upl-10q_20190331.htm

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ☑ NO ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐ NO ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distributions of securities under a plan confirmed by a court. YES ☑ NO ☐

The number of shares, without par value, of Ultra Petroleum Corp., outstanding as of April 30, 2019 was 197,383,295.

	March 31,			December 31,
	2019			2018
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	10,469		$	17,014
Restricted cash		2,596			2,291
Oil and gas revenue receivable		86,763			133,042
Joint interest billing and other receivables, net		6,701			11,348
Derivative assets		10,985			23,374
Income tax receivable		—			6,431
Inventory		18,277			18,757
Other current assets		2,840			2,473
Total current assets		138,631			214,730
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,543,166			1,497,727
Property, plant and equipment, net		11,178			11,635
Long-term right-of-use assets		127,861			—
Other assets		13,532			9,196
Total assets	$	1,834,368		$	1,733,288
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	36,314		$	36,923
Accrued liabilities		62,999			58,574
Production taxes payable		84,108			58,365
Current portion of long-term debt		9,750			7,313
Interest payable		28,771			28,672
Lease liabilities		11,261			—
Derivative liabilities		38,483			62,350
Capital cost accrual		16,966			15,014
Total current liabilities		288,652			267,211
Long-term debt
Credit facility		38,000			104,000
Long-term debt		1,915,906			1,932,722
Add: Premium on exchange transactions		235,941			228,096
Less: Unamortized deferred financing costs and discount		(54,161	)		(56,650	)
Total long-term debt, net		2,135,686			2,208,168
Deferred gain on sale of liquids gathering system		—			94,636
Long-term lease liabilities		116,613			—
Other long-term obligations		207,420			211,895
Total liabilities		2,748,371			2,781,910
Commitments and contingencies (Note 9)
Shareholders' equity:
Common stock - no par value; authorized - 750,000,000; issued and outstanding - 197,383,295 at March 31, 2019 and December 31, 2018, respectively		2,138,570			2,137,443
Treasury stock		(49	)		(49	)
Retained loss		(3,052,524	)		(3,186,016	)
Total shareholders' deficit		(914,003	)		(1,048,622	)
Total liabilities and shareholders' equity	$	1,834,368		$	1,733,288

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

	For the Three Months Ended March 31,
	2019			2018
	(In thousands, except per share data)
Revenues:
Natural gas sales	$	245,989		$	181,462
Oil sales		23,465			41,284
Other revenues		2,007			2,628
Total operating revenues		271,461			225,374
Expenses:
Lease operating expenses		17,225			21,764
Facility lease expense		6,645			6,156
Production taxes		30,175			23,270
Gathering fees		19,880			23,055
Depletion, depreciation and amortization		51,653			50,540
General and administrative		7,052			12,688
Other expenses		684			213
Total operating expenses		133,314			137,686
Operating income		138,147			87,688
Other income (expense), net:
Interest expense		(33,327	)		(35,837	)
Loss on commodity derivatives		(64,339	)		(6,530	)
Deferred gain on sale of liquids gathering system		—			2,638
Other income (expense), net		166			(32	)
Total other (expense) income, net		(97,500	)		(39,761	)
Income before income tax (benefit) provision		40,647			47,927
Income tax (benefit) provision		(27	)		434
Net income	$	40,674		$	47,493
Basic earnings per share:
Net income per common share - basic	$	0.21		$	0.24
Fully diluted earnings per share:
Net income per common share - fully diluted	$	0.21		$	0.24
Weighted average common shares outstanding - basic		197,383			196,550
Weighted average common shares outstanding - fully diluted		197,801			196,550

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

	Common Stock
	Shares Issued and Outstanding		Amount		Retained (Loss) Earnings			Treasury Stock			Total Shareholders' (Deficit) Equity
Balances at January 1, 2019		197,383	$	2,137,443	$	(3,186,016	)	$	(49	)	$	(1,048,622	)
Fair value of employee stock plan grants		—		1,127		—			—			1,127
Net income		—		—		40,674			—			40,674
Initial adoption of ASC 842		—		—		92,818			—			92,818
Balances at March 31, 2019		197,383		2,138,570		(3,052,524	)		(49	)		(914,003	)

	Common Stock
	Shares Issued and Outstanding			Amount		Retained (Loss) Earnings			Treasury Stock			Total Shareholders' (Deficit) Equity
Balances at January 1, 2018		196,347		$	2,116,018	$	(3,270,605	)	$	(49	)	$	(1,154,636	)
Employee stock plan grants		1,226			—		—			—			—
Net share settlements		(519	)		—		(2,061	)		—			(2,061	)
Fair value of employee stock plan grants		—			10,709		—			—			10,709
Initial adoption of ASC 606		—			—		1,761			—			1,761
Net income		—			—		47,493			—			47,493
Balances at March 31, 2018		197,054		$	2,126,727	$	(3,223,412	)	$	(49	)	$	(1,096,734	)

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

	Three Months Ended March 31,
	2019			2018
	(In thousands)
Operating activities - cash provided by (used in):
Net income for the period	$	40,674		$	47,493
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		51,653			50,540
Unrealized loss (gain) on commodity derivatives		(14,292	)		7,606
Deferred gain on sale of liquids gathering system		—			(2,638	)
Stock compensation		841			8,810
Payable-in-Kind (“PIK”) interest payable		3,183			—
Amortization of premium on debt exchange		(9,716	)		—
Amortization of deferred financing costs		3,123			2,727
Other		582			209
Net changes in operating assets and liabilities:
Accounts receivable		50,243			12,561
Other current assets		(307	)		2,485
Other non-current assets		30			30
Accounts payable		(359	)		(5,263	)
Accrued liabilities		4,425			(7,486	)
Production taxes payable		25,743			23,622
Interest payable		99			17,172
Other long-term obligations		(11,663	)		(12,708	)
Income taxes payable/receivable		6,431			6,836
Net cash provided by operating activities		150,690			151,996
Investing Activities - cash provided by (used in):
Oil and gas property expenditures		(92,352	)		(134,500	)
Change in capital cost accrual and accounts payable		1,702			(8,079	)
Inventory		419			(5,074	)
Purchase of capital assets		(211	)		(1,196	)
Net cash used in investing activities		(90,442	)		(148,849	)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement		232,000			191,000
Payments under Credit Agreement		(298,000	)		(191,000	)
Deferred financing costs		(488	)		—
Repurchased shares/net share settlements		—			(2,061	)
Net cash used in financing activities		(66,488	)		(2,061	)
(Decrease) increase in cash during the period		(6,240	)		1,086
Cash, cash equivalents, and restricted cash, beginning of period		19,305			18,269
Cash, cash equivalents and restricted cash, end of period	$	13,065		$	19,355

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

All amounts in this Quarterly Report on Form 10-Q are expressed in thousands of U.S. dollars (except per share data) unless otherwise noted.

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, “us”) is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of Wyoming.

In December 2018, the Company exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022 Notes”) and (ii) $275 million aggregate principal amount, or 55.0%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022 Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of Ultra Petroleum Corp., for (a) $545.0 million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “Second Lien Notes”), and (b) an aggregate of 10,919,499 new $0.01 warrants of Ultra Petroleum Corp. entitling the holder thereof to purchase one common share of Ultra Petroleum Corp. (each a “Warrant” and collectively, the “Warrants”) (such transaction, the “December Exchange Transaction”).

In January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes in a series of follow-on debt exchange transactions (such transactions, the “Follow-on Exchange Transactions” and, together with the December Exchange Transaction, the “Exchange Transactions”).

All Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. Refer to Note 4 for additional details and the accounting treatment on the Exchange Transactions.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

The condensed consolidated balance sheet at December 31, 2018, has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements.

For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2018.

Basis of Presentation and Principles of Consolidation: The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All inter-company transactions and balances have been eliminated.

Cash and Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash: Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute.

The Company follows Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash and reports the change in cash, cash equivalents, and restricted cash in total on the Condensed Consolidated Statements of Cash Flows.

Accounts Receivable, net: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. As of March 31, 2019, the allowance for uncollectible accounts was $9.0 million. The carrying amount of the Company’s accounts receivable approximates fair value due to the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of successful, as well as unsuccessful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion.

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs, as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the three months ended March 31, 2019 or 2018.

Inventories: Inventory primarily includes $17.2 million in pipe and production equipment that will be utilized during the 2019-2020 drilling programs and $1.1 million in crude oil inventory as of March 31, 2019. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost.

Deferred Financing Costs (“DFC”): The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs for its borrowings under the Term Loan Agreement (as defined below), Second Lien Notes and Unsecured Notes and includes the costs for issuing debt including issuance discounts, as a direct deduction from the carrying amount of the related debt liability.

Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements for its Revolving Credit Facility (as defined below) and includes the costs related to the issuance of the Revolving Credit Facility in Other assets on the Condensed Consolidated Balance Sheets.

Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Condensed Consolidated Balance Sheets and records the changes in the fair value of its commodity derivatives in the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 7 for additional details.

Income Taxes: Income taxes are accounted for under the asset and liability method. 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 basis and operating loss and tax credit carryforwards. 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. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

Warrants: In December 2018, the Company issued 10,919,499 Warrants. The Warrants are initially exercisable for one common share of Ultra Petroleum Corp., no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the common shares is at least $2.50 per common share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase common shares will terminate. Under the guidance in FASB ASC 815, the Warrants do not meet the definition of a derivative. The Warrants are classified as equity and recorded at fair value as of the date of issuance on the Company’s Consolidated Balance Sheets and no further adjustments to their valuation are made.

Earnings Per Share: Basic earnings per share is computed by dividing net earnings attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are not included in the diluted earnings per share denominator until the performance or market criteria are met. Additionally, the Warrants issued in connection with the Exchange Transaction are not included in the diluted earnings per share denominator using the treasury stock method as the Trading Price Condition on the Warrants exceeded the average market price. For the three months ended March 31, 2019 and 2018, the Company had 19.2 million and 2.8 million, respectively, of contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met.

The following table provides a reconciliation of components of basic and diluted net income per common share:

Use of Estimates: Preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Beginning as of January 1, 2019, the Company revised its estimate of administrative costs associated with its operations and classified as Lease operating expenses on the consolidated statement of operations. During 2018 and 2019, the Company has taken steps to drive efficiencies through its operations which resulted in its overhead costs being less than the inflation adjustment to the overhead rates set by the Council of Petroleum Accountants Societies (“COPAS”). Accordingly, the Company reduced the amount of costs categorized as Lease operating expenses, with General and administrative expenses absorbing a larger portion of the total costs.

Accounting for Share-Based Compensation: The Company measures and recognizes compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.

Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 8 for additional details.

Asset Retirement Obligation: The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Condensed Consolidated Balance Sheets.

Leases: The Company adopted ASU 2016-02, Leases, and all applicable amendments as of January 1, 2019. The Company elected to apply the new standard to all leases existing at the date of initial application. Consequently, historical financial information will not be updated, and the disclosures required under the new standard will not be provided for dates and periods prior to January 1, 2019.

The Company determines if an arrangement is a lease at inception. Operating leases are included in long-term right-of-use (“ROU”) assets, and long-term lease liabilities on our condensed consolidated balance sheets. ROU assets represent the Company’s right to use of an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives. The Company’s lease terms may include options to extend or terminate the lease when the Company is reasonably certain that it will exercise that option.

Lease expense for lease payments is recognized on a straight-line basis over the lease term. The ROU assets are tested for impairment in accordance with ASC 360.

The Company has lease agreements with lease and non-lease components, which are accounted for as a single lease component under the practical expedient provisions of the standard. Additionally, for certain leases, the Company applies a portfolio approach to effectively account for the operating lease ROU assets and liabilities. The portfolio approach was used to assess and determine the incremental borrowing rate with information available at adoption date.

The Company has lease agreements with terms less than one year. For the qualifying short-term leases, the Company elected the short-term lease recognition exemption in which the Company will not recognize ROU assets or lease liabilities, including the ROU assets or lease liabilities for existing short-term leases of those assets in upon adoption.

Additionally, the Company had existing lease agreements with easements in which the Company elected the practical expedient. All new and modified lease agreements with easements completed after the adoption date will be evaluated under the ASC 842 (as defined below).

Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments.

Other Revenues: Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed.

Capital Cost Accrual: The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

Reclassifications: Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. The Company adopted ASC 842 and applicable amendments on January 1, 2019 using the modified retrospective approach. The Company elected certain practical expedients and established internal controls and key system functionality to enable the preparation of financial information on adoption.

The adoption of the standard had an effect on the Company’s condensed consolidated balance sheets but did not have an effect on the Company’s condensed consolidated income statements. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 9 for additional discussion.

The following table reflects the cumulative impact of the adoption of ASC 842 using the modified retrospective approach.

	December 31, 2018 as reported			Impact of ASC 842			January 1, 2019 as adjusted
	(Amounts in thousands)
Long-term right-of-use assets	$	—		$	130,649		$	130,649
Total assets		1,733,288			130,649			1,863,937

Lease liabilities (current)		—			11,141			11,141
Deferred gain on sale of liquids gathering system		94,636			(94,636	)		—
Long-term lease liabilities		—			121,326			121,326
Total liabilities		2,781,910			37,831			2,819,741
Retained earnings (loss)		(3,186,016	)		92,818			(3,093,198	)
Total stockholders' equity (deficit)		(1,048,622	)		92,818			(955,804	)
Total liabilities and stockholders' equity (deficit)		1,733,288			130,649			1,863,937

Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement. The amendments in this update modify the disclosure requirements on fair value measurements in Topic 820. The ASU is effective for public companies for fiscal years beginning after December 15, 2019, and interim periods therein. Early adoption is permitted. The Company is currently assessing the impact of this standard on its consolidated financial statements.

Financial Instruments. In June 2016, The FASB issued ASU 2016-13, "Financial Instruments—Credit Losses (Topic 326)", Measurement of Credit Losses on Financial Instruments ("ASU 2016-13"). This ASU changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. Early adoption is permitted for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are currently assessing the impact ASU 2016-13 will have on our Consolidated Financial Statements.

Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies.

We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations.

Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the natural gas production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production.

We sell oil production at (a) a lease automatic custody transfer meter, (b) a tank battery, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations.

Our working interest partners are considered the principal for their working interest shares. They have the option to take in kind their volumes. The Company may act as an agent and market the other partners’ share of the oil production. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production.

Our other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred upon completion of the processing service. The Company is considered the principal, and revenue is recognized at the point in time that the control is transferred.

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

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

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

The following tables summarize the Company’s debt instruments as of March 31, 2019 and December 31, 2018:

	March 31, 2019
	Principal repayment obligation (1)			Unamortized DFC and discounts (2)			Unamortized premium		Carrying value
Credit Facility, secured, due January 2022	$	38,000		$	—		$	—	$	38,000
Term Loan, secured, due April 2024		975,068			(25,807	)		—		949,261
Second Lien Notes, secured, due July 2024		575,149			—			235,941		811,090
6.875% Notes, unsecured, due April 2022		150,439			(14,189	)		—		136,250
7.125% Notes, unsecured, due April 2025		225,000			(14,165	)		—		210,835
Total debt	$	1,963,656		$	(54,161	)	$	235,941	$	2,145,436
Less: Current maturities		(9,750	)		—			—		(9,750	)
Total long-term debt, net	$	1,953,906		$	(54,161	)	$	235,941	$	2,135,686

	December 31, 2018
	Principal repayment obligation			Unamortized DFC and discounts (1)			Unamortized premium		Carrying value
Credit Facility, secured, due January 2022	$	104,000		$	—		$	—	$	104,000
Term Loan, secured, due April 2024		975,000			(26,874	)		—		948,126
Second Lien Notes, secured, due July 2024		545,000			—			228,096		773,096
6.875% Notes, unsecured, due April 2022		195,035			(15,168	)		—		179,867
7.125% Notes, unsecured, due April 2025		225,000			(14,608	)		—		210,392
Total debt	$	2,044,035		$	(56,650	)	$	228,096	$	2,215,481
Less: Current maturities		(7,313	)		—			—		(7,313	)
Total long-term debt, net	$	2,036,722		$	(56,650	)	$	228,096	$	2,208,168

Credit Agreement. In April 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “RBL Lenders”), providing for a revolving credit facility (the “Revolving Credit Facility”) subject to a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (as defined below). The semi-annual redetermination in February 2019 resulted in a borrowing base commitment of $1.3 billion, with $975.0 million allocated to the Company’s Term Loan (as defined below) and $325.0 million allocated to the Revolving Credit Facility.

In December 2018, Ultra Resources and the parent guarantors entered into the Third Amendment to the Credit Agreement (the “Third Amendment to Credit Agreement”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Third Amendment to Credit Agreement, the parties agreed, among other things, to amend the Credit Agreement to permit the issuance of the Second Lien Notes and the December Exchange Transaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to:

On February 14, 2019, Ultra Resources entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment to Credit Agreement”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Fourth Amendment to Credit Agreement, the borrowing base was reaffirmed at $1.3 billion. Given the Revolving Credit Agreement was amended in February 2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is in October 2019.

The Fourth Amendment to Credit Agreement also revised certain covenants and other provisions of the Credit Agreement, including, but not limited to:

At March 31, 2019, Ultra Resources had $38.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022.

The Revolving Credit Facility requires Ultra Resources to maintain (i) a minimum interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, of a minimum of 1.00 to 1.00; and (iii) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. In addition, as of the last day of (i) each fiscal quarter ending during the period from March 31, 2019 through June 30, 2019, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.75 to 1.00, (ii) each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.90 to 1.0, (iii) the fiscal quarter ending September 30, 2020, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.50 to 1.0, and (iv) the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter, Ultra Resources will not permit the consolidated net leverage ratio to exceed 4.25

to 1.0. At March 31, 2019, Ultra Resources’ consolidated net leverage ratio and interest coverage ratio were 4.11 to 1.00 and 3.26 to 1.00, respectively, and Ultra Resources was in compliance with each of its debt covenants under the Credit Agreement.

Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its proved developed producing (“PDP”) reserves; and during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projected volumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.

Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees.

The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements and other customary covenants.

The Revolving Credit Facility contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Revolving Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Revolving Credit Facility and any outstanding unfunded commitments may be terminated.

Term Loan. In April 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement (the “Term Loan Agreement”) with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent (the “Term Loan Administrative Agent”), and the other lenders party thereto (collectively, the “Term Loan Lenders”). As part of the Term Loan Agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in the deferred financing costs noted above.

In December 2018, Ultra Resources and the parent guarantors entered into the First Amendment to the Term Loan Agreement (the “Term Loan Amendment”) with the Term Loan Administrative Agent and the Term Loan Lenders party thereto. Pursuant to the Term Loan Amendment, the parties agreed, among other things, to amend the Term Loan Agreement to permit the issuance of the Second Lien Notes and the December Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payable in cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to:

At March 31, 2019, Ultra Resources had $975.1 million in outstanding borrowings under the Term Loan Agreement, including PIK interest and current maturities.

Borrowings under the Term Loan Agreement bear interest either at a rate equal to (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable-in-kind (“PIK”) upon election by Ultra Resources. Beginning in March 2019, the Company has elected the PIK option and management expects to continue this practice into the future. The borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. Borrowings under the Term Loan Agreement matures on April 12, 2024.

Borrowings under the Term Loan Agreement are subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the borrowings under the Term Loan Agreement.

The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At March 31, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Second Lien Notes. On December 21, 2018, in connection with the consummation of the December Exchange Transaction, Ultra Resources issued $545.0 million aggregate principal amount of Second Lien Notes and entered into an Indenture, dated as of December 21, 2018 (the “Second Lien Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral agent.

During January and February 2019, certain holders of the 2022 Notes exchanged approximately $44.6 million aggregate principal amount of 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes in a series of Follow-on Exchange Transactions. All Second Lien Notes were issued pursuant to the Second Lien Notes Indenture. As of March 31, 2019, Ultra Resources had approximately $575.1 million in outstanding borrowings under the Second Lien Notes Indenture, including PIK interest.

The Second Lien Notes will mature on July 12, 2024. Interest on the Second Lien Notes will accrue at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing on July 15, 2019. The Company has accounted for such PIK interest as an increase to the principal outstanding.

The Second Lien Notes are senior secured obligations of Ultra Resources and rank senior in right of payment to all of its existing and future unsecured senior debt, to the extent of the value of the collateral pledged under the Second Lien Notes Indenture and related collateral arrangements, senior in right of payment to all of its future subordinated debt, and junior in right of payment to all of its existing and future secured debt of senior priority, to the extent of the value of the collateral pledged thereby. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company. Payment by Ultra Resources of all amounts due on or in respect of the Second Lien Notes and the performance of Ultra Resources under the Indenture are initially guaranteed by the Company.

thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest (including PIK interest), if any, to the redemption date. In addition, on or after December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to 105.50% for the twelve-month period beginning on December 21, 2021, 102.75% for the twelve-month period beginning December 21, 2022, and 100.00% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plus accrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes.

If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second Lien Notes may require the Issuer to repurchase all or a portion of its Second Lien Notes for cash at a price equal to 101% of the aggregate principal amount of such Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase.

The Second Lien Notes Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur or redeem indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) pay cash dividends, (vi) change the nature of its business or operations, (vii) make certain types of investments, (ix) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (x) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Second Lien Notes Indenture); and (xi) create unrestricted and foreign subsidiaries. The covenants in the Second Lien Notes Indenture are subject to important exceptions and qualifications. Subject to conditions, the Second Lien Notes Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Second Lien Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc.

The Second Lien Notes Indenture contains customary events of default. Unless otherwise noted in the Second Lien Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Second Lien Notes, by notice to the Company and the Trustee, may declare the Second Lien Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) or group of Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Second Lien Notes to become due and payable.

In conjunction with the Exchange Transactions, the portion of the Unsecured Notes which were exchanged for Second Lien Notes was accounted for as a troubled debt restructuring. The Company evaluated the quantitative and qualitative factors in the accounting literature and concluded that concessions were granted as the future undiscounted cash flows of the Second Lien Notes was greater than the net carrying value of the senior Unsecured Notes. No gain is recognized, and an effective interest rate is established based on the carrying value of the Second Lien Notes and revised cash flows. The amount of extinguished debt will be amortized over the remaining life of the Second Lien Notes using the effective interest method and recognized as a reduction to interest expense. As a result, our reported interest expense will be significantly less than the contractual cash interest payments throughout the term of the Second Lien Notes.

The exchanged debt resulted in a calculation of cancellation of debt income for tax purposes. Our current tax attributes are expected to offset any potential cash tax impacts from the Exchange Transactions. For additional details on the Company’s income taxes, refer to Note 6.

Unsecured Notes. In April 2017, Ultra Resources issued $700.0 million of its 2022 Notes and $500.0 million of its 2025 Notes and entered into an Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as Trustee. The Unsecured Notes are treated as a single class of securities for most purposes under the Unsecured Notes Indenture.

In December 2018, the Company completed the December Exchange Transaction, pursuant to which the exchanging noteholders exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the issued and outstanding 2022 Notes and (ii) $275 million aggregate principal amount, or 55.0%, of the issued and outstanding 2025 Notes for (a) $545.0 million aggregate principal amount of Second Lien Notes and (b) an aggregate of 10,919,499 new warrants of Ultra Petroleum Corp. each entitling the holder thereof to purchase one common share of Ultra Petroleum Corp.

In January and February 2019, the Company completed a series of Follow-on Exchange Transactions, pursuant to which the exchanging noteholders exchanged approximately $44.6 million aggregate principal amount of the issued and outstanding 2022 Notes for approximately $27.0 million aggregate principal amount of Second Lien Notes.

At March 31, 2019, the aggregate principal amounts outstanding under the Unsecured Notes were approximately $150.4 million with respect to the 2022 Notes and $225.0 million with respect to the 2025 Notes.

The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity.

In December 2018, Ultra Resources, the Company and its other subsidiaries, as guarantors, and the Trustee entered into the First Supplemental Indenture to the Unsecured Indenture (the “Supplemental Indenture”). Pursuant to the Supplemental Indenture, the parties amended the Unsecured Indenture to, among other things, eliminate or amend substantially all of the restrictive covenants contained in the Unsecured Indenture, other than those relating to the payment of principal and interest. The Supplemental Indenture is binding on all Unsecured Notes that remain outstanding.

The Unsecured Notes Indenture contains customary events of default. Unless otherwise noted in the Unsecured Notes Indenture, upon a continuing event of default, the Trustee, by notice to the Company, or the holders of at least 25% in principal amount of the then outstanding Unsecured Notes, by notice to the Company and the Trustee, may, declare the Unsecured Notes immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Unsecured Notes Indenture) or group of Restricted Subsidiaries (as defined in the Unsecured Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Unsecured Notes to become due and payable.

2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established by our board of directors (the “Board”) pursuant to which 7.5% of the equity in the Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, and other employees of the Company (the “Reserve”). During 2017, management incentive plan grants (the “Initial MIP Grants”) were made to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, such Initial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time.

In June 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of the Ultra Petroleum Corp. 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends and restates the 2017 Stock Incentive Plan to, among other things:

In July 2018, the Company modified its incentive plan and recipients of the Initial MIP Grants were offered an opportunity to exchange the unvested portion of their Initial MIP Grants for new equity awards of time-based restricted stock units (the “2018 RSUs”) effective July 31, 2018 on a one-for-one basis. All 2018 RSUs are time-based awards and vest in equal tranches on May 25, 2019, May 25, 2020, and May 25, 2021. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation (“ASC 718”), the cancellation of an outstanding award of stock-based compensation followed by the issuance of a replacement award is treated as a modification of the original award. The equity award cancellations and subsequent new grants by the Company were considered Type I, probable-to-probable modification in 2018. This type represents modifications where the award was likely to vest prior to modification and is still likely to vest after modification. For these types of modifications, the fair value of the award is assessed both prior to modification and after modification. If the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period.

In March 2019, additional Initial MIP Grants were exchanged for new equity awards of time-based and performance-based restricted stock units. The Company evaluated the cancellation of an outstanding award of stock-based compensation followed by the issuance of a replacement award under ASC 718. For this modification, the fair value of the award is assessed both prior to modification and after modification. Per ASC 718, if the fair value after modification exceeds the fair value prior to modification, incremental expense is generated and recognized over the remaining vesting period.

Long Term Incentive Awards. In 2018 and March 2019, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The awards cover a performance period of three years and includes time-based and performance-based measures established by the Committee at the beginning of the three-year period.

Market-Based Condition Awards. When vesting of an award of stock-based compensation is dependent, at least in part, on the value of a company’s total equity, for purposes of FASB ASC 718, the award is considered to be subject to a “market condition”. Because the Company’s total equity value is a component of its enterprise value, the awards based on enterprise value are considered to be subject to a market condition. Unlike the valuation of an award that is subject to a service condition (i.e., time vested awards) or a performance condition that is not related to stock price, FASB ASC 718 requires the impact of the market condition to be considered when estimating the fair value of the award. As a result, we have used a Monte Carlo simulation model to estimate the fair value of the awards that include a market condition.

FASB ASC 718 requires the expense for an award of stock-based compensation that is subject to a market condition that can be attained at any point during the performance period to be recognized over the shorter of (a) the period between the date of grant and the date the market condition is attained, and (b) the award’s derived service period. For purposes of FASB ASC 718, the derived service period represents the duration of the median of the distribution of share price paths on which the market condition is satisfied. That median is the middle share price path (the midpoint of the distribution of paths) on which the market condition is satisfied. The

duration is the period of time from the service inception date to the expected date of market condition satisfaction. Compensation expense is recognized regardless of whether the market condition is actually satisfied.

Expense. For the three months ended March 31, 2019, the Company recognized $0.8 million in pre-tax compensation expense, which is included within General and administrative expenses on the Condensed Consolidated Statement of Operations. During the three months ended March 31, 2018, the Company recognized $8.8 million in pre-tax compensation expense, of which $8.6 million related to the Initial MIP Grants.

The Company’s overall effective tax rate on pre-tax income was different than the statutory rate of 21% due primarily to adjustments to the valuation allowances.

The Company has recorded a valuation allowance against all deferred tax assets as of March 31, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. As a result of the Tax Act, further clarifications and new regulations to the Tax Act continue to be issued at times. The Company will continue to monitor these new regulations and analyze their applicability and impact on the Company.

Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. The prices we receive for our 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.

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s operations and capital investment program. These types of instruments may include fixed price swaps, costless collars, deferred premium puts or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

The Company’s Revolving Credit Facility requires the Company to hedge 65% of forecast proved producing natural gas production, based on its most recent reserve report for 18 months from the end of the given quarter. This requirement is in effect through September 29, 2019. After that time, the requirement decreases to 50% of the estimated proved producing forecast for natural gas through March 30, 2020. This means the Company may unwind hedges beginning September 30, 2019 at its discretion providing the Company remains hedged at the 50% level for natural gas. Additionally, the Revolving Credit Facility limits the amount of hedging to 85% of forecast production for all products within a given quarter.

Fair Value of Commodity Derivatives: FASB ASC 815 requires that all derivatives be recognized on the Condensed Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Condensed Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Condensed Consolidated Statements of Cash Flows.

Commodity Derivative Contracts: At March 31, 2019, the Company had the following open commodity derivative contracts to manage commodity price risks. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable

price to the counterparty. For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period. For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below the floor price on a notional quantity. For deferred premium puts, the Company pays the deferred premium in the month of settlement. To the extent the market price is below the put price, the counterparty owes the Company the difference between the market price and put price in the period of settlement. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties. Refer to Note 8 for more information regarding the Company’s derivative instruments.

Type/Year	Index	Total Volumes		Weighted Average Price per Unit		Fair Value - March 31, 2019
		(in millions)				Asset (Liability)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2019 (April through December)	NYMEX-Henry Hub		137.8	$	2.77	$	(2,079	)
2020	NYMEX-Henry Hub		24.6		2.78		(5,439	)

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2019 (April through December)	NW Rockies Basis Swap		90.2	$	0.58	$	(18,734	)
2020	NW Rockies Basis Swap		7.7		0.15		770

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2019 (April through December)	NYMEX-WTI		1.0	$	58.64	$	(1,680	)
2020	NYMEX-WTI		0.1		60.05		51

Type/Year	Index	Total Volumes		Weighted Average Floor Price ($/MMBTU)		Weighted Average Ceiling Price ($/MMBTU)		Fair Value - March 31, 2019
		(in millions)						Asset (Liability)
Natural gas collars		(Mmbtu)
2019 (April through December)	NYMEX		2.8	$	2.85	$	3.13	$	264
2020	NYMEX		49.4	$	2.51	$	2.97	$	(1,298	)

Natural gas deferred premium put options		(Mmbtu)
2020	NYMEX		25.1	$	2.41	N/A		$	(394	)

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018:

As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three-level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

The valuation assumptions the Company has used to measure the fair value of its commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	10,985	$	—	$	10,985
Long-term derivative asset (1)		—		5,715		—		5,715
Total derivative instruments	$	—	$	16,700	$	—	$	16,700
Liabilities:
Current derivative liability	$	—	$	38,483	$	—	$	38,483
Long-term derivative liability (2)		—		6,756		—		6,756
Total derivative instruments	$	—	$	45,239	$	—	$	45,239

The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk. Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract. In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties. In addition, each of our current counterparties are lenders under our Revolving Credit Facility. We believe that all of our counterparties are of substantial credit quality. Other than as provided in our Revolving Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of March 31, 2019, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts. Refer to Note 7 for additional details on our derivative financial instruments.

The Company uses fair value to determine the value of its asset retirement obligations. The inputs used to determine such fair value under the expected present value technique are primarily based upon internal estimates prepared by reservoir engineers for costs of dismantlement, removal, site reclamation and similar activities associated with the Company’s oil and gas properties and would be classified Level 3 inputs.

The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents,

restricted cash, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The Company uses available market data and valuation methodologies to estimate the fair value of its debt and the fair values presented in the tables below reflect original maturity dates for each of the debt instruments. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s consolidated financial position, results of operations or cash flows.

	March 31, 2019				December 31, 2018
	Principal		Estimated		Principal		Estimated
	repayment obligation		Fair Value		repayment obligation		Fair Value
Credit Facility, secured, due January 2022	$	38,000	$	38,000	$	104,000	$	104,000
Term Loan, secured, due April 2024		975,068		840,996		975,000		858,000
Second Lien Notes, secured, due July 2024		575,149		342,616		545,000		395,125
6.875% Notes, unsecured, due April 2022		150,439		50,021		195,035		68,262
7.125% Notes, unsecured, due April 2025		225,000		49,500		225,000		69,750
Total debt	$	1,963,656	$	1,321,133	$	2,044,035	$	1,495,137

The Company has operating leases for corporate offices, drilling rigs, the Company’s liquids gathering system, and certain equipment. The leases have remaining lease terms of one year to nine years. The Company does not include renewal options in the lease term for calculating the lease liability unless it is reasonably certain that it will exercise the option or the lessor has the sole ability to exercise the option.

The following table provides supplemental balance sheet information related to the Company’s operating leases:

The following table provides supplemental cash flow information related to the Company’s operating leases:

The following table summarizes the fixed, future minimum rental payments, excluding variable costs, which are discounted by the Company’s incremental borrowing rates to calculate the lease liabilities for the Company’s operating leases:

On April 29, 2016, the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the U.S. Code in the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.). On March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”) and on April 12, 2017, we emerged from bankruptcy.

The Plan provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. As noted in this Quarterly Report on Form 10-Q, the claims resolution process associated with our chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time.

Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest dates, unpaid postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Company’s emergence from bankruptcy, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the debt agreements.

On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, the Company distributed $399.0 million from a $400.0 million reserve fund set up in connection with our emergence from chapter 11 proceedings to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims described above and $175.2 million representing postpetition interest at the default rate. The Company appealed the court order denying its objections to these claims to the U.S. Court of Appeals for the Fifth Circuit (the “Appellate Court”).

During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company.

On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court denying the Company’s objection to the asserted make-whole and post-petition interest claims and remanding the matter and those determinations to the Bankruptcy Court for further reconsideration. As of March 31, 2019, there were approximately $260 million of claims subject to the Appellate Court decision. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc. It is not possible to determine the ultimate disposition of these matters at this time.

On April 19, 2016, the Company received a preliminary determination notice from the U.S. Department of the Interior’s Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under federal oil and gas leases. ONRR also filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims related to these matters. We disputed the preliminary determination and the proof of claim. We have notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice, and we continue to be in discussions with ONRR related to these matters. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, and we cannot reasonably estimate the potential impact of these claims. We are defending these cases vigorously, and we expect these claims to be resolved in our chapter 11 proceedings. In addition, we are currently involved in various routine disputes and allegations incidental to our business operations. While it is not possible to determine the ultimate disposition of these matters, we believe the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on our financial position or results of operations.

The Company has evaluated the period subsequent to March 31, 2019 for material events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the Company’s condensed consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995. Except for statements of historical facts, all statements included in this document, including without limitation, statements in Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding the Company’s financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the Company assure adequate funding will be available to execute the Company’s planned future capital program.

Other risks and uncertainties include, but are not limited to, the Company’s ability to decrease its leverage or fixed costs, increased competition, the timing and extent of changes in prices for oil and gas, particularly in the areas where we own properties, conduct operations, and market our production, as well as the timing and extent of our success in discovering, developing, producing and estimating oil and gas reserves, our ability to successfully monetize the properties we are marketing, weather and government regulation, and the availability of oil field services, personnel and equipment. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 for additional risks related to the Company’s business.

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, “us”) is an independent exploration and production company focused on developing and producing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of southwest Wyoming. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.

The Company conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience. Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations or capital investment program.

The Company currently generates its revenue, earnings and cash flow from the production and sales of natural gas and condensate from its properties in southwest Wyoming.

Total production for the quarter ended March 31, 2019 was 59.6 Bcf of natural gas and 436.7 MBbl of crude oil and condensate, for a total of 62.2 Bcfe of production. The quarterly production was derived from producing wells in place as of the beginning of 2019 and the production of new wells turned to sales in the first quarter under the Company’s three-rig operated drilling program. On a per unit basis, the average realized prices for the Company in the quarter ended March 31, 2019 and 2018, was $4.33 per Mcfe and $3.08 per Mcfe, respectively.

The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and this volatility could be detrimental to the Company’s financial performance. As a result, and from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements, costless collars, and/or deferred premium puts. The Company also enters into short-term fixed price forward physical delivery contracts for natural gas and oil from time-to-time. The Company is currently required under its Revolving Credit Facility to enter into derivative commodity contracts for a minimum of 65% of its forecast proven producing natural gas reserves for the ensuing 18-month period. The Company has also begun to utilize more costless collars and is now utilizing deferred put contracts, with low premium costs, to provide a degree of floor price protection and allow the Company to participate in more upward price exposure.

The average price realization for the Company’s natural gas during the three months ended March 31, 2019 was $2.77 per Mcf, including realized gains and losses on commodity derivatives settled in the period. The average price realization for the Company’s natural gas during the three months ended March 31, 2019, excluding realized gains and losses on commodity derivatives, was $4.13 per Mcf. The realized natural gas prices were strong in the first quarter of 2019, as compared to the preceding 12-month average based on weather-related demand and tightness in the transportation markets in the western United States. The Company benefited from this upward pricing on its unhedged production volumes.

The average price realization for the Company’s crude oil and condensate during the three months ended March 31, 2019 was $59.58 per barrel, including realized gains and losses on commodity derivatives. The average price realization for the Company’s crude oil and condensate during the three months ended March 31, 2019, excluding realized gains and losses on commodity derivatives, was $53.70 per barrel.

The Company has operated three rigs in the Pinedale field with a primary focus of planned activities on vertical wells. The Company has also participated in wells drilled by another operator in the Pinedale field during this period. The total capital investment in oil and gas properties was $92.4 million for the quarter ended March 31, 2019. During the quarter ended March 31, 2019, there were 27 gross (26.1 net) vertical wells and 1 gross (0.9 net) horizontal well turned to sales, together with 6 gross (2.0 net) vertical wells operated by others.

The vertical well costs for the three months ended March 31, 2019 averaged $3.15 million, which included approximately $0.1 million to advance certain technical initiatives designed to help accelerate the next step-change reduction in vertical well costs. This stabilization of capital cost from the higher well cost levels in the early part of 2018 was a reflection of more concentrated vertical well operations. This resulted in efficiencies from development on larger drill pads resulting in less rig movement and a higher utilization rate of equipment.

As of March 31, 2019, the Company had $10.5 million of cash and $38.0 million outstanding under its Revolving Credit Facility. The Revolving Credit Facility has an established borrowing base of $325.0 million based on the borrowing base redetermination completed in February 2019.

Beginning as of January 1, 2019, the Company revised its estimate administrative costs associated with its operations and classified as Lease operating expenses on the consolidated statement of operations. During 2018 and 2019, the Company has taken steps to drive efficiencies through its operations which resulted its overhead costs being less than the inflation adjustment to the overhead rates set by the Council of Petroleum Accountants Societies (“COPAS”). Accordingly, the Company reduced the amount of costs categorized as Lease operating expenses, with General and administrative expenses absorbing a larger portion of the total costs.

The following table summarizes our unaudited condensed consolidated statement of operations for the periods indicated:

	For the Quarter Ended
	Ended March 31,						%
	2019			2018			Variance
	(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)		59,574			68,233			(13	)%
Crude oil and condensate (Bbl)		437			678			(36	)%
Total production (Mcfe)		62,196			72,301			(14	)%

Commodity Prices:
Natural gas ($/Mcf, excluding hedges)	$	4.13		$	2.66			55	%
Natural gas ($/Mcf, including realized hedges)	$	2.77		$	2.68			3	%
Oil and condensate ($/Bbl, excluding hedges)	$	53.70		$	60.90			(12	)%
Oil and condensate ($/Bbl, including realized hedges)	$	59.58		$	60.36			(1	)%

Revenues:
Natural gas sales	$	245,989		$	181,462			36	%
Oil sales		23,465			41,284			(43	)%
Other revenues		2,007			2,628			(24	)%
Total operating revenues	$	271,461		$	225,374			20	%

Derivatives:
Realized gain (loss) on commodity derivatives	$	(78,631	)	$	1,076			(7408	)%
Unrealized gain (loss) on commodity derivatives		14,292			(7,606	)		288	%
Total Loss on commodity derivatives	$	(64,339	)	$	(6,530	)		885	%

Operating Costs and Expenses:
Lease operating expenses	$	17,225		$	21,764			(21	)%
Facility lease expense	$	6,645		$	6,156			8	%
Production taxes	$	30,175		$	23,270			30	%
Gathering fees	$	19,880		$	23,055			(14	)%
Depletion, depreciation and amortization	$	51,653		$	50,540			2	%
General and administrative expenses	$	7,052		$	12,688			(44	)%

Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.28		$	0.30			(7	)%
Facility lease expense	$	0.11		$	0.09			22	%
Production taxes	$	0.49		$	0.32			53	%
Gathering fees	$	0.32		$	0.32			—
Depletion, depreciation and amortization	$	0.83		$	0.70			19	%
General and administrative expenses	$	0.11		$	0.18			(39	)%

Production. During the quarter ended March 31, 2019, total production decreased on a gas equivalent basis to 62.2 Bcfe compared to 72.3 Bcfe for the same period in 2018. The decrease is primarily attributable to a decrease in capital investment which occurred over the second half of 2018 compared to the end of 2017 and early 2018 and resulted in lower production in the current period. Additionally, the sale of the non-core assets in Utah during the third quarter of 2018 resulted in a relative decrease in production on a comparative basis.

Commodity Prices – Natural Gas. During the quarter ended March 31, 2019, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $53.70 per barrel as compared to $60.36 per barrel for the same period in 2018. The significant increase in the unhedged price of natural gas in the first quarter of 2019 was a result of weather-related demand in regions supplied by Rockies natural gas as well as supply constraints into western markets, thereby driving an increase in regional natural gas realizations. This market situation was limited to the period of November 2018 through March 2019, and projected natural gas prices have returned to levels seen in recent periods. This improved natural gas price on unhedged volumes was realized on the Company’s unhedged volumes and certain volumes sold on a daily spot basis during the quarter ended March 31, 2019.

Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 3% to $2.77 per Mcf during the quarter ended March 31, 2019, as compared to $2.68 per Mcf for the same period in 2018. The Company has entered into various natural gas price commodity derivative contracts with contract periods extending through the third quarter of 2020. See Note 7 for additional details relating to these derivative contracts. During the quarter ended March 31, 2019, the Company’s average price for natural gas, excluding realized gains and losses on commodity derivatives, was $4.13 per Mcf as compared to $2.66 per Mcf for the same period in 2018.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, decreased to $59.58 per barrel during the quarter ended March 31, 2019, as compared to $60.90 per barrel for the same period in 2018. The Company has entered into various oil price commodity derivative contracts with contract periods extending through 2020. See Note 7 for additional details relating to these derivative contracts. During the three months ended March 31, 2019, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $53.70 per barrel as compared to $60.36 per barrel for the same period in 2018.

Revenues. During the quarter ended March 31, 2019, revenues increased to $271.5 million as compared to $225.4 million for the same period in 2018. This increase is primarily attributable to the increase in average natural gas prices, excluding gains and losses on commodity derivatives, partially offset by the decrease in total production and decrease in average oil prices.

Lease Operating Expense. Lease operating expense (“LOE”) decreased to $17.2 million during the quarter ended March 31, 2019 as compared to $21.8 million during the same period in 2018 is driven by the exclusion of the Utah production and related expenses in 2019 which approximated $2.8 million for the quarter ended March 31, 2018. The sale of the Utah assets was completed in September 2018. Additionally, the Company adjusted the estimate used to determine the overhead rate used for the Company administrative expenses as previously discussed. The decrease in the overhead charged to the LOE was approximately $2.8 million. On a unit of production basis, LOE costs decreased to $0.28 per Mcfe during the quarter ended March 31, 2019 as compared with $0.30 per Mcfe during the same period in 2018.

Facility Lease Expense. In 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual base rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which base rent may increase if certain volume thresholds are exceeded. For the quarter ended March 31, 2019, the Company recognized expense associated with the Lease Agreement of $6.6 million, or $0.11 per Mcfe, as compared to $6.2 million, or $0.09 per Mcfe for the same period in 2018.

Production Taxes. During the quarter ended March 31, 2019, production taxes increased to $30.2 million compared to $23.3 million during the same period in 2018, or $0.49 per Mcfe compared to $0.32 per Mcfe, respectively. Production taxes in Wyoming are primarily calculated based on a percentage of revenue from the physical production and realized revenues, excluding derivative hedge settlements, after certain deductions and were 11.1% of revenues for the quarter ended March 31, 2019 and 10.3% of revenues for the same period in 2018. The increase in per unit taxes was attributable to increased natural gas prices during the quarter ended March 31, 2019 as compared to the same period in 2018, as well as the fact that production from Utah in 2018 was taxed at a lower rate.

Gathering Fees. During the quarter ended March 31, 2019, gathering fees decreased to $19.9 million compared to $23.1 million during the same period in 2018, related to decreased production volumes. On a per unit basis, gathering fees remained flat at $0.32 per Mcfe for the three months ended March 31, 2019 and 2018.

Depletion, Depreciation and Amortization. During the quarter ended March 31, 2019, depletion, depreciation and amortization (“DD&A”) expense increased to $51.7 million compared to $50.5 million for the same period in 2018. The increase is primarily attributable to a higher depletion rate due to a higher depletable base from the recognition of proved undeveloped properties, as well as overall higher finding and development costs in recent periods than the historical depletion rate per Mcfe, offset slightly by decreased production volumes during the three months ended March 31, 2019. On a unit of production basis, the DD&A rate increased to $0.83 per Mcfe for the quarter ended March 31, 2019 compared to $0.70 per Mcfe for the same period in 2018.

General and Administrative Expenses. During the quarter ended March 31, 2019, general and administrative expenses decreased to $7.1 million as compared to $12.7 million for the same period in 2018. The decrease is primarily attributable to a decrease of stock compensation expense from $8.8 million to $0.8 million for the quarter ended March 31, 2018 and 2019, respectively, as well as severance costs incurred during the quarter ended March 31, 2018. This was partially offset by legal fees related to the Follow-on Debt Exchange Transactions (as defined below) incurred during the quarter ended March 31, 2019, as well as higher level of general and administrative expense resulting from the change in estimate of the overhead costs transferred to LOE. On a per unit basis, general and administrative expenses decreased to $0.11 per Mcfe for the quarter ended March 31, 2019 compared to $0.18 per Mcfe for the same period in 2018.

Interest Expense. Interest expense decreased to $33.3 million during the quarter ended March 31, 2019 as compared to $35.8 million during the same period in 2018. Interest expense is comprised of four primary elements: (i) cash interest expense; (ii) PIK interest expense; (iii) amortization of deferred premium; and (iv) amortization of deferred financing costs. The table below reflects the comparative amounts in each period presented (in thousands):

Deferred Gain on Sale of Liquids Gathering System (“LGS”). During the quarter ended March 31, 2018, the Company recognized $2.6 million in deferred gain on the 2012 sale of the LGS and certain associated real property rights. On January 1, 2019, the Company recognized the remaining deferred gain as an opening balance sheet adjustment to Retained loss upon adoption of ASC 842.

Gain (Loss) on Commodity Derivatives. During the quarter ended March 31, 2019, the Company recognized a loss of $64.3 million, as compared to a loss of $6.5 million related to commodity derivatives for the same period in 2018. Of this total, the Company recognized $78.6 million related to a realized loss on commodity derivatives that were settled during the quarter ended March 31, 2019, as compared with $1.1 million related to a realized gain on commodity derivatives during the same period in 2018. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This amount also includes an unrealized gain of $14.3 million on commodity derivatives during the quarter ended March 31, 2019, as compared to an unrealized loss of $7.6 million during the same period in 2018. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.

Pretax Income. During the quarter ended March 31, 2019, the Company recognized income before income taxes of $40.6 million compared to $47.9 million for the same period in 2018. The operating income and operating expense elements together with the loss on commodity derivatives, offset by the decreased net interest expense were the primary elements for the decrease in net income during the quarter ended March 31, 2019 as compared to the same period in 2018.

Income Taxes. The Company has recorded a valuation allowance against all deferred tax assets as of March 31, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. During the quarter ended March 31, 2019, the Company recognized net income of $40.7 million, or $0.21 per diluted share, as compared to $47.5 million, or $0.24 per diluted share, for the same period in 2018. The operating income and operating expense elements together with the loss on commodity derivatives, offset by the decreased interest expense were the primary elements for the decrease in net income during the quarter ended March 31, 2019 as compared to the same period in 2018.

Overview. During the three months ended March 31, 2019, we funded our operations primarily through cash flows from operating activities and periodic borrowings under the Revolving Credit Facility (defined below). At March 31, 2019, the Company reported a cash position of $10.5 million. At March 31, 2019, the Company had $38.0 million outstanding borrowings. The borrowing base provides for a total of $325.0 million of availability as determined in February 2019. In addition to the borrowings outstanding under the Revolving Credit Facility, the Company had $1.9 billion of other indebtedness outstanding in the form of term loans, secured notes and unsecured notes with maturities commencing in 2022. Availability under the borrowing base may be limited based on compliance with financial covenants; however, the Company expects to have adequate liquidity to fund its operations into the foreseeable future.

Given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, the Company’s liquidity needs could be significantly higher than the Company currently anticipates. The Company’s ability to maintain adequate liquidity depends on the prevailing market prices for oil and natural gas, the successful operation of the business, and appropriate management of operating expenses and capital spending. The Company’s anticipated liquidity needs are highly sensitive to changes in each of these and other factors.

Capital Expenditures. For the quarter ended March 31, 2019, total capital expenditures were $92.4 million. During this period, the Company participated in 27 gross (26.1 net) vertical wells which were drilled and cased in the Pinedale field.

Debt Exchanges. In December 2018, the Company exchanged (i) approximately $505 million aggregate principal amount, or 72.1%, of the 6.875% Senior Notes due 2022 (the “2022 Notes”) and (ii) $275 million aggregate principal amount, or 55.0%, of the 7.125% Senior Notes due 2025 (the “2025 Notes” and, together with the 2022 Notes, the “Unsecured Notes”) of Ultra Resources, Inc., a Delaware corporation (“Ultra Resources”), a wholly owned subsidiary of Ultra Petroleum Corp., for (a) $545.0 million aggregate principal amount of new 9.00% Cash/2.00% PIK Senior Secured Second Lien Notes due July 2024 of Ultra Resources (the “Second Lien Notes”), and (b) an aggregate of 10,919,499 new $0.01 warrants of Ultra Petroleum Corp. entitling the holder thereof to purchase one common share of Ultra Petroleum Corp. (each a “Warrant” and collectively, the “Warrants”) (such transaction, the “December Exchange Transaction”).

2019 Capital Investment Plan. For 2019, our capital expenditures are expected to be $320 million to $350 million, including capitalized general and administrative costs. Our capital investment for the first quarter of 2019 totaled $92.4 million and includes a greater percentage allocation for the year due to the Company having a higher working interest in the wells scheduled early in the year. We expect to fund these capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility, and cash on hand. We expect to allocate all of the budget to development activities in our Pinedale field. The Company has the ability to adjust the capital investment plan depending on the projected natural gas price. Additionally, this amount may vary depending on whether partners elect to participate in their working interest share of proposed wells and, similarly, the Company may elect not to participate in wells drilled by other operators.

Credit Agreement. In April 2017, Ultra Resources, as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “RBL Lenders”), providing for a revolving credit facility (the “Revolving Credit Facility”) subject to a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (as defined below). The semi-annual redetermination in February 2019 resulted in a borrowing base commitment of 1.3 billion, with $975.0 million allocated to the Company’s Term Loan (as defined below) and $325.0 million allocated to the Revolving Credit Facility.

of the Second Lien Notes and the December Exchange Transaction and to revise certain covenants and other provisions of the Credit Agreement, including, but not limited to:

On February 14, 2019, Ultra Resources entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment to Credit Agreement”) with the RBL Administrative Agent and the RBL Lenders party thereto. Pursuant to the Fourth Amendment to Credit Agreement, the borrowing base was affirmed at $1.3 billion. Given the Revolving Credit Agreement was amended in February 2019 and the borrowing base was reaffirmed therein, the next scheduled borrowing base redetermination date is in October 2019.

The Fourth Amendment to Credit Agreement also revised certain covenants and other provisions of the Credit Agreement, including, but not limited to:

At March 31, 2019, Ultra Resources had $38.0 million of outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $325.0 million.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions, and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022.

At March 31, 2019, Ultra Resources had $975.1 million in outstanding borrowings under the Term Loan Agreement, including PIK interest and current maturities.

Borrowings under the Term Loan Agreement bear interest either at a rate equal to (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable-in-kind upon election by Ultra Resources. Beginning in March 2019, the Company has affirmatively elected the PIK option and management expects to continue this practice into the future. Borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. Borrowings under the Term Loan Agreement mature on April 12, 2024.

indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At March 31, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

Prior to December 21, 2021, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the Second Lien Notes in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 111.000% of the principal amount of the Second Lien Notes, plus accrued and unpaid interest (including PIK interest), if any, to the date of redemption, if at least 65% of the original principal amount of the Second Lien Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest (including PIK interest), if any, to the redemption date. In addition, on or after December 21, 2021, Ultra Resources may redeem all or a part of the Second Lien Notes at redemption prices (expressed as percentages of principal amount) equal to 105.500% for the twelve-month period beginning on December 21, 2021, 102.750% for the twelve-month period beginning December 21, 2022, and 100.000% for the twelve-month period beginning December 21, 2023 and at any time thereafter, plus accrued and unpaid interest (including PIK interest), if any, to the applicable redemption date on the Second Lien Notes.

immediately due and payable, except that an event of default resulting from entry into a bankruptcy, insolvency or reorganization with respect to the Company, any Significant Subsidiary (as defined in the Second Lien Notes Indenture) or group of Restricted Subsidiaries (as defined in the Second Lien Notes Indenture), that taken together would constitute a Significant Subsidiary, will automatically cause the Second Lien Notes to become due and payable.

Unsecured Notes. In April 2017, the Company issued $700.0 million of its 2022 Notes and $500.0 million of its 2025 Notes and entered into an Indenture, dated April 12, 2017 (the “Unsecured Notes Indenture”), among Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as Trustee. The Unsecured Notes are treated as a single class of securities for most purposes under the Unsecured Notes Indenture.

Operating Activities. During the three months ended March 31, 2019, net cash provided by operating activities was $150.7 million compared to $152.0 million for the same period in 2018. The slight decrease in net cash provided by operating activities is attributable to a decrease in net income offset by an increase in working capital.

Investing Activities. During the three months ended March 31, 2019, net cash used in investing activities was $90.4 million as compared to $148.8 million for the same period in 2018. The decrease in net cash used in investing activities is largely related to decreased capital investments associated with the Company’s drilling activities, as the Company was operating a three-drilling rig program during the three months ended March 31, 2019 compared to a seven-drilling rig program in the same period of 2018.

Financing Activities. During the three months ended March 31, 2019, net cash used in financing activities was $66.5 million as compared to $2.1 million for the same period in 2018. The increase in net cash used in financing activities is attributable to the payments on the Revolving Credit Facility from operating cash flows in excess of the borrowings for the three months ended March 31, 2019.

The discussion and analysis of the Company’s financial condition and results of operations is based upon consolidated financial statements, which have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). In addition, application of GAAP requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements as well as the revenues and expenses reported during the period. Changes in these estimates related to judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated. Set forth below is a discussion of the critical accounting policies used in the preparation of our financial statements which we believe involve the most complex or subjective decisions or assessments.

Derivative Instruments and Hedging Activities. The Company follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Condensed Consolidated Balance Sheets and records the changes in the fair value of its commodity derivatives in the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. See Note 7 for additional details.

Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three-level hierarchy for measuring fair value.

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	10,985	$	—	$	10,985
Long-term derivative asset (1)		—		5,715		—		5,715
Total derivative instruments	$	—	$	16,700	$	—	$	16,700
Liabilities:
Current derivative liability	$	—	$	38,483	$	—	$	38,483
Long-term derivative liability (2)		—		6,756		—		6,756
Total derivative instruments	$	—	$	45,239	$	—	$	45,239

Asset Retirement Obligation. The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) requires that the fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Condensed Consolidated Balance Sheets.

Share-Based Payment Arrangements. The Company applies FASB ASC Topic 718, Compensation – Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards

made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the three months ended March 31, 2019 and 2018 was $0.8 million and $8.8 million, respectively.

Property, Plant and Equipment. Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life.

Oil and Natural Gas Properties. The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and FASB ASC Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded on the fair value of the asset retirement obligation when incurred. Gain or loss or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation during the three months ended March 31, 2019 or 2018.

Leases. The Company adopted ASU 2016-02, Leases, and all applicable amendments as of January 1, 2019. The Company elected to apply the new standard to all leases existing at the date of initial application. Consequently, historical financial information will not be updated, and the disclosures required under the new standard will not be provided for dates and periods prior to January 1, 2019.

The Company determines if an arrangement is a lease at inception. Operating leases are included in long-term right-of-use (“ROU”) assets, and long-term lease liabilities on our condensed consolidated balance sheets. ROU assets represent the Company’s right to use of an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives. The Company’s lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The ROU assets are tested for impairment in accordance with ASC 360.

The Company has lease agreements with lease and non-lease components, which are accounted for as a single lease component under the practical expedient provisions of the standard. Additionally, for certain leases, we apply a portfolio approach to effectively account for the operating lease ROU assets and liabilities. The portfolio approach was used to assess and determine the incremental borrowing rate with information available at adoption date.

Revenue Recognition. The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosures related to the Company’s revenue recognition policy.

Valuation of Deferred Tax Assets. Income taxes are accounted for under the asset and liability method. 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 basis and operating loss and tax credit carryforwards. 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. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

Warrants. In December 2018, the Company issued 10,919,499 new Warrants. The Warrants are initially exercisable for one common share of Ultra Petroleum Corp., no par value, at an initial exercise price of $0.01 per Warrant (the “Warrant Exercise Price”). No Warrants will be exercisable until the date on which the volume-weighted average price of the common shares is at least $2.50 per common share for 30 consecutive trading days (the “Trading Price Condition”). Subject to the Trading Price Condition, the Warrants are exercisable at the option of the holders thereof until July 14, 2025, at which time all unexercised Warrants will expire and the rights of the holders of such Warrants to purchase common shares will terminate. Under the guidance in FASB ASC 815, the Warrants do not meet the definition of a derivative. The Warrants are classified as equity and recorded at fair value as of the date of issuance on the Company’s Consolidated Balance Sheets and no further adjustments to their valuation are made.

Deferred Financing Costs. The Company follows ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs for its Term Loan, Second Lien Notes and Unsecured Notes, and includes the costs for issuing debt, including issuance discounts, as a direct deduction from the carrying amount of the related debt liability.

Additionally, the Company follows ASU No. 2015-15, Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line of Credit Arrangements for its Revolving Credit Facility and includes the costs related to the issuance of the Revolving Credit Facility in Other assets on the Condensed Consolidated Balance Sheets.

Conversion of Barrels of Oil to Mcfe of Gas. The Company converts barrels of oil and other liquid hydrocarbons to Mcfe at a ratio of one barrel of oil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas. The sales price of one barrel of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six-to-one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a barrel of oil or other liquids.

expedients and established internal controls and key system functionality to enable the preparation of financial information on adoption.

The following table reflects the cumulative impact of the adoption of ASC 842 using the modified retrospective approach.

	December 31, 2018 as reported			Impact of ASC 842			January 1, 2019 as adjusted
	(Amounts in thousands)
Long-term right-of-use assets	$	—		$	130,649		$	130,649
Total assets		1,733,288			130,649			1,863,937

Lease liabilities (current)		—			11,141			11,141
Deferred gain on sale of liquids gathering system		94,636			(94,636	)		—
Long-term lease liabilities		—			121,326			121,326
Total liabilities		2,781,910			37,831			2,819,741
Retained earnings (loss)		(3,186,016	)		92,818			(3,093,198	)
Total stockholders' equity (deficit)		(1,048,622	)		92,818			(955,804	)
Total liabilities and stockholders' equity (deficit)		1,733,288			130,649			1,863,937

The Company did not have any off-balance sheet arrangements as of March 31, 2019.

Objectives and Strategy: The Company is exposed to commodity price risk. The following quantitative and qualitative information is provided about financial instruments to which we were a party at March 31, 2019, and from which we may incur future gains or losses from changes in commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. The prices we receive for our

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.

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in the Company’s forward cash flows supporting the Company’s capital investment program. These types of instruments may include fixed price swaps, costless collars, deferred premium puts or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. While mitigating the effects of fluctuating commodity prices, these derivative contracts may limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

Under the Revolving Credit Facility, the Company is subject to the following minimum hedging requirements: through September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volumes of natural gas from its PDP reserves; and during the period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of the quarterly projected volumes of natural gas from PDP reserves. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Condensed Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 8 for details regarding the fair value of the derivative contracts described below.

Commodity Derivative Contracts: At March 31, 2019, the Company had the following open commodity derivative contracts to manage commodity price risk. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty. For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

Type/Year	Index	Total Volumes		Weighted Average Price per Unit		Fair Value - March 31, 2019
		(in millions)				Asset (Liability)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2019 (April through December)	NYMEX-Henry Hub	137.8		$	2.77	$	(2,079	)
2020	NYMEX-Henry Hub		24.6		2.78		(5,439	)

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2019 (April through December)	NW Rockies Basis Swap		90.2	$	0.58	$	(18,734	)
2020	NW Rockies Basis Swap		7.7		0.15		770.00

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2019 (April through December)	NYMEX-WTI		1.0	$	58.64	$	(1,680	)
2020	NYMEX-WTI		0.1		60.05		51.00

Type/Year	Index	Total Volumes		Weighted Average Floor Price ($/MMBTU)			Weighted Average Ceiling Price ($/MMBTU)			Fair Value - March 31, 2019
		(in millions)
Natural gas collars		(Mmbtu)
2019 (April through December)	NYMEX		2.8		$	2.85		$	3.13		$	264
2020	NYMEX		49.4		$	2.51		$	2.97		$	(1,298	)

Natural gas deferred premium put options		(Mmbtu)
2020	NYMEX		25.1		$	2.41		N/A			$	(394	)

Subsequent to March 31, 2019 and through April 30, 2019, the Company entered into the following open commodity derivative contracts to manage commodity price risk.

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

We are also exposed to market risk related to adverse changes in interest rates, primarily related to fluctuations in short-term rates that are based on the London interbank offered rate. Such fluctuations may result in reductions of earnings or cash flows due to increases in the interest rates we pay on outstanding borrowings under the Revolving Credit Facility and Term Loan Agreement. At March 31, 2019, the weighted average interest rate on our variable rate debt was 6.43% per year. If the balance of our variable interest rate at March 31, 2019 were to remain constant, a 10% change in the variable market interest rates would impact our cash flows by approximately $2.7 million per year.

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our natural gas and oil production, which we market to diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness.

To a lesser extent, we are also exposed to credit risk through our derivative counterparties. We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 7 for additional information regarding our derivative activities.

The Company has performed an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report on Form 10-Q. The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2019.

There were no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

See Note 10 for discussion of on-going claims and disputes that arose during our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

Our business has many risks. Any of the risks discussed in this Quarterly Report on Form 10-Q or in our other SEC filings, could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. Except as set forth below, there have been no material changes to the risks described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

Compliance with environmental and occupational safety and health laws and other government regulations could be costly and could negatively impact our production.

Our operations are subject to numerous and complex laws and regulations relating to environmental and occupational protection. These laws and regulations, which are continuously being reviewed for amendment and/or expansion, may:

Under these laws and regulations or under the common law, we could be liable for personal injury and clean-up costs and other environmental, natural resource and property damages, as well as administrative, civil and criminal penalties or injunctions. Failure to comply with these laws and regulations could also result in the occurrence of delays or restrictions in permitting or performance of projects, or the issuance of orders and injunctions limiting or preventing operations relating to our properties in some areas. Under certain environmental laws and regulations, an owner or operator of our properties could be subject to strict, joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination, regardless of whether the owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred. Private parties, including the owners of properties upon which wells are drilled or facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, to seek damages for contamination or for personal injury or property damage. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by accidental environmental damages. Accordingly, we may be subject to liability in excess of our insurance coverage or may be required to cease production from properties in the event of material environmental damages.

We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, greenhouse gases and hydraulic fracturing. Changes in environmental laws and regulations, or their interpretation, can occur frequently, and any changes that result in delays or restrictions in permitting, development or operations of projects, including any temporary curtailments of operations by regulators, or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements could require significant expenditures by Ultra or other operators of the properties to attain and maintain compliance and may otherwise have a material adverse effect on the results of operations, competitive position or financial condition of Ultra or such other operators. Increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY 2017-2019 National Enforcement Initiatives, through which the EPA will purportedly address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment. In addition, government disruptions, such as an extended federal government shutdown resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits, approvals, and certificates required to conduct our operations.

A significant percentage of our operations are conducted on federal and state lands. These operations are subject to a wide variety of regulations as well as other permits and authorizations which must be obtained from and issued by state and federal agencies. To conduct these operations, we may be required to file applications for permits, seek agency authorizations and comply with various other statutory and regulatory requirements. Complying with any of these requirements may adversely affect our ability to complete our drilling programs at the costs and in the time periods anticipated.

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.

Yukon, Canada	N/A
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)

116 Inverness Drive East, Suite 400 Englewood, Colorado	80112
(Address of principal executive offices)	(Zip code)


Title of Each Class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Shares, without par value	UPL	NASDAQ Global Select Market

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements	3

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	41

ITEM 4.	Controls and Procedures	44

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	45

ITEM 1A.	Risk Factors	45

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

ITEM 3.	Defaults upon Senior Securities	46

ITEM 4.	Mine Safety Disclosures	46

ITEM 5.	Other Information	46

ITEM 6.	Exhibits	47

	Signatures	49

	For the Three Months
	Ended March 31,
	2019		2018
Total cost of share-based payment plans	$	1,127	$	10,910
Amounts capitalized in oil and gas properties and equipment	$	286	$	2,100
Amounts charged against income, before income tax benefit	$	841	$	8,810
Amount of related income tax benefit recognized in income before valuation allowance	$	177	$	1,850

	For the Three Months
	Ended March 31,
Commodity Derivatives (in thousands):	2019			2018
Realized gain (loss) on commodity derivatives - natural gas (1)	$	(81,203	)	$	1,446
Realized gain (loss) on commodity derivatives - oil (1)		2,572			(370	)
Unrealized gain (loss) on commodity derivatives (1)		14,292			(7,606	)
Total gain (loss) on commodity derivatives	$	(64,339	)	$	(6,530	)


Large accelerated filer	☐	Accelerated filer	☑
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

	For the Three Months Ended
	March 31,
	2019		2018
	(Share amounts in 000's)
Net income	$	40,674	$	47,493
Weighted average common shares outstanding - basic		197,383		196,550
Effect of dilutive instruments		418		—
Weighted average common shares outstanding - diluted		197,801		196,550
Net income per common share - basic	$	0.21	$	0.24
Net income per common share - fully diluted	$	0.21	$	0.24

	For the Three Months Ended
	March 31, 2019
Operating lease cost	$	5,255
Variable lease cost (1)	$	1,694
Short-term lease cost (2)	$	9,910
Total lease cost (3)	$	16,859

	March 31, 2019
Operating Leases
Operating lease right-of-use assets	$	127,861

Operating lease liabilities	$	11,261
Long-term operating lease liabilities		116,613
Total operating lease liabilities	$	127,874

Weighted Average Remaining Lease Term
Operating leases	8.6 years
Weighted Average Discount Rate
Operating leases		7.91	%

	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	$	5,242

	Operating Leases
For the year ending December 31,
2019 (remaining)	$	15,646
2020		20,853
2021		20,750
2022		20,327
2023		19,719
Thereafter		78,239
Total lease payments	$	175,534
Less: imputed interest		(47,660	)
Total	$	127,874

Exhibit Number		Description
2.1		Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit A of the Order Confirming Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization, filed as Exhibit 99.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on March 16, 2017).

3.1		Articles of Reorganization of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form 8-A filed by Ultra Petroleum Corp. on April 12, 2017).

3.2		Second Amended and Restated Bylaw No. 1 of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on March 12, 2018).

4.1		Specimen Common Share Certificate (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017).

4.2		Indenture dated as of April 12, 2017 among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017).

4.3		First Supplemental Indenture dated as of December 21, 2018, to Indenture dated as of April 12, 2017, among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018).

4.4		Indenture dated as of December 21, 2018, among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on December 26, 2018).

4.5		First Supplemental Indenture dated as of January 22, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on January 25, 2019).

4.6		Second Supplemental Indenture dated as of January 23, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on January 25, 2019).

4.7		Third Supplemental Indenture dated as of February 4, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.7 to the Annual Report on Form 10-K filed by Ultra Petroleum Corp. on March 7, 2019).

4.8		Fourth Supplemental Indenture dated as of February 13, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.8 to the Annual Report on Form 10-K filed by Ultra Petroleum Corp. on March 7, 2019).

4.9		Fifth Supplemental Indenture dated as of February 15, 2019, to Indenture dated as of December 21, 2018, among Ultra Petroleum Corp., Ultra Resources, Inc., the subsidiary guarantors party thereto, and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.9 to the Annual Report on Form 10-K filed by Ultra Petroleum Corp. on March 7, 2019).

10.1		Fourth Amendment to Credit Agreement dated as of February 14, 2019, among Ultra Resources, Inc. as borrower, Bank of Montreal, as administrative agent, and each of the lenders and other parties party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on February 19, 2019).
*#10.2		Employment Agreement of Brad Johnson dated as of March 11, 2019.
*#10.3		Employment Agreement of Kent Rogers dated as of March 11, 2019.
*#10.4		Form of Restricted Stock Unit Agreement

*#10.5		Form of Restricted Stock Unit Agreement
*31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document.

**101.SCH		XBRL Taxonomy Extension Schema Document.

**101.CAL		XBRL Taxonomy Calculation Linkbase Document.

**101.LAB		XBRL Label Linkbase Document.

**101.PRE		XBRL Presentation Linkbase Document.

**101.DEF		XBRL Taxonomy Extension Definition.

	ULTRA PETROLEUM CORP.

	By:	/s/ Brad Johnson
		Name:	Brad Johnson
		Title:	President and Chief Executive Officer

Date: May 9, 2019

	By:	/s/ David W. Honeyfield
		Name:	David W. Honeyfield
		Title:	Senior Vice President and Chief Financial Officer

Date: May 9, 2019