December 31, 2017			March 31, 2019			December 31, 2018
Oil and natural gas properties:
Unproved	$	537,958		$	459,549		$	557,583		$	482,475
Proved		1,973,468			1,896,081			2,511,575			2,188,233
Gross oil and natural gas properties		2,511,426			2,355,630			3,069,158			2,670,708
Less accumulated depreciation, depletion and amortization		(1,278,869	)		(1,248,200	)		(1,409,803	)		(1,380,650	)
Oil and natural gas properties, net		1,232,557			1,107,430			1,659,355			1,290,058
Other property and equipment		13,837			13,508			21,662			14,460
Less accumulated depreciation		(7,052	)		(6,566	)		(8,516	)		(8,160	)
Other property and equipment, net		6,785			6,942			13,146			6,300
Property and equipment, net	$	1,239,342		$	1,114,372		$	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 ~~$0.5~~$0.7 million and ~~$0.4~~$0.5 million for the three months ended March 31, 2019 and 2018, ~~and 2017,~~ respectively.

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.

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.

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 ~~receives~~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.

The Company sells NGLs directly to the NGLs purchaser. For these NGLs, the sales contracts provide that the Company ~~delivers~~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.~~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.

Under the Company’s oil sales contracts, the Company generally sells oil to the purchaser from storage tanks ~~near~~at central stabilization facilities and ~~collect~~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.

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.

The following table illustrates the revenue disaggregated by type for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,				Three Months Ended March 31,
	2018		2017		2019		2018
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420	$	81,825	$	58,483
NGL sales		19,743		17,063		21,248		19,743
Oil sales		31,958		20,949		28,755		31,958
Brokered natural gas and marketing revenue		8		2,431		9,530		8
Other revenue						139		—
Total revenues	$	110,192	$	101,863	$	141,497	$	110,192

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 isare 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.

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 ~~$51.3~~$83.2 million and ~~$52.9~~$94.1 million at March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively.

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, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):

	March 31, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Receivables by product or service:
Sale of oil and natural gas and related products and services	$	51,298	$	52,908	$	83,188	$	94,107
Joint interest owners		60,263		23,154		35,559		24,830
Derivatives		1,628		1,528		1,878		372
Other		19		19		177		23
Total	$	113,208	$	77,609	$	120,802	$	119,332

Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the ~~State~~States of ~~Ohio.~~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.~~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 ($~~8.9)~~3.3) million and ~~($5.1)~~a net asset position of $5.7 million at March 31, ~~2018~~2019 and December 31, ~~2017,~~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, ~~2018~~2019 and December 31, ~~2017,~~2018, the Company did not have past-due receivables from or payables to any of such counterparties.

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 ~~$30.7~~$29.5 million and ~~$25.7~~$30.9 million for the three months ended March 31, 2019 and 2018, respectively and ~~2017, respectively.~~is included in Depreciation, depletion, amortization and accretion expense in the Condensed Consolidated Statements of Operations.

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 ~~each of~~ the three months ended March 31, 2019 and 2018, ~~and 2017.~~respectively. This amount is included in ~~DD&A~~Depreciation, depletion, amortization and accretion expense in the ~~condensed consolidated statements~~Condensed Consolidated Statements of ~~operations.~~Operations.

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, ~~2018~~2019 or the three months ended March 31, ~~2017.~~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 ~~$6.7~~$9.6 million and ~~$4.1~~$6.7 million for the three months ended March 31, 2019 and 2018, ~~and 2017,~~ respectively. The increase in impairment charges during the three months ended March 31, 2018 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity price environment. These costs are included in exploration expense in the condensed consolidated statements of operations.

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.

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.

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.

The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “~~Asset~~“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, which was 10.33% for each of the three months ended March 31, 2018 and 2017.~~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~~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, ~~2018~~2019 (in thousands):

	Three Months Ended March 31, 2018		Three Months Ended March 31, 2019
Asset retirement obligations, beginning of period	$	6,029	$	7,110
Accretion				347
Additional liabilities incurred		85		49
Accretion		155
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	$	6,269	$	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.

The Company leases office space under an operating lease that expires in 2024. The lease term begins on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease term unless the renewals are deemed to be reasonably assured at lease inception.

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.

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.

The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”), which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted this standard effective January 1, 2018 using the modified retrospective method. The Company did not recognize a significant impact on its financial position or results of operations. Upon adoption of this new standard, the Company did not record a cumulative effect adjustment nor did the Company alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify the impact of future revenue contracts entered into by the Company. Additional disclosures have been included to provide further detail regarding the Company’s revenue recognition policies. 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~~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 ~~plans to adopt this standard~~adopted these standards effective January 1, 2019 using the ~~modified retrospective~~optional transition method ~~and is evaluating the standard’s applicability to its various contractual arrangements. Although the Company believes that the adoption~~ of the standard will result in increases to its assets and liabilities on its consolidated balance sheet as well as changes to the presentation of certain operating expenses on its consolidated statement of operations, the Company has not yet determined the extent of the adjustments that will be required upon implementation of the standard.adoption. The Company ~~continues~~implemented a third party sponsored lease accounting information system to ~~monitor relevant industry guidance regarding~~facilitate the ~~implementation of the standard.~~

~~In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts~~accounting and ~~Cash Payments.” The new standard provides guidance on how certain cash receipts~~financial reporting requirements, and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and did not recognize a significant impact on its financial position, results of operations, or statement of cash flows.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” Currently under the standard, there are three elements of a business: inputs,implemented processes and ~~outputs. The revised guidance adds an initial screen test~~controls to ~~determine if substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets. If~~review new contracts and modifications to existing contracts that ~~screen is met, the set of assets is not a business. The new framework also specifies the minimum required inputs and processes necessary to be a business. This amendment is effective~~contain lease components for ~~periods after December 15, 2017, with early adoption permitted. The Company adopted this standard effective January 1, 2018 and considered the new guidance in its assessment of the~~appropriate accounting ~~treatment~~treatment. See “Note 7 – Leases” for the ~~Flat Castle Acquisition. (See Note 4—Acquisition~~).disclosures required by the standards.

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 ~~37.8~~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.

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):

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.

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 totaling approximately 400 acres.~~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 totaling approximately 50 acres.~~party. As a result of this sale, the Company recognized a gain of approximately $0.3 million.

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:

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:

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

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):

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

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, ~~2018,~~2019, the Company’s derivative instruments were with Bank of Montreal, ~~Citibank, Goldman Sachs,~~J Aron, Morgan Stanley, Capital One N.A., BP Energy Company, KeyBank N.A, NextEra Energy, Inc., Shell Oil Company and ~~KeyBank N.A.~~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, ~~2018,~~2019, for future production periods:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)			Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90			90,000	April 2019 – December 2019	$	2.84
		20,000	April 2018 – December 2018	$	2.80			15,000	April 2019 – September 2019	$	2.79
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
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)		30,000	April 2018 – March 2019	$	3.00			77,500	April 2019 – December 2019	$	2.72
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40			77,500	April 2019 – December 2019	$	3.04
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50			77,500	April 2019 – December 2019	$	2.30
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80			40,000	April 2019 – June 2019	$	2.65
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36			40,000	April 2019 – June 2019	$	2.84
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50			40,000	April 2019 – June 2019	$	2.30
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75			70,000	January 2020 – June 2020	$	2.70
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10			70,000	January 2020 – June 2020	$	2.98
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30			70,000	January 2020 – June 2020	$	2.25
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72			30,000	October 2019 – June 2020	$	2.90
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02			30,000	October 2019 – June 2020	$	3.15
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30			30,000	October 2019 – June 2020	$	2.50
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75			40,000	April 2019 – December 2019	$	3.44
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)		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	)

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

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, 2018	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
As of March 31, 2019											Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	11,768		$	(6,258	)	$	5,510		Other current assets	$	2,416		$	(2,154	)	$	262		Other current assets
Commodity derivatives - noncurrent		3,931			(14	)		3,917		Other assets		1,510			(176	)		1,334		Other assets
Total assets	$	15,699		$	(6,272	)	$	9,427			$	3,926		$	(2,330	)	$	1,596

Liabilities
Commodity derivatives - current	$	(23,012	)	$	6,258		$	(16,754	)	Accrued liabilities	$	(6,234	)	$	2,154		$	(4,080	)	Accrued liabilities
Commodity derivatives - noncurrent		(1,603	)		14			(1,589	)	Other liabilities		(972	)		176			(796	)	Other liabilities
Total liabilities	$	(24,615	)	$	6,272		$	(18,343	)		$	(7,206	)	$	2,330		$	(4,876	)

As of December 31, 2017	Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
As of December 31, 2018											Gross Amount			Netting Adjustments(a)			Net Amount Presented in Balance Sheets			Balance Sheet Location
Assets
Commodity derivatives - current	$	15,971		$	(6,380	)	$	9,591		Other current assets	$	4,960		$	(845	)	$	4,115		Other current assets
Commodity derivatives - noncurrent		469			(176	)		293		Other assets		1,910			—			1,910		Other assets
Total assets	$	16,440		$	(6,556	)	$	9,884			$	6,870		$	(845	)	$	6,025

Liabilities
Commodity derivatives - current	$	(21,256	)	$	6,380		$	(14,876	)	Accrued liabilities	$	(845	)	$	845		$	—		Accrued liabilities
Commodity derivatives - noncurrent		(252	)		176			(76	)	Other liabilities		(326	)		—			(326	)	Other liabilities
Total liabilities	$	(21,508	)	$	6,556		$	(14,952	)		$	(1,171	)	$	845		$	(326	)

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						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,					Location of Gain (Loss) Recognized in Income	Three Months Ended March 31,
		2018			2017			2019			2018
Commodity derivatives	Gain (loss) on derivative instruments	$	(4,215	)	$	25,097	Gain (loss) on derivative instruments	$	(4,931	)	$	(4,215	)

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			Level 1		Level 2			Level 3		Total Fair Value
As of March 31, 2018: (in thousands)
As of March 31, 2019: (in thousands)
Commodity derivative instruments	$	—	$	(8,916	)	$	—	$	(8,916	)	$	—	$	(3,280	)	$	—	$	(3,280	)
Total	$	—	$	(8,916	)	$	—	$	(8,916	)	$	—	$	(3,280	)	$	—	$	(3,280	)
As of December 31, 2017: (in thousands)
As of December 31, 2018: (in thousands)
Commodity derivative instruments	$	—	$	(5,068	)	$	—	$	(5,068	)	$	—	$	5,699		$	—	$	5,699
Total	$	—	$	(5,068	)	$	—	$	(5,068	)	$	—	$	5,699		$	—	$	5,699

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 8—10—Debt).

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~~senior PIK ~~Notes.~~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, ~~2018~~2019 and ~~2017,~~2018, the Company amortized ~~$0.9~~$1.0 million and ~~$0.8~~$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, ~~2018.~~2019.

Based on Level 2 market data inputs, the fair value of the senior unsecured notes at March 31, ~~2018~~2019 was ~~$482.0~~$486.6 million.

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).

~~In January 2015, the~~The credit agreement governing the revolving credit facility ~~was amended and restated~~ (as amended and restated, the “Credit Agreement”)~~, primarily~~ was amended and restated on January 12, 2015. The primary change effected by such amendment was to add ~~Eclipse~~Montage Resources Corporation as a party ~~thereto~~to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions ~~therein.~~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, ~~Eclipse~~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 ~~remained~~remain generally consistent with Eclipse I’s previous credit agreement.

On February 24, 2016, the Company amended the Credit ~~Amendment~~Agreement to, among other ~~things,~~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, ~~2018,~~2019, the borrowing base was ~~$225~~$375 million and the Company had ~~$65~~$97.5 million in outstanding borrowings under the revolving credit facility. After giving effect to outstanding letters of credit issued by the Company totaling ~~$33.6~~$13.5 million and the outstanding borrowings of ~~$65~~$97.5 million, the Company had available borrowing capacity under the revolving credit facility of ~~$126.4~~$264.0 million at March 31, ~~2018.~~ 2019.

Subsequent to March 31, ~~2018,~~2019, the Company ~~repaid $20~~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 ~~which reduced the outstanding borrowings to $45 million and resulted in available borrowing capacity of $146.4~~was $248.3 million. In April 2018, the Company completed its most recent borrowing base redetermination, which resulted in no change to the borrowing base of $225 million. The Company’s next scheduled borrowing base redetermination is expected to be completed by October 2018.

The revolving credit facility is secured by mortgages on ~~substantially all~~85% of the value of the Company’s ~~properties~~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, ~~2018.~~2019. Commitment fees on the unused portion of the revolving credit facility are due quarterly at ~~0.5%~~0.375%-0.500% of the unused facility based on utilization.

The Company currently maintains a retirement plan intended to provide benefits under section ~~401(K)~~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)~~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, ~~2018~~2019 and ~~2017,~~2018, respectively.

The Company is authorized to grant up to ~~25,000,000~~1,666,667 shares of common stock under its ~~Amended and Restated~~ 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 ~~7,199,257~~430,656 shares were available for future grants under the Plan as of March 31, ~~2018.~~2019.

Our stock-based compensation expense was as follows for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 (in thousands):

	Three Months Ended March 31,				Three Months Ended March 31,
	2018		2017		2019		2018
Restricted stock units	$	1,164	$	1,247	$	3,147	$	1,164
Performance units		728		734		2,759		728
Restricted stock issued to directors		89		100		95		89
Total expense	$	1,981	$	2,081	$	6,001	$	1,981

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, ~~2018,~~2019, there was ~~$7.0~~$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 ~~1 year.~~2 years. A summary of employee restricted stock unit awards activity during the three months ended March 31, ~~2018~~2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)		Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		4,057,354		$	2.48	$	9,738
Total awarded and unvested, December 31, 2018									233,960		$	29.27	$	3,685
Granted		1,498,524			1.70				70,409			17.55
Vested		(1,378,403	)		3.17				(198,279	)		29.28
Forfeited		(6,512	)		2.15				(485	)		31.78
Total awarded and unvested, March 31, 2018		4,170,963		$	1.97	$	6,006
Total awarded and unvested, March 31, 2019									105,605		$	21.42	$	1,588

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, ~~2018,~~2019, there was ~~$6.4~~$2.0 million of total unrecognized compensation cost related to outstanding performance units. The weighted average period for the shares to vest is approximately ~~2 years.~~1 year. A summary of performance stock unit awards activity during the three months ended March 31, ~~2018~~2019 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)		Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested, December 31, 2017		3,966,377		$	1.82	$	11,257
Total awarded and unvested, December 31, 2018									346,589		$	27.68	$	716
Granted		1,498,524			1.92				—			—
Vested		—			—				(265,311	)		27.54
Forfeited		(9,768	)		1.94				(16,001	)		24.47
Total awarded and unvested, March 31, 2018		5,455,133		$	1.84	$	2,856
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 and 2017:~~2018:

On May ~~18, 2016,~~17, 2017, the Company issued an aggregate of ~~149,448~~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 ~~18, 2017.~~17, 2018. For the three months ended March 31, ~~2017,~~2018, the Company recognized expense of approximately $0.1 million related to these awards.

On May ~~17, 2017,~~16, 2018, the Company issued an aggregate of ~~153,192~~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 ~~17, 2018.~~16, 2019. For the three months ended March 31, ~~2018,~~2019, the Company recognized expense of approximately $0.1 million related to these awards. As of March 31, ~~2018,~~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.

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.

Effective immediately prior to the Effective Timeon 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, ~~2018~~2019 and ~~2017, respectively:~~2018:

	Three Months Ended March 31,														Three Months Ended March 31,
(in thousands, except per share data)	2018								2017						2019								2018
	Income (Loss)			Shares		Per Share			Income (Loss)		Shares		Per Share		Loss			Shares		Per Share			Loss			Shares		Per Share
Basic:
Net income (loss), shares, basic	$	(2,626	)		293,450	$	(0.01	)	$	26,847		261,105	$	0.10
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		—			—					—		3,110				—			—					—			—
Diluted:
Net income (loss), shares, diluted	$	(2,626	)		293,450	$	(0.01	)	$	26,847		264,215	$	0.10
Net loss, shares, diluted															$	(14,098	)		25,564	$	(0.55	)	$	(2,626	)		19,563	$	(0.13	)

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 ~~are~~were owned by the Company’s former Chairman, President and Chief Executive Officer. The ~~Company incurred approximately $0.1 million related to such services during the three months ended March 31, 2017. The~~ fees ~~are~~were paid in accordance with a standard service contract that ~~does~~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.~~EnCap Investments L.P. (“EnCap”). EnCap has representatives on the Board, and affiliates of EnCap collectively beneficially own ~~a majority~~approximately 40% of the outstanding shares of ~~our~~the Company’s common stock. (See Note 4—~~Acquisition~~Acquisitions).

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.

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.

~~The development~~As a result of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent thatBRMR Merger, the Company ~~is not the operator~~assumed commitments related to certain gas gathering and processing agreements entered into by Triad Hunter, LLC (“Triad Hunter”), a wholly owned subsidiary of ~~oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties.~~BRMR as shown below (in thousands):

The Company leases office space under an operating lease that expires in 2024. The Company recognized rent expense of $0.2 million and $0.2 million for the three months ended March 31, 2018 and 2017, respectively.

For the year ending December 31, ~~2018,~~2019, the Company’s annual estimated effective tax rate is forecasted to be 0%, exclusive of discrete items. The Company expects to incur ~~both~~book income but a ~~book and~~ tax loss in fiscal year ~~2018,~~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%. For the three months ended March 31, 2018, the Company’s overall effective tax rate on operations was different than the federal statutory rate of 21% due primarily to valuation allowances and other permanent differences.

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. Future interpretations relating to the passage of the Tax Cuts and Jobs Act which vary from our current interpretation, and possible changes to state tax laws in response to the recently enacted federal legislation, may have a significant effect on our future taxable position. The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.

In forecasting the ~~2018~~2019 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book ~~loss~~income such that no net deferred tax asset is recorded in ~~2018.~~2019. Management reached this conclusion considering several factors such as: (i) the ~~Company’s short tax history, (ii) the~~ lack of carryback potential resulting in a tax refund, and ~~(iii)~~(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. ~~At this time,~~

The Company is forecasting positive pre-tax book income for the ~~estimated~~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 ~~be recorded~~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 ~~2018~~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 ~~$5.3 million.~~still evaluating the impacts that Code section 382 will have on its tax attributes.

~~The~~Each subsidiary of the Company that guarantees the Company’s ~~wholly-owned subsidiaries each have~~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 8—10—Debt). ~~The Parent company~~Montage Resources Corporation, standing alone, has no independent assets or operations. The Company’s wholly owned subsidiaries are not restricted from transferring funds to ~~the Parent~~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:

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 ~~those~~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.~~statements (See Note 8—10—Debt and Note 15—Commitments and Contingencies).

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, ~~2017~~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.

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, ~~2018,~~2019, we had assembled an acreage position approximating ~~199,000~~243,500 net acres in Eastern Ohio, ~~and 43,000~~45,000 net acres in Pennsylvania, and 45,800 net acres in West Virginia, which excludes any acreage currently pending title. As used in this Quarterly Report, unless the context indicates or otherwise requires, “Eclipse,” “Eclipse Resources,” the “Company,” “we,” “our,” “us” and like terms refer collectively to Eclipse Resources Corporation and its consolidated subsidiaries.

Approximately ~~135,000~~204,800 of our net acres are located in the Utica Shale fairway, which we refer to as the Utica Core Area, and approximately ~~15,500~~89,300 net acres of ~~these net acres~~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 ~~95%~~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, 2018, we, or our operating partners, had commenced drilling 242 gross wells within the Utica Core Area and our Marcellus Area, of which 7 gross were top holed, 7 gross were drilling, 12 gross were awaiting completion or were in the process of being completed, and 216 gross had been turned to sales.

~~As of March 31, 2018,~~2019, we were operating 2 horizontal rigs in the Utica Core Area. We had average daily production for the three months ended March 31, ~~2018~~2019 of approximately ~~315.2~~407.5 MMcfe comprised of approximately ~~72%~~74% natural gas, 16% NGLs and ~~12%~~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.

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).

During the three months ended March 31, ~~2018,~~2019, we achieved the following financial and operating results:

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 ~~average daily,~~the high, low and average daily and monthly settled NYMEX Henry Hub prices for natural gas and the high, low and average daily ~~high and low~~ NYMEX WTI prices for oil for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,				Three Months Ended March 31,
	2018		2017		2019		2018
NYMEX Henry Hub High ($/MMBtu)	$	6.24	$	3.71	$	4.25	$	6.24
NYMEX Henry Hub Low ($/MMBtu)		2.49		2.44		2.54		2.49
Average Daily NYMEX Henry Hub ($/MMBtu)		3.08		3.02		2.92		3.08
Average Monthly Settled NYMEX Henry Hub ($/MMBtu)		3.00		3.32		3.15		3.00

NYMEX WTI High ($/Bbl)	$	66.27	$	54.48	$	60.19	$	66.27
NYMEX WTI Low ($/Bbl)		59.20		47.00		46.31		59.20
Average Daily NYMEX WTI ($/Bbl)		62.91		51.62		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, ~~2017.~~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, ~~2018~~2019 and held all other factors constant, then our estimated net proved reserves at December 31, ~~2017~~2018 would have increased by approximately 5%0.1% from our previously reported estimated net proved reserves at such time, including a 7%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 ~~$2.99~~$3.07 per MMBtu for natural gas and ~~$53.59~~$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, ~~2017.~~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, ~~2018,~~2019, cash flows from operations, borrowings under our revolving credit facility, and proceeds from asset ~~sales, and proceeds from additional debt and/or equity offerings.~~sales.

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, ~~2018~~2019 Compared to Three Months Ended March 31, ~~2017~~2018

The following table illustrates the revenue attributable to our operations for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,							Three Months Ended March 31,
	2018		2017		Change			2019		2018		Change
Revenues (in thousands)
Natural gas sales	$	58,483	$	61,420	$	(2,937	)	$	81,825	$	58,483	$	23,342
NGL sales		19,743		17,063		2,680			21,248		19,743		1,505
Oil sales		31,958		20,949		11,009			28,755		31,958		(3,203	)
Brokered natural gas and marketing revenue		8		2,431		(2,423	)		9,530		8		9,522
Other revenue									139		—		139
Total revenues	$	110,192	$	101,863	$	8,329		$	141,497	$	110,192	$	31,305

Our production ~~grew~~increased by approximately ~~2.3~~8.3 Bcfe for the three months ended March 31, ~~2018~~2019 over the same period in ~~2017~~2018 due to ~~new~~increased drilling activity and from wells ~~that we placed into production.~~acquired as part of the BRMR Merger. Our production for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 is set forth in the following table:

	Three Months Ended March 31,						Three Months Ended March 31,
	2018		2017		Change		2019		2018		Change
Production:
Natural gas (MMcf)		20,343.3		19,381.6		961.7		27,205.0		20,343.3		6,861.7
NGLs (Mbbls)		772.7		665.0		107.7		980.5		772.7		207.8
Oil (Mbbls)		565.4		454.1		111.3		598.0		565.4		32.6
Total (MMcfe)		28,371.9		26,096.2		2,275.7		36,676.0		28,371.9		8,304.1

Average daily production volume:
Natural gas (Mcf/d)		226,037		215,351		10,686		302,278		226,037		76,241
NGLs (Bbls/d)		8,586		7,389		1,197		10,894		8,586		2,308
Oil (Bbls/d)		6,282		5,046		1,236		6,644		6,282		362
Total (Mcfe/d)		315,243		289,958		25,285		407,506		315,243		92,263

Our average realized price (including cash ~~derivative settlements~~settled derivatives and firm ~~third-party transportation costs)~~transportation) received during the three months ended March 31, ~~2018~~2019 was ~~$3.62~~$3.10 per Mcfe compared to ~~$3.23~~$3.62 per Mcfe during the three months ended March 31, ~~2017.~~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 ~~derivative~~cash settled settlements and ~~third-party~~ firm ~~transportation costs)~~transportation) calculation also includes all cash settlements for derivatives. Average sales price (excluding cash settled ~~derivatives)~~derivatives and firm transportation) does not include derivative settlements or ~~third-party~~firm transportation, ~~costs,~~ which are reported in transportation, gathering and compression expense on the accompanying condensed consolidated statements of operations. Average sales price ~~(excluding~~(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, ~~2018~~2019 and ~~2017~~2018 are shown below:

	Three Months Ended March 31,							Three Months Ended March 31,
	2018		2017		Change			2019		2018		Change
Average realized price (excluding cash settled derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.87	$	3.17	$	(0.30	)	$	3.01	$	2.87	$	0.14
NGLs ($/Bbl)		25.55		25.66		(0.11	)		21.67		25.55		(3.88	)
Oil ($/Bbl)		56.52		46.13		10.39			48.09		56.52		(8.43	)
Total average prices ($/Mcfe)		3.88		3.81		0.07			3.59		3.88		(0.29	)

Average realized price (including cash settled derivatives, excluding firm transportation)
Natural gas ($/Mcf)	$	3.05	$	3.01	$	0.04		$	2.85	$	3.05	$	(0.20	)
NGLs ($/Bbl)		24.33		24.07		0.26			21.89		24.33		(2.44	)
Oil ($/Bbl)		52.30		46.28		6.02			49.66		52.30		(2.64	)
Total average prices ($/Mcfe)		3.89		3.66		0.23			3.52		3.89		(0.37	)

Average realized price (including firm transportation, excluding cash settled derivatives)
Natural gas ($/Mcf)	$	2.49	$	2.60	$	(0.11	)	$	2.45	$	2.49	$	(0.04	)
NGLs ($/Bbl)		25.55		25.66		(0.11	)		21.67		25.55		(3.88	)
Oil ($/Bbl)		56.52		46.13		10.39			48.09		56.52		(8.43	)
Total average prices ($/Mcfe)		3.61		3.39		0.22			3.18		3.61		(0.43	)

Average realized price (including cash settled derivatives and firm transportation)
Natural gas ($/Mcf)	$	2.67	$	2.44	$	0.23		$	2.30	$	2.67	$	(0.37	)
NGLs ($/Bbl)		24.33		24.07		0.26			21.89		24.33		(2.44	)
Oil ($/Bbl)		52.30		46.28		6.02			49.66		52.30		(2.64	)
Total average prices ($/Mcfe)		3.62		3.23		0.39			3.10		3.62		(0.52	)

Brokered natural gas and marketing revenue was ~~$2.4~~$9.5 million for the three months ended March 31, ~~2017. There was~~2019 compared to less than $0.1 million ~~of brokered natural gas and marketing revenue~~ for the three months ended March 31, 2018. Brokered natural gas and marketing revenue includes revenue ~~we receive as a result of~~received from selling natural gas ~~that is~~ not related to ~~our~~ production and from the release of firm transportation capacity. The ~~decrease~~increase from ~~the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during~~ the three months ended March 31, 2018 ~~which resulted in a decrease~~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.

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, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,							Three Months Ended March 31,
	2018		2017		Change			2019		2018		Change
Operating expenses (in thousands):
Lease operating	$	9,390	$	2,343	$	7,047		$	7,525	$	9,390	$	(1,865	)
Transportation, gathering and compression		27,689		32,877		(5,188	)		41,168		27,689		13,479
Production and ad valorem taxes		2,445		1,931		514			2,848		2,445		403
Depreciation, depletion and amortization		31,156		26,189		4,967
Depreciation, depletion, amortization and accretion									29,897		31,311		(1,414	)
General and administrative		9,757		10,132		(375	)		28,930		9,757		19,173
Operating expenses per Mcfe:
Lease operating	$	0.33	$	0.09	$	0.24		$	0.21	$	0.33	$	(0.12	)
Transportation, gathering and compression		0.97		1.27		(0.30	)		1.12		0.97		0.15
Production and ad valorem taxes		0.09		0.07		0.02			0.08		0.09		(0.01	)
Depreciation, depletion and amortization		1.10		1.00		0.10
Depreciation, depletion, amortization and accretion									0.82		1.10		(0.28	)
General and administrative		0.34		0.39		(0.05	)		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 compared to $2.3 million~~2018. Lease operating expense per Mcfe was $0.21 in the three months ended March 31, ~~2017. Lease operating expense per Mcfe was~~2019 compared to $0.33 in the three months ended March 31, ~~2018 compared~~2018. The decrease of ($1.9) million and $(0.12) per Mcfe was primarily attributable to ~~$0.09 in~~a reduction of non-recurring workovers for the three months ended March 31, 2017. The increase of $7.0 million and $0.24 per Mcfe is attributable to an increase in the number of producing wells during the three months ended March 31, 2018 as well as increases in salt water disposal and workover expenses incurred during the three months ended March 31, 2018, in each case,2019 as compared to the three months ended March 31, ~~2017.~~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 compared to $32.9 million during the three months ended March 31, 2017.~~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 compared to $1.27 in the three months ended March 31, 2017.~~2018. The following table details our transportation, gathering and compression expenses for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,							Three Months Ended March 31,
	2018		2017		Change			2019		2018		Change
Transportation, gathering and compression (in thousands):
Gathering, compression and fuel	$	9,661	$	10,748	$	(1,087	)	$	12,325	$	9,661	$	2,664
Processing and fractionation		8,501		8,317		184			11,978		8,501		3,477
Liquids transportation and stabilization		1,783		2,761		(978	)		1,744		1,783		(39	)
Marketing		7		12		(5	)		72		7		65
Firm transportation		7,737		11,039		(3,302	)		15,049		7,737		7,312
	$	27,689	$	32,877	$	(5,188	)	$	41,168	$	27,689	$	13,479
Transportation, gathering and compression per Mcfe:
Gathering, compression and fuel	$	0.34	$	0.42	$	(0.08	)	$	0.33	$	0.34	$	(0.01	)
Processing and fractionation		0.30		0.32		(0.02	)		0.33		0.30		0.03
Liquids transportation and stabilization		0.06		0.11		(0.05	)		0.05		0.06		(0.01	)
Marketing		—		—		—			—		—		—
Firm transportation		0.27		0.42		(0.15	)		0.41		0.27		0.14
	$	0.97	$	1.27	$	(0.30	)	$	1.12	$	0.97	$	0.15

The ~~decrease~~increase of ~~$5.2~~$13.5 million to transportation, gathering and compression ~~expense in~~expenses during the three months ended March 31, ~~2018~~2019 was primarily due to ~~our lower contracted~~increased firm transportation capacity and ~~utilization~~increased production during the three months ended March 31, 2019. The increase of ~~third party volumes. The decrease of $0.30~~$0.15 per Mcfe was primarily ~~related~~due to ~~lower contractual rates, utilization of third party volumes~~increased firm transportation capacity and ~~fixed costs spread over~~ increased ~~production.~~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, ~~compared~~respectively. The increase in aggregate for production and ad valorem taxes was primarily due to ~~$1.9~~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, ~~2017. Production and ad valorem taxes per Mcfe was $0.09~~2019 compared to $31.3 million in the three months ended March 31, ~~2018 compared to $0.07 in~~2018. DD&A per Mcfe was $0.82 for the three months ended March 31, ~~2017. The increase in production and ad valorem taxes is due~~2019 compared to ~~increased production~~$1.10 for the three months ended March 31, 2018. ~~The $0.02 increase~~DD&A decreased on ~~a per unit basis is due to the increased percentage of condensate production.~~

~~Depreciation, depletion~~an aggregate and ~~amortization~~ was approximately $31.2 million in the three months ended March 31, 2018 compared to $26.2 million in the three months ended March 31, 2017. The increase in the three months ended March 31, 2018 when compared to the three months ended March 31, 2017 is due to the increase in production for the three months ended March 31, 2018. On a per Mcfe basis ~~DD&A increased to $1.10 in the three months ended March 31, 2018 from $1.00 in the three months ended March 31, 2017,~~ which was predominantly driven by the ~~higher~~lower depletion rate resulting from ~~increased proved property~~reserves increasing at a higher rate than capital costs for the three months ended March 31, ~~2018.~~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 compared to $10.1 million for~~2018. General and administrative expense per Mcfe was $0.79 in the three months ended March 31, ~~2017. General and administrative expense per Mcfe was~~2019 compared to $0.34 in the three months ended March 31, ~~2018 compared~~2018. The increase of $19.2 million and $0.45 per Mcfe was primarily related to ~~$0.39~~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, 2017. The decrease of $0.4 million during the three months ended March 31, 2018 when compared to three months ended March 31, 2017 was primarily due to reduced personnel costs compared to the prior year period. The decrease of $0.05 per Mcfe is due to fixed costs being spread across higher production as of March 31, 2018 as compared to March 31, 2017.2019. General and administrative expense ~~includes $2.0~~included $6.0 million and ~~$2.1~~$2.0 million of stock-based compensation expense for the three months ended March 31, 2019 and 2018, ~~and 2017,~~ respectively.

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, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,									Three Months Ended March 31,
	2018			2017			Change			2019		2018			Change
Other operating expenses (in thousands):
Brokered natural gas and marketing expense	$	48		$	2,460		$	(2,412	)	$	9,459	$	48		$	9,411
Exploration		15,278			11,581			3,697			16,789		15,278			1,511
Accretion of asset retirement obligations		155			124			31
(Gain) loss on sale of assets		(267	)		(5	)		(262	)		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 compared to $2.5 million for the three months ended March 31, 2017.~~2018. Brokered natural gas and marketing expenses relate to gas purchases ~~for brokered natural gas~~ that we buy and sell ~~that is~~ not ~~related~~relating to ~~our~~ production and firm transportation capacity that is marketed to third parties. The ~~decrease~~increase from ~~the prior year period to the current year period was due to increased utilization of our firm transportation capacity for operated production during~~ the three months ended March 31, 2018 ~~which resulted in a decrease~~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.~~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 compared to $11.6 million for the three months ended March 31, 2017.~~2018. The following table details our exploration-related expenses for the three months ended March 31, ~~2018~~2019 and ~~2017:~~2018:

	Three Months Ended March 31,							Three Months Ended March 31,
	2018		2017		Change			2019		2018		Change
Exploration expenses (in thousands):
Geological and geophysical	$	665	$	415	$	250		$	206	$	665	$	(459	)
Delay rentals		7,823		6,177		1,646			6,983		7,823		(840	)
Impairment of unproved properties		6,696		4,125		2,571			9,600		6,696		2,904
Dry hole and other		94		864		(770	)		—		94		(94	)
	$	15,278	$	11,581	$	3,697		$	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 compared to $6.2 million for the three months ended March 31, 2017.~~2018. The ~~increase~~decrease in delay rental expenses ~~relates~~related to the reduction of converting of future lump-sum extension payments into annual delay rentals during the three months ended March 31, ~~2018.~~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 compared to $4.1 million for the three months ended March 31, 2017.~~2018. The increase in impairment charges during the three months ended March 31, ~~2018 is~~2019 was the result of an increase in expected lease expirations due to ~~the reduction in~~ our planned future drilling ~~activity.~~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.

~~Accretion of asset retirement obligations~~ was $0.2 million for the three months ended March 31, 2018 compared to $0.1 million for three months ended March 31, 2017. The increase in accretion expense primarily relates to the asset retirement obligations associated with the increase in the number of our producing wells during the three months ended March 31, 2018.

(Gain) loss on sale of assets was ~~($0.3) million for the three months ended March 31, 2018 compared to~~ less than $0.1 million for the three months ended March 31, ~~2017. The increase is due~~2019 compared to ~~the sale of pipeline assets during~~($0.3) million for the three months ended March 31, 2018.

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, ~~compared to $25.1 million for the three months ended March 31, 2017,~~ primarily due to changes in commodity prices during each ~~year.~~period. Cash (payments) receipts ~~(payments)~~ were approximately ~~$0.1~~($3.2) million and ~~($4.0)~~$0.1 million for derivative instruments that settled during the three months ended March 31, 2019 and 2018, ~~and March 31, 2017,~~ respectively.

Interest expense, net was ~~$13.0~~$13.8 million for the three months ended March 31, ~~2018~~2019 compared to ~~$12.5~~$13.0 million for three months ended March 31, ~~2017. The increase in interest~~2018. Interest expense increased primarily ~~relates~~due to our increased borrowings under our revolving credit facility ~~utilization~~ during the three months ended March 31, ~~2018.~~2019.

Income tax benefit (expense) was not recognized for the three months ended March 31, ~~2018~~2019 and ~~2017~~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 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, ~~and~~ 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, ~~2018~~2019 Compared to the Three Months Ended March 31, ~~2017~~2018

Net cash provided by (used in) operations in the three months ended March 31, ~~2018~~2019 was ~~$3.3~~($8.9) million compared to ~~$28.4~~$3.3 million in the three months ended March 31, ~~2017.~~2018. The decrease in cash provided by ~~operators~~operating activities reflects ~~changes in~~ working capital changes, increased payments related to the BRMR Merger and ~~the~~ timing of cash receipts and disbursements ~~partially offset by higher revenues.~~during the year-over-year comparative periods.

Net cash used in investing activities in the three months ended March 31, ~~2018~~2019 was ~~$62.5~~$45.8 million compared to ~~$66.2~~$62.5 million in the three months ended March 31, ~~2017.~~2018.

Net cash provided by ~~(used in)~~ financing activities in the three months ended March 31, ~~2018~~2019 was ~~$63.8~~$56.4 million compared to ~~($3.0)~~$63.8 million in the three months ended March 31, ~~2017.~~2018.

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 ~~2018.~~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, ~~2018,~~2019, we were in compliance with all of our debt covenants under the ~~credit agreement~~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.

Long-term debt at March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, excluding discount, totaled ~~$510.5 million.~~$607.5 million and $542.5 million, respectively. Information related to our credit arrangements is described in “Note 8—10—Debt” to our consolidated financial statements and is incorporated herein by reference.

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, ~~2018,~~2019, we had entered into the following derivative contracts:

Description	Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)			Volume (MMBtu/d)		Production Period	Weighted Average Price ($/MMBtu)
Natural Gas Swaps:
		30,000	April 2018 – March 2019	$	2.90			90,000	April 2019 – December 2019	$	2.84
		20,000	April 2018 – December 2018	$	2.80			15,000	April 2019 – September 2019	$	2.79
		20,000	July 2018 – September 2018	$	2.81
		40,000	October 2018 – December 2019	$	2.80
		50,000	January 2019 – December 2019	$	2.87
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)		30,000	April 2018 – March 2019	$	3.00			77,500	April 2019 – December 2019	$	2.72
Ceiling sold price (call)		30,000	April 2018 – March 2019	$	3.40			77,500	April 2019 – December 2019	$	3.04
Floor sold price (put)		30,000	April 2018 – March 2019	$	2.50			77,500	April 2019 – December 2019	$	2.30
Floor purchase price (put)		40,000	April 2018 – December 2018	$	3.11
Floor purchase price (put)		60,000	April 2018 – December 2018	$	2.80			40,000	April 2019 – June 2019	$	2.65
Ceiling sold price (call)		100,000	April 2018 – December 2018	$	3.36			40,000	April 2019 – June 2019	$	2.84
Floor sold price (put)		100,000	April 2018 – December 2018	$	2.50			40,000	April 2019 – June 2019	$	2.30
Floor purchase price (put)		20,000	October 2018 – December 2019	$	2.75			70,000	January 2020 – June 2020	$	2.70
Ceiling sold price (call)		20,000	October 2018 – December 2019	$	3.10			70,000	January 2020 – June 2020	$	2.98
Floor sold price (put)		20,000	October 2018 – December 2019	$	2.30			70,000	January 2020 – June 2020	$	2.25
Floor purchase price (put)		57,500	January 2019 – December 2019	$	2.72			30,000	October 2019 – June 2020	$	2.90
Ceiling sold price (call)		57,500	January 2019 – December 2019	$	3.02			30,000	October 2019 – June 2020	$	3.15
Floor sold price (put)		57,500	January 2019 – December 2019	$	2.30			30,000	October 2019 – June 2020	$	2.50
Natural Gas Call/Put Options:
Call sold		40,000	April 2018 – December 2018	$	3.75			40,000	April 2019 – December 2019	$	3.44
Call sold		30,000	January 2019 – March 2019	$	3.50
Call sold		30,000	April 2019 – December 2019	$	3.00
Call sold		10,000	January 2019 – December 2019	$	4.75
Basis Swaps:
Appalachia - Dominion		12,500	April 2019 – October 2019	$	(0.52	)		12,500	April 2019 – October 2019	$	(0.52	)
Appalachia - Dominion		12,500	April 2020 – October 2020	$	(0.52	)		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	)

Description	Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)		Volume (Bbls/d)		Production Period	Weighted Average Price ($/Bbl)
Oil Swaps:
		1,000	July 2018 – March 2019	$	61.00		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)		4,000	April 2018 – December 2018	$	45.00		2,000	April 2019 – December 2019	$	50.00
Ceiling sold price (call)		4,000	April 2018 – December 2018	$	53.47		2,000	April 2019 – December 2019	$	60.56
Floor sold price (put)		4,000	April 2018 – December 2018	$	35.00		2,000	April 2019 – December 2019	$	40.00
Floor purchase price (put)		2,000	January 2019 – December 2019	$	50.00		2,000	January 2020 – June 2020	$	62.50
Ceiling sold price (call)		2,000	January 2019 – December 2019	$	60.56		2,000	January 2020 – June 2020	$	74.00
Floor sold price (put)		2,000	January 2019 – December 2019	$	40.00		2,000	January 2020 – June 2020	$	55.00

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, ~~Citibank, Goldman Sachs,~~J Aron, Morgan Stanley, Capital One N.A., BP Energy Company, ~~and~~ 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, ~~2018,~~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, ~~2018.~~2019. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by ~~$25.1~~$16.7 million. Similarly, a hypothetical 10 percent increase in future natural gas prices would decrease future earnings related to derivatives by ~~$27.2~~$18.2 million. A hypothetical 10 percent decrease in future oil prices would increase future earnings related to derivatives by ~~$9.7~~$7.6 million. Similarly, a hypothetical 10 percent increase in future oil prices would decrease future earnings related to derivatives by ~~$10.7~~$8.5 million.

Subsequent to March 31, ~~2018,~~2019, we entered into the following derivative instruments to mitigate our exposure to natural gas and oil prices:

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 ~~2018~~2019 of between approximately ~~$300~~$375 - ~~$320~~$400 million, allocated approximately ~~84%~~90% for drilling and completions activities ~~8% for midstream activities, 6%~~and approximately 10% for land activities and ~~2% for~~ other capital requirements. ~~Following the end of the first quarter, Eclipse reduced its 2018 capital expenditure budget to approximately $250 million due to the current negative outlook of natural gas prices.~~ The ~~revised 2018~~2019 capital budget is expected to be substantially funded through internally generated cash flows, ~~and~~ the Company’s current cash balance, and borrowings under the revolving credit ~~facility and/or other debt and equity offerings.~~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 ~~agreement~~facility and other factors.

As of March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, our total debt, excluding debt discount and issuance costs, and capitalization were as follows (in millions):

	March 31, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Senior unsecured notes	$	510.5	$	510.5	$	510.0	$	510.0
Revolving credit facility						97.5		32.5
Stockholders' equity		660.6		572.4		949.7		687.5
Total capitalization	$	1,171.1	$	1,082.9	$	1,557.2	$	1,230.0

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, ~~2018~~2019 and December 31, ~~2017,~~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, ~~2018~~2019 reflects accrued interest payable of ~~$10.4~~$10.9 million, compared to ~~$21.1~~$21.7 million as of December 31, ~~2017.~~2018.

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.

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.

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.

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:

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).

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.

At March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, we had ~~$510.5~~$510.0 million of senior unsecured notes outstanding, excluding discounts, which ~~bear~~bore interest at a fixed cash rate of 8.875% and iswas 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 8—10—Debt” to our consolidated financial statements and is incorporated herein by reference.

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.”

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 ~~2018~~2019 to continue to be a function of supply and demand. Further strengthening of commodity prices could stimulate demand for ancillary services causing ~~services~~service costs to increase. In the near term, the majority of our service costs are expected to remain flat in ~~2018~~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 ~~efficacies.~~efficiencies.

“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:

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,						Three Months Ended March 31,
$ thousands	2018			2017				2019		2018
Net income (loss)	$	(2,626	)	$	26,847
Depreciation, depletion and amortization		31,156			26,189
Net loss							$	(14,098	)	$	(2,626	)
Depreciation, depletion, amortization and accretion								29,897			31,311
Exploration expense		15,278			11,581			16,789			15,278
Stock-based compensation		1,981			2,081			6,001			1,981
Accretion of asset retirement obligations		155			124
(Gain) loss on sale of assets		(267	)		(5	)		2			(267	)
(Gain) loss on derivative instruments		4,215			(25,097	)
Loss on derivative instruments								4,931			4,215
Net cash receipts (payments) on settled derivatives		141			(3,989	)		(3,186	)		141
Interest expense, net		12,952			12,462			13,840			12,952
Other (income) expense		—			19
Merger-related expenses								14,583			—
Loss from discontinued operations								182			—
Adjusted EBITDAX	$	62,985		$	50,212		$	68,941		$	62,985

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.

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, ~~2017~~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.

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.

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 ~~75%~~82% of our December 31, ~~2017~~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 6—8—Derivative Instruments.”

Information related to our interest rates is described in “Note 8—10—Debt” to our consolidated financial statements and is incorporated herein by reference.

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.

WeBy using derivative instruments that are ~~exposed~~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 ~~the event of nonperformance~~derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by ~~counterparties.~~management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. ~~We have~~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 ~~experienced any issues~~available, a discount rate based on the applicable Reuters bond rating) at March 31, 2019 for each of ~~nonperformance by derivative counterparties.~~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, ~~2018,~~2019, we did not have past-due receivables from, or payables to, any of the counterparties to our derivative ~~contracts.~~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.

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.

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.

Information regarding the Company’s legal proceedings is set forth in “Note ~~13—~~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.

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in ~~“Risk~~“Item 1A. Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March ~~2, 2018,~~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.

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.

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.

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

~~2121 Old Gatesburg Rd,~~122 West John Carpenter Freeway, Suite ~~110~~300 ~~State College, PA~~Irving, TX	~~16803~~75039
(Address of principal executive offices)	(Zip code)

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

		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	2630
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3844
Item 4.	Controls and Procedures	3845

PART II - Other Information		4046
Item 1.	Legal Proceedings	4046
Item 1A.	Risk Factors	4046
Item 6.	Exhibits	4047

Index to Exhibits		4147
Signatures		4249

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

	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	)

(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

	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	)

	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

	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

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

	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

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

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 ~~Eclipse~~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 ~~June 24, 2014)~~March 6, 2019).

3.2		Second Amended and Restated Bylaws of ~~Eclipse~~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 ~~June 24, 2014)~~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		Stockholders Agreement, dated June 25, 2014, 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. and Eclipse Management, L.P. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 30, 2014).

~~4.2~~		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).

~~4.3~~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).

~~4.4~~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*†~~10.1		~~Eclipse Resources Corporation~~Third Amended and Restated ~~2014 Long-Term Incentive Plan,~~Credit Agreement, dated as of February ~~22, 2018.~~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.~~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.

May ~~4, 2018~~9, 2019		~~ECLIPSE~~MONTAGE RESOURCES CORPORATION (Registrant)

		/s/ ~~Benjamin W. Hulburt~~ John K. Reinhart
		~~Benjamin W. Hulburt,~~John K. Reinhart,
		~~Chairman,~~ President and Chief Executive Officer

		/s/ ~~Matthew R. DeNezza~~ Michael L. Hodges
		~~Matthew R. DeNezza,~~Michael L. Hodges,
		Executive Vice President and Chief Financial Officer

Large accelerated filer

Accelerated filer

Non-accelerated filer

☐ ~~(Do not check if a small reporting company)~~

~~Small~~Smaller reporting company

Emerging growth company