upl-10q_20190630.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 July 31, 2019 was 197,840,056.

	June 30,			December 31,
	2019			2018
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	5,191		$	17,014
Restricted cash		2,902			2,291
Oil and gas revenue receivable and other receivables, net of allowances $10,427 and $8,350, respectively		55,669			144,390
Derivative assets		58,198			23,374
Inventory		17,058			18,757
Other current assets		3,240			8,904
Total current assets		142,258			214,730
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,576,539			1,497,727
Property, plant and equipment, net		10,620			11,635
Long-term right-of-use assets		125,110			—
Other assets		18,699			9,196
Total assets	$	1,873,226		$	1,733,288
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	34,315		$	36,923
Accrued liabilities		53,206			58,574
Production taxes payable		55,151			58,365
Current portion of long-term debt		9,750			7,313
Interest payable		34,724			28,672
Lease liabilities		11,489			—
Derivative liabilities		20,692			62,350
Capital cost accrual		13,430			15,014
Total current liabilities		232,757			267,211
Long-term debt
Credit facility		59,000			104,000
Long-term debt		1,917,008			1,932,722
Add: Premium on exchange transactions		225,085			228,096
Less: Unamortized deferred financing costs and discount		(51,635	)		(56,650	)
Total long-term debt, net		2,149,458			2,208,168
Deferred gain on sale of liquids gathering system		—			94,636
Long-term lease liabilities		113,642			—
Other long-term obligations		233,594			211,895
Total liabilities		2,729,451			2,781,910
Commitments and contingencies (Note 12)
Shareholders' equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 197,840,056 and 197,383,295 at June 30, 2019 and December 31, 2018, respectively		2,139,314			2,137,443
Treasury stock		(49	)		(49	)
Retained loss		(2,995,490	)		(3,186,016	)
Total shareholders' deficit		(856,225	)		(1,048,622	)
Total liabilities and shareholders' equity	$	1,873,226		$	1,733,288

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands, except per share data)
Revenues:
Natural gas sales	$	125,915		$	141,255		$	371,903		$	322,716
Oil sales		27,301			43,167			50,767			84,451
Other revenues		2,190			5,716			4,197			8,344
Total operating revenues		155,406			190,138			426,867			415,511
Expenses:
Lease operating expenses		15,889			23,645			33,114			45,409
Facility lease expense		6,543			6,526			13,188			12,682
Production taxes		16,443			18,883			46,618			42,153
Gathering fees		20,320			24,181			40,200			47,238
Depletion, depreciation and amortization		55,768			51,742			107,422			102,282
General and administrative		7,433			2,063			14,485			14,752
Other operating expenses, net		15,281			639			16,085			853
Total operating expenses		137,677			127,679			271,112			265,369
Operating income		17,729			62,459			155,755			150,142
Other income (expense), net:
Interest expense		(32,376	)		(37,715	)		(65,703	)		(73,552	)
Gain (loss) on commodity derivatives		71,654			(47,271	)		7,316			(53,803	)
Deferred gain on sale of liquids gathering system		—			2,638			—			5,276
Other income (expense), net		(43	)		(657	)		243			(688	)
Total other (expense) income, net		39,235			(83,005	)		(58,144	)		(122,767	)
Income before income tax (benefit) provision		56,964			(20,546	)		97,611			27,375
Income tax (benefit) provision		(141	)		9			(169	)		442
Net income (loss)	$	57,105		$	(20,555	)	$	97,780		$	26,933
Basic earnings (loss) per share:
Net income (loss) per common share - basic	$	0.29		$	(0.10	)	$	0.50		$	0.14
Fully diluted earnings (loss) per share:
Net income (loss) per common share - fully diluted	$	0.29		$	(0.10	)	$	0.49		$	0.14
Weighted average common shares outstanding - basic		197,514			197,054			197,449			196,803
Weighted average common shares outstanding - fully diluted		198,069			197,054			198,089			196,803

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

	Common Stock
	Shares			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	)
Stock plan grants		648			—		—			—			—
Net share settlements		(191	)		—		(71	)		—			(71	)
Fair value of employee stock plan grants		—			744		—			—			744
Net income		—			—		57,105			—			57,105
Balances at June 30, 2019		197,840		$	2,139,314	$	(2,995,490	)	$	(49	)	$	(856,225	)

	Common Stock
	Shares			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		—			—		47,488			—			47,488
Balances at March 31, 2018		197,054		$	2,126,727	$	(3,223,417	)	$	(49	)	$	(1,096,739	)
Fair value of employee stock plan grants		—			2,464		—			—			2,464
Net income (loss)		—			—		(20,555	)		—			(20,555	)
Balances at June 30, 2018		197,054		$	2,129,191	$	(3,243,972	)	$	(49	)	$	(1,114,830	)

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

	Six Months Ended June 30,
	2019			2018
	(In thousands)
Operating activities - cash provided by (used in):
Net income for the period	$	97,780		$	26,933
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		107,422			102,282
Unrealized loss (gain) on commodity derivatives		(82,527	)		61,539
Deferred gain on sale of liquids gathering system		—			(5,276	)
Stock compensation		1,521			10,122
Payable-in-kind (“PIK”) interest payable		6,722			—
Amortization of premium on debt exchange		(20,572	)		—
Amortization of deferred financing costs		6,308			5,510
Other		1,915			207
Net changes in operating assets and liabilities:
Accounts receivable		86,645			17,738
Other current assets		(636	)		3,783
Other non-current assets		59			338
Accounts payable		(1,449	)		(18,525	)
Accrued liabilities		(5,519	)		(4,116	)
Production taxes payable		(3,214	)		3,696
Interest payable		6,052			(3,647	)
Other long-term obligations		8,187			(1,647	)
Income taxes payable/receivable		6,431			6,844
Net cash provided by operating activities		215,125			205,781
Investing Activities - cash provided by (used in):
Oil and gas property expenditures		(176,791	)		(250,966	)
Change in capital cost accrual and accounts payable		(2,743	)		(14,483	)
Inventory		1,567			(4,140	)
Purchase of capital assets		(373	)		(2,389	)
Net cash used in investing activities		(178,340	)		(271,978	)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement		431,000			450,000
Payments under Credit Agreement		(476,000	)		(392,000	)
Payments under Term Loan		(2,438	)		—
Deferred financing costs		(488	)		(638	)
Repurchased shares/net share settlements		(71	)		(2,061	)
Net cash used in financing activities		(47,997	)		55,301
(Decrease) increase in cash during the period		(11,212	)		(10,896	)
Cash, cash equivalents, and restricted cash, beginning of period		19,305			18,269
Cash, cash equivalents and restricted cash, end of period	$	8,093		$	7,373

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”, or “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 southwest Wyoming.

Basis of Presentation: 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 and six months ended June 30, 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.

Significant Accounting Policies: The significant accounting policies followed by the Company are set forth in Note 1, Significant Accounting Policies, in the 2018 Form 10-K and are supplemented by the notes to the unaudited condensed consolidated financial statements included in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2018 Form 10-K. Refer to Note 11, Leases, for the updated policies related to the implementation of ASU 2016-02, Leases (Topic 842).

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

New Accounting Pronouncements: From time to time, the Financial Accounting Standards Board ("FASB") or other standards setting bodies issue new accounting pronouncements. Updates to the FASB Accounting Standards Codification ("ASC") are communicated through issuance of an Accounting Standards Update ("ASU"). Unless otherwise discussed, we believe that the impact of recently issued guidance, whether adopted or to be adopted in the future, is not expected to have a material impact on the consolidated financial statements upon adoption.

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 11 for additional discussion.

The following table reflects the cumulative impact of the adoption of ASC 842 on January 1, 2019, using the modified retrospective approach:

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 (“ASU 2018-13”). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. ASU 2018-13 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. The Company is currently assessing the impact of ASU 2016-13 on its 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 either (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 either (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 either (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 at index-based prices. 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 six months ended June 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

The following table summarizes the major classes of inventory included on the Condensed Consolidated Balance Sheet:

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, warrants are not included in the diluted earnings per share denominator using the treasury stock method 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”).

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

The following tables summarize the Company’s debt instruments as of June 30, 2019 and December 31, 2018:

Credit Agreement. Ultra Resources Inc., a Delaware corporation and wholly-owned subsidiary of the Company, (“Ultra Resources”) entered into a Credit Agreement as the borrower 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. At June 30, 2019, Ultra Resources had $59.0 million of outstanding borrowings under the Revolving Credit Facility, and with total commitments of $325.0 million. The next scheduled borrowing base redetermination is scheduled for October 1, 2019.

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. The applicable margin increases by 25 basis points in the event the Company’s consolidated net leverage ratio, as defined, exceeds 4.00 to 1.00. 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 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 is required to maintain the consolidated net leverage ratio at or below 4.75 to 1.00, (ii) each fiscal quarter ending during the period from September 30, 2019 through June 30, 2020, Ultra Resources is required to maintain the consolidated net leverage ratio at or below 4.90 to 1.0, (iii) the fiscal quarter ending September 30, 2020, Ultra Resources is required to maintain the consolidated net leverage ratio at or below 4.50 to 1.0, and (iv) the fiscal quarter ending December 31, 2020 and each other fiscal quarter end thereafter, Ultra Resources is required to maintain the consolidated net leverage ratio at or below 4.25 to 1.0. At June 30, 2019, Ultra Resources’ consolidated net leverage ratio and interest coverage ratio were 4.44 to 1.00 and 3.18 to 1.00, respectively, and Ultra Resources was in compliance with each of its debt covenants under the Credit Agreement. A sustained decline in commodity prices could cause the Company to be out of compliance with future consolidated net leverage covenant ratios.

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. The duration of the hedging requirements is an 18-month period from the end of a given quarter.

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. As of June 30, 2019, the Ultra Resources’ First Amendment to the Senior Secured Term Loan (the “Term Loan Agreement”) had a balance of approximately $973.2 million in borrowings, including payable-in-kind (“PIK”) and current maturities. The Term Loan Agreement is signed 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”).

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:

Borrowings under the Term Loan Agreement bear interest at a rate equal to either (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 initial aggregate principal amount beginning on June 30, 2019. Borrowings under the Term Loan Agreement mature 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 conditions, 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 equal to six monthly payments are required to attain compliance and 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 June 30, 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. As of June 30, 2019, Ultra Resources had approximately $578.1 million, including PIK interest, in outstanding borrowings of Senior Secured Second Lien Notes (“Second Lien Notes”) pursuant to the Indenture, dated December 21, 2018 (the “Second Lien Notes Indenture”), with Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral agent (the “Trustee”).

Interest on the Second Lien Notes 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 will mature on July 12, 2024.

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.

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 Ultra Resources 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.

Ultra Resources is subject to certain customary covenants under the Second Lien Notes Indenture and was in compliance with all such covenants as of June 30, 2019. Refer to Note 6 Long Term Debt in the 2018 Form 10-K for additional details on the terms of the Second Lien Notes.

Unsecured Notes. At June 30, 2019, Ultra Resources had approximately $150.4 million of the 6.875% Senior Notes due 2022 (the “2022 Notes”) and $225.0 million with respect to the 7.125% Senior Notes due 2025 (the “2025 Notes”, and together with the 2022 Notes, the “Unsecured Notes”).

The 2022 Notes will mature on April 15, 2022. Interest on the 2022 Notes accrue at an annual rate of 6.875% and 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. Interest on the 2025 Notes accrue at an annual rate of 7.125% and 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. Refer to Note 6 Long Term Debt in the 2018 Form 10-K for additional details on the terms of the Unsecured Notes.

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, employees, and consultants 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% or $6.6 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, the Board 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 include time-based and performance-based measures established by the Board 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 within the model) 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 six months ended June 30, 2019, the Company recognized $1.5 million in pre-tax compensation expense, which is included within General and administrative expenses on the condensed consolidated statement of operations. During the six months ended June 30, 2018, the Company recognized $10.1 million in pre-tax compensation expense, of which $10.0 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 the valuation allowances.

The Company has a valuation allowance recorded against all deferred tax assets as of June 30, 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. Further guidance and clarifications continue to be issued regarding the regulations and provisions of the Tax Act. 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.

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.

Fair Value of Commodity Derivatives: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC 815”). The Company does not apply hedge accounting to any of its derivative instruments. Instead, in accordance with ASC 815 the derivative contracts are recorded at fair value as derivative assets and liabilities on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense on the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. 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 June 30, 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 10 for more information regarding the Company’s derivative instruments.

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 June 30, 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).

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 June 30, 2019, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts. Refer to Note 9 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.

The Company adopted ASU 2016-02, Leases (Topic 842), 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 be provided only for periods beginning 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.

As of the adoption date, 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.

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. 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, 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 the reserve fund 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 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 June 30, 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. In August 2019, the Company and ONRR agreed in principle to a resolution agreement whereby the Company agreed to pay $12.4 million through installment payments over 60 months, with interest accruing at the applicable federal rate and payable with the final installment payment. This obligation has been recorded to Other operating expense, net on the condensed consolidated statement of operations as of June 30, 2019, and the first installment payments is due in September 2019. Both the Company and ONRR will issue full releases in connection with the audit period. The releases will not be an admission of liability as to any of the matters settled.

During the quarter ended June 30, 2019, the Company settled and funded a dispute related to a net profits interest in certain of its operated leases in the Pinedale field. This settlement resulted in a payment of $3.5 million. The Company had previously accrued for this item; therefore, no additional expense was recognized during the quarter. Additionally, the Company agreed in principle the settlement of a separate overriding royalty interest dispute and has recognized an expense of $1.5 million as an estimate of the historical claims.

We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in the Pinedale field. 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 Company has adequately reserved for such items where it has been determined that a liability is probable and is reasonably estimable. Additionally, we believe that resolution of all such additional 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 June 30, 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, except as set forth below:

As previously disclosed, 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. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc.

As previously disclosed, the Company had settled certain claims in 2018 and in the first quarter 2019. As of March 31, 2019, the Company had approximately $260 million of claims still outstanding. During and subsequent to the quarter ended June 30, 2019, the Company entered into additional settlement agreements with holders of certain make-whole and post-petition interest claims. Pursuant to these settlements, the parties agreed to settle the pending disputes between such holders and the Company, and the holders collectively agreed to pay approximately $13.5 million to the Company. As of August 8, 2019, there is approximately $240 million of claims subject to the Appellate Court decision. It is not possible to determine the ultimate disposition of these matters at this time.

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 crude oil and condensate from its Pinedale field.

Total production for the quarter ended June 30, 2019 was 59.8 Bcf of natural gas and 449.2 MBbl of crude oil and condensate, for a total of 62.5 Bcfe of production. The production was 0.3 Bcfe higher as compared to the first quarter of 2019, as the drilling program in the first quarter and into the second quarter approximately replaced the natural decline from the proved producing wells on line as of the beginning of the year. The Company generated significant cash flow from it producing activities, whereby it has produced 124.7 Bcfe through the six months ended June 30, 2019. For the six months ended June 30, 2019, cash flow from operations was $215.1 million.

During the second quarter, the Company elected to release a drilling rig and reduce its operated rig count in the Pinedale field from three to two. This decision was based on the following factors: 1) consideration of the current pace at which the drilling of wells was occurring; 2) the Company participated in the wells at a higher working interest percentage due to one of its partners electing to non-consent participation in the wells; 3) the overall expected economic returns on the invested capital with the current commodity pricing; and 4) the goal of the Company to generate free cash flow.

In the third quarter of 2019, the Company has announced plans to further reduce its operated drilling program to a single rig as a result of continued low commodity prices. This will reduce the level of total 2019 capital investment to range of $260 million to $290

million, a reduction of approximately $60 million, or 18%, from the midpoint of the Company’s initial 2019 capital investment guidance. The Company will continue to evaluate the commodity price environment and the projected investment returns, as it manages its capital investment program.

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 derivative commodity contracts through the use of 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. 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. The Company utilizes costless collars and 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.

On a per unit basis, the average realized prices for the Company in the quarters ended June 30, 2019 and 2018, was $2.45 per Mcfe and $2.60 per Mcfe, respectively. The average price realization for the Company’s natural gas during the quarter ended June 30, 2019 was $2.17 per Mcf, including realized gains and losses on commodity derivatives, compared to $2.28 per Mcf during the quarter ended June 30, 2018. The average price realization for the Company’s natural gas during the each of the quarters ended June 30, 2019 and 2018, excluding realized gains and losses on commodity derivatives, was $2.11 per Mcf.

The average price realization for the Company’s crude oil and condensate during the quarter ended June 30, 2019 was $59.65 per barrel, including realized gains and losses on commodity derivatives, compared to $58.24 per barrel during the quarter ended June 30, 2018. The average price realization for the Company’s crude oil and condensate during the quarter ended June 30, 2019, excluding realized gains and losses on commodity derivatives, was $60.80 per barrel, compared to $64.71 per barrel during the quarter ended June 30, 2018.

As of June 30, 2019, the Company operated two rigs in the Pinedale field with a primary focus of drilling vertical wells. The Company has also participated in wells drilled by other operators in the Pinedale field during this period. The total capital investment in oil and gas properties was $176.8 million for the six months ended June 30, 2019. During this period, there were 53 gross (52.5 net) vertical wells and 1 gross (0.9 net) horizontal wells, together with 16 gross (5.3 net) vertical wells operated by others that were brought online.

The vertical well costs as of June 30, 2019 averaged $3.19 million. 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 June 30, 2019, the Company had $5.2 million of cash and $59.0 million outstanding under its Revolving Credit Facility. The borrowing base under our Revolving Credit Facility is currently $1.3 billion, and lender commitments under the Revolving Credit Facility are $325.0 million based on the borrowing base redetermination completed in February 2019. The next borrowing base redetermination is scheduled for October 1, 2019.

The Company’s borrowing base may decrease as a result of lower commodity prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness, or for various other reasons. A decrease in the Company’s borrowing base due to declines in commodity prices or otherwise, would impact the Company’s ability to borrow under the Revolving Credit Facility and could require the Company to pay indebtedness in excess of the redetermined borrowing base. In addition, the Company may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations, including any such debt repayment obligations.

Moreover, while the Company’s current borrowing base and the amount outstanding under the Revolving Credit Facility indicate sufficient liquidity to execute our business plan for the foreseeable future, the amount that we may borrow under the Revolving Credit Facility is governed by compliance with the consolidated net leverage covenant as discussed in Note 6. A sustained decline in commodity prices could cause the Company to be out of compliance with future consolidated net leverage covenant ratios, which could reduce the Company’s effective liquidity.

Beginning as of January 1, 2019, the Company revised its estimated 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 Company’s total administrative costs.

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

	For the Quarter Ended								For the Six Months
	Ended June 30,					%			Ended June 30,						%
	2019		2018			Variance			2019			2018			Variance
	(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)		59,805		66,892			(11	)%		119,380			135,128			(12	)%
Crude oil and condensate (Bbl)		449		667			(33	)%		886			1,345			(34	)%
Total production (Mcfe)		62,499		70,894			(12	)%		124,696			143,198			(13	)%

Commodity Prices:
Natural gas ($/Mcf, excluding hedges)	$	2.11	$	2.11			—		$	3.12		$	2.39			31	%
Natural gas ($/Mcf, including realized hedges)	$	2.17	$	2.28			(5	)%	$	2.47		$	2.48			(1	)%
Oil and condensate ($/Bbl, excluding hedges)	$	60.80	$	64.71			(6	)%	$	57.30		$	62.79			(9	)%
Oil and condensate ($/Bbl, including realized hedges)	$	59.65	$	58.24			2	%	$	59.62		$	59.31			1	%

Revenues:
Natural gas sales	$	125,915	$	141,255			(11	)%	$	371,903		$	322,716			15	%
Oil sales		27,301		43,167			(37	)%		50,767			84,451			(40	)%
Other revenues		2,190		5,716			(62	)%		4,197			8,344			(50	)%
Total operating revenues	$	155,406	$	190,138			(18	)%	$	426,867		$	415,511			3	%

Derivatives:
Realized gain (loss) on commodity derivatives	$	3,420	$	6,662			(49	)%	$	(75,211	)	$	7,736			(1072	)%
Unrealized gain (loss) on commodity derivatives		68,234		(53,933	)		(227	)%		82,527			(61,539	)		(234	)%
Total Gain (loss) on commodity derivatives	$	71,654	$	(47,271	)		(252	)%	$	7,316		$	(53,803	)		(114	)%

Operating Costs and Expenses:
Lease operating expenses	$	15,889	$	23,645			(33	)%	$	33,114		$	45,409			(27	)%
Facility lease expense	$	6,543	$	6,526			0	%	$	13,188		$	12,682			4	%
Production taxes	$	16,443	$	18,883			(13	)%	$	46,618		$	42,153			11	%
Gathering fees	$	20,320	$	24,181			(16	)%	$	40,200		$	47,238			(15	)%
Depletion, depreciation and amortization	$	55,768	$	51,742			8	%	$	107,422		$	102,282			5	%
General and administrative expenses	$	7,433	$	2,063			260	%	$	14,485		$	14,752			(2	)%

Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.25	$	0.33			(24	)%	$	0.27		$	0.32			(16	)%
Facility lease expense	$	0.10	$	0.09			11	%	$	0.11		$	0.09			22	%
Production taxes	$	0.26	$	0.27			(4	)%	$	0.37		$	0.29			28	%
Gathering fees	$	0.33	$	0.34			(3	)%	$	0.32		$	0.33			(3	)%
Depletion, depreciation and amortization	$	0.89	$	0.73			22	%	$	0.86		$	0.71			21	%
General and administrative expenses	$	0.12	$	0.03			300	%	$	0.12		$	0.10			20	%

Production. During the quarter ended June 30, 2019, total production decreased on a gas equivalent basis to 62.5 Bcfe compared to 70.9 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 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 decrease in production on a comparative basis.

Commodity Prices – Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 5% to $2.17 per Mcf during the quarter ended June 30, 2019, as compared to $2.28 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 fourth quarter of 2020. See Note 9 for additional details relating to these derivative contracts. During the quarter ended June 30, 2019 and 2018, the Company’s average price for natural gas, excluding realized gains and losses on commodity derivatives, was $2.11 per Mcf.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased to $59.65 per barrel during the quarter ended June 30, 2019, as compared to $58.24 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 9 for additional details relating to these derivative contracts. During the three months ended June 30, 2019, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $60.80 per barrel as compared to $64.71 per barrel for the same period in 2018.

Revenues. During the quarter ended June 30, 2019, revenues decreased to $155.4 million as compared to $190.1 million for the same period in 2018. This decrease is primarily attributable to the decrease in total production and the decrease natural gas prices.

Lease Operating Expense. Lease operating expense (“LOE”) decreased to $15.9 million during the quarter ended June 30, 2019 as compared to $23.6 million during the same period in 2018. The decrease for the period was partially driven by the exclusion of the Utah production and related expenses in 2019 which approximated $3.0 million of expense for the quarter ended June 30, 2018. The sale of the Utah assets was completed in September 2018. Additionally, beginning in 2019, 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 $4.1 million compared to the same period in 2018. On a unit of production basis, LOE costs decreased to $0.25 per Mcfe during the quarter ended June 30, 2019 as compared with $0.33 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 field. 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 quarters ended June 30, 2019 and 2018, the Company recognized expense associated with the Lease Agreement of $6.5 million.

Production Taxes. During the quarter ended June 30, 2019, production taxes decreased to $16.4 million compared to $18.9 million during the same period in 2018, or $0.26 per Mcfe compared to $0.27 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 10.6% of revenues for the quarter ended June 30, 2019 and 9.9% of revenues for the same period in 2018.

Gathering Fees. During the quarter ended June 30, 2019, gathering fees decreased to $20.3 million compared to $24.2 million during the same period in 2018, related to decreased production volumes. On a per unit basis, gathering fees decreased slightly to $0.33 per Mcfe for the quarter ended June 30, 2019 as compared to $0.34 per Mcfe in the same period in 2018.

Depletion, Depreciation and Amortization. During the quarter ended June 30, 2019, depletion, depreciation and amortization (“DD&A”) expense increased to $55.8 million compared to $51.7 million for the same period in 2018. The increase in 2019 is primarily attributable to projected capital costs associated with proved undeveloped properties being at a higher cost and, therefore, the depletion rate per unit is greater than the current oil and gas property value per unit, offset slightly by decreased production volumes during the three months ended June 30, 2019. On a unit of production basis, the DD&A rate increased to $0.89 per Mcfe for the quarter ended June 30, 2019 compared to $0.73 per Mcfe for the same period in 2018.

General and Administrative Expenses. During the quarter ended June 30, 2019, general and administrative expenses increased to $7.4 million as compared to $2.1 million for the same period in 2018. The increase is primarily attributable to the revision in estimate of costs attributed to General and administrative expenses and LOE, as previously described. Additionally, the increase is a result of increased of legal fees related to the Company’s unsuccessful offer to exchange Ultra Resources, Inc.’s outstanding 7.125% Senior Notes due 2025 for new third lien senior secured notes, which was ultimately terminated in July 2019. The change was partially offset by a decrease in share-based compensation expense recognized during the quarter. On a per unit basis, general and administrative expenses increased to $0.12 per Mcfe for the quarter ended June 30, 2019 compared to $0.03 per Mcfe for the same period in 2018.

The Company analyzes the combined LOE and General and administrative expenses as controllable costs. The combined LOE and General and administrative expenses for the quarter ended June 30, 2019, was $0.37 per Mcfe compared to $0.36 per Mcfe for the same period in 2018. As previously noted, the slight increase in General and administrative expenses associated with the unsuccessful offering of third lien senior secured notes, partially offset by the exclusion of the Utah production and related expenses in 2019. The sale of the Utah assets was completed in September 2018.

Interest Expense. Interest expense decreased to $32.4 million during the quarter ended June 30, 2019 as compared to $37.7 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). The cash interest expense and PIK interest increased for the quarter ended June 30, 2019, as a result of the higher interest cost from the Second Lien Notes issued in December 2019. In conjunction with the issuance of the Second Lien Notes, the Company recognized a deferred premium which is amortized over the term of the Second Lien Notes.

Deferred Gain on Sale of Liquids Gathering System (“LGS”). During the quarter ended June 30, 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.

Other Expense. During the quarter ended June 30, 2019, the Company reached a settlement with the ONRR audit from 2010 through 2012, including an overriding royalty claim. Such amounts have been in dispute prior to the Company’s bankruptcy filing in 2016 and are described in more detail in Note 12.

Gain (Loss) on Commodity Derivatives. During the quarter ended June 30, 2019, the Company recognized a gain of $71.7 million, as compared to a loss of $47.3 million related to commodity derivatives for the same period in 2018. Of this total, the Company recognized $3.4 million related to a realized gain on commodity derivatives that were settled during the quarter ended June 30, 2019, as compared with $6.7 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 $68.2 million on commodity derivatives during the quarter ended June 30, 2019, as compared to an unrealized loss of $53.9 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(Loss). During the quarter ended June 30, 2019, the Company recognized income before income taxes of $57.0 million compared to a pretax loss of $20.5 million for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives, offset by the decreased net interest expense were the primary elements for the increase in net income during the quarter ended June 30, 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 June 30, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. During the quarter ended June 30, 2019, the Company recognized net income of $57.1 million, or $0.29 per diluted share, as compared to a net loss of $20.6 million, or $(0.10) per diluted share, for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives, offset by the decreased interest expense were the primary elements for the increase in net income during the quarter ended June 30, 2019, as compared to the same period in 2018.

Production. During the six months ended June 30, 2019, total production decreased by 13% on a gas equivalent basis to 124.7 Bcfe compared to 143.2 Bcfe for the same period in 2018, primarily attributable to a decrease in capital investment which occurred over the second half of 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. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased to $2.47 per Mcf during the six months ended June 30, 2019, as compared to $2.48 per Mcf for the same period in 2018. During the six months ended June 30, 2019, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through 2020. See Note 9 for additional details. During the six months ended June 30, 2019, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $3.12 per Mcf as compared to $2.39 per Mcf for the same period in 2018.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased slightly to $59.62 per barrel during the six months ended June 30, 2019 as compared to $59.31 per barrel for the same period in 2018. During the six months ended June 30, 2019, the Company entered into additional oil price commodity derivative contracts with contract periods extending through 2020. See Note 9 for additional details. During the six months ended June 30, 2019, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was $57.30 per barrel as compared to $62.79 per barrel for the same period in 2018.

Revenues. Increased average natural gas prices, partially offset by decreased production, resulted in revenues increasing to $426.9 million for the six months ended June 30, 2019 as compared to $415.5 million for the same period in 2018.

Lease Operating Expense. LOE decreased to $33.1 million during the six months ended June 30, 2019 compared to $45.4 million during the same period in 2018, primarily related to the exclusion of the Utah production and related expenses in 2019 which approximated $5.8 million for the six months ended June 30, 2019. The sale of the Utah assets was completed in September 2018. Additionally, beginning in 2019, 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 $6.9 million for the six months ended June 30, 2019. On a unit of production basis, LOE costs decreased to $0.27 per Mcfe during the six months ended June 30, 2019 compared to $0.32 per Mcfe during the same period in 2018.

Facility Lease Expense. During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale field and the Company entered into the Lease Agreement. The Lease Agreement provides for an initial term of 15 years, and annual rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. For the six months ended June 30, 2019, the Company recognized operating lease expense associated with the Lease Agreement of $13.2 million, or $0.11 per Mcfe, as compared to $12.7 million, or $0.09 per Mcfe, for the same period in 2018.

Production Taxes. During the six months ended June 30, 2019, production taxes were $46.6 million compared to $42.2 million during the same period in 2018, or $0.37 per Mcfe compared to $0.29 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 10.9% of revenues for the six months ended June 30, 2019 and 10.1% of revenues for the same period in 2018. The increase in per unit taxes is primarily attributable to increased natural gas prices during the six months ended June 30, 2019, as compared to the same period in 2018.

Gathering Fees. Gathering fees decreased to $40.2 million for the six months ended June 30, 2019, compared to $47.2 million during the same period in 2018, largely related to decreased production. On a per unit basis, gathering fees decreased slightly to $0.32 per Mcfe for the six months ended June 30, 2019 compared to $0.33 per Mcfe for the same period in 2018.

Depletion, Depreciation and Amortization. DD&A expenses increased to $107.4 million during the six months ended June 30, 2019, from $102.3 million for the same period in 2018. The increase in 2019 is primarily attributable to projected capital costs associated with proved undeveloped properties being at a higher cost and, therefore, the depletion rate per unit is greater than the current oil and gas property value per unit, offset slightly by decreased production volumes during the six months ended June 30, 2019. On a unit of production basis, the DD&A rate increased to $0.86 per Mcfe for the six months ended June 30, 2019 compared to $0.71 per Mcfe for the six months ended June 30, 2018.

General and Administrative Expenses. General and administrative expenses decreased to $14.5 million for the six months ended June 30, 2019 compared to $14.8 million for the same period in 2018. The decrease is primarily attributable to the stock incentive compensation expense that was incurred as of June 30, 2018, as part of the Management Incentive Plan. This was partially offset by the change in estimate of costs attributed to General and administrative expenses and LOE, as previously described. Furthermore, during the quarter the Company incurred the legal fees related to the Company’s unsuccessful offer to exchange Ultra Resources, Inc.’s outstanding 7.125% Senior Notes due 2025 for new third lien senior secured notes, which was ultimately terminated in July 2019. On a per unit basis, general and administrative expenses increased to $0.12 per Mcfe for the six months ended June 30, 2019 compared to $0.10 per Mcfe for the six months ended June 30, 2018.

The Company analyzes the combined LOE and General and administrative expenses as controllable costs. The combined LOE and General and administrative expenses for the six months ended June 30, 2019, was $0.39 per Mcfe compared to $0.42 per Mcfe for the same period in 2018. As previously noted, the slight decrease in controllable costs on a per unit basis is a result of the exclusion of the Utah production and related expenses in 2019. The sale of the Utah assets was completed in September 2018. This was partially offset by the incremental increase in General and administrative expenses associated with the unsuccessful offering of third lien senior secured notes.

Interest Expense. Interest expense decreased to $65.7 million during the six months ended June 30, 2019 compared to $73.6 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. During the six months ended June 30, 2018, the Company recognized $5.3 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale field during December 2012. 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.

Other Expense. During 2019, the Company reached a settlement with the ONRR audit from 2010 through 2012, including an overriding royalty claim. Such amounts have been in dispute prior to the Company’s bankruptcy filing in 2016 and are described in more detail in Note 12.

Gain (Loss) on Commodity Derivatives. During the six months ended June 30, 2019, the Company recognized a gain of $7.3 million related to commodity derivatives as compared to a loss of $53.8 million related to commodity derivatives during the same period in 2018. Of this total, the Company recognized $75.2 million related to a realized loss on commodity derivatives during the six months ended June 30, 2019, as compared with $7.7 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 gain (loss) on commodity derivatives also includes an $82.5 million unrealized gain on commodity derivatives for the six months ended June 30, 2019, as compared to a $61.5 million unrealized loss on commodity derivatives for 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. See Note 9 for additional details.

Pretax Income. The Company recognized income before income taxes of $97.6 million for the six months ended June 30, 2019 compared to $27.4 million for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives, offset by the decreased net interest expense were the primary elements for the increase in net income during the six months ended June 30, 2019, as compared to the same period in 2018.

Income Taxes. The Company recorded a current tax benefit of $0.2 million for the six months ended June 30, 2019. The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. For the six months ended June 30, 2019, the Company recognized net income of $97.8 million, or $0.49 per diluted share, as compared to $26.9 million, or $0.14 per diluted share, for the same period in 2018. The increase in earnings is driven by the operating income and operating expense elements together with the gain on commodity derivatives, offset by the decreased interest expense were the primary elements for the increase in net income during the six months ended June 30, 2019, as compared to the same period in 2018.

Overview. During the six months ended June 30, 2019, we funded our operations primarily through cash flows from operating activities and periodic borrowings under the Revolving Credit Facility (defined below). At June 30, 2019, the Company has cash and cash equivalents of $5.2 million and $59.0 million outstanding borrowings under the Revolving Credit Facility. The borrowing base attributed to the Revolving Credit Facility 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 in 2022 through 2025. 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, levels of capital investment, and availability under the Revolving Credit Facility. The Company’s anticipated liquidity needs are highly sensitive to changes in each of these and other factors.

Capital Expenditures. For the six months ended June 30, 2019, total capital expenditures were $176.8 million. During this period, the Company participated in 53 gross (52.5 net) vertical wells and 1 gross (0.9 net) horizontal wells, together with 16 gross (5.3 net) vertical wells operated by others.

2019 Capital Investment Plan. Based on the decision in the third quarter to move to a one rig operated drilling program, the Company’s 2019 capital investment forecast has been adjusted to a range of $260 million to $290 million, a reduction of approximately $60 million from the midpoint of the initial capital investment guidance. Our capital investment for the six months ended June 30, 2019, totaled $176.8 million. We expect to fund future capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility, and cash on hand. We expect to allocate all of the capital 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 and estimates of economic returns on the capital investment. Additionally, future estimates of capital expenditures 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.

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. At June 30, 2019, Ultra Resources had $59.0 million of outstanding borrowings under the Revolving Credit Facility, and with total commitments of $325.0 million. The next borrowing base redetermination is scheduled for October 1, 2019.

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. The applicable margin is increased by 25 basis points in the event the Company’s leverage ratio, as defined, exceeds 4.00 to 1.00. 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 loans mature on January 12, 2022.

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. The Company expects to be in compliance with these requirements while the requirements remain effective. The duration of the hedging requirements is an 18-month period from the end of a given quarter.

Borrowings under the Term Loan Agreement bear interest at a rate equal to either (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 initial aggregate principal amount beginning on June 30, 2019. Borrowings under the Term Loan Agreement mature on April 12, 2024.

The Term Loan Agreement also contains customary affirmative and negative covenants, and at June 30, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement. Refer to Note 6 Long Term Debt in the 2018 Form 10-K for additional details on the terms of the Term Loan Agreement.

Operating Activities. During the six months ended June 30, 2019, net cash provided by operating activities was $215.1 million compared to $205.8 million for the same period in 2018. The increase in net cash provided by operating activities is attributable to an increase in net income and an increase in working capital.

Investing Activities. During the six months ended June 30, 2019, net cash used in investing activities was $178.3 million as compared to $272.0 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. In 2018, the Company was drilling vertical and horizontal wells which resulted in higher capital costs. During 2019, the Company is primarily focused on drilling vertical wells. Additionally, in the second quarter of 2019, the Company elected to release a drilling rig and reduce its operated rig count in the Pinedale field from three to two. In the third quarter of 2019, the Company plans to reduce its operated drilling program to a single rig.

Financing Activities. During the six months ended June 30, 2019, net cash used in financing activities was $48.0 million as compared to net cash provided by financing activities of $55.3 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 six months ended June 30, 2019.

Please refer to the corresponding section in Part II, Item 7 and to Note 1, Significant Accounting Policies, included in Part II, Item 8 of our 2018 Form 10-K for discussion of our accounting policies and estimates.

Please refer to, Significant Accounting Policies, under Part I, Item 1 of this report for new accounting pronouncements.

The Company did not have any off-balance sheet arrangements as of June 30, 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 June 30, 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.

Fair Value of Commodity Derivatives: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC 815”). Derivative contracts that do not qualify for hedge accounting treatment are recorded at fair value as derivative assets and liabilities on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense on the Condensed Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. 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. The Company does not apply hedge accounting to any of its derivative instruments. See Note 10 of this report for details regarding the fair value of the derivative contracts described below.

Commodity Derivative Contracts: At June 30, 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.

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

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 and six months ended June 30, 2019 and 2018:

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 June 30, 2019, the weighted average interest rate on our variable rate debt was 6.3% per year. If the balance of our variable interest rate at June 30, 2019 were to remain constant, a 10% change in the variable market interest rates would impact our cash flows by approximately $1.3 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 9 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 June 30, 2019.

There were no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

See Note 12 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, results of operations, or cash flows.

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 and the Quarterly Report on the Form 10-Q for the period ended March 31, 2019. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

Our common shares were recently delisted from The NASDAQ Global Select Market and trade in an over-the-counter market. This may negatively affect our stock price and liquidity.

As previously disclosed, on January 29, 2019, we received written notice from the Listing Qualifications Staff of The NASDAQ Stock Market LLC notifying us that our common shares over a period of 30 consecutive trading days closed below the average closing price of $1.00 per share, which is the minimum average closing price required to maintain listing under NASDAQ Listing Rule 5450(a)(1). Further, as previously disclosed, on July 30, 2019, we received written notice from the Listing Qualifications Staff of The NASDAQ Global Select Market that our common shares would be delisted from The NASDAQ Global Select Market on August 8, 2019 because we have not regained compliance within the automatic period of 180 calendar days provided to us in accordance with NASDAQ Listing Rule 5810(c)(3)(A).

Trading in our common shares is now conducted in the over-the-counter markets on the OTC Bulletin Board and the liquidity of our common shares may likely be reduced or impaired, not only in the number of shares which could be purchased and sold, but also through delays in the timing of the transactions. There may also be a reduction in our coverage by security analysists and the news media, thereby resulting in potential lower prices for our common shares than might otherwise prevail. The delisting of our common shares may also result in other adverse consequences, including lower demand for our shares, adverse publicity and a reduced interest in our Company from investors, analysts and other market participants.

Investments in securities trading on the over-the-counter markets are generally less liquid than investments in securities trading on a national securities exchange. In addition, the trading of our common shares on the over-the-counter markets could have other negative implications, including the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional investor interest in our common shares. This could further depress the trading price of our common shares and could also have a long-term adverse effect on our ability to raise capital.

There can be no assurance that our common shares will continue to trade on the over-the-counter markets or that any public market for the common shares will exist in the future, whether broker-dealers will continue to provide public quotes of the common shares on this market, whether the trading volume of the common shares will be sufficient to provide for an efficient trading market, whether quotes for the common shares may be blocked in the future, or that we will be able to relist the common shares on a national securities exchange.

The following table provides information about purchases made by the Company (as defined in Rule 10b-18(a)(3) under the Exchange Act) during the quarter ended June 30, 2019, of shares of common stock, which is the sole class of equity securities registered by the Company pursuant to Section 12 of the Exchange Act:

On April 15, 2019, the Board of Directors of Ultra Petroleum Corp. (the “Company”) appointed Mr. James N. Whyte as Senior Vice President and Chief Human Resources Officer of the Company, effective April 22, 2019. Mr. Whyte, age 60, previously served as Executive Vice President for Intrepid Potash, Inc. from August 2016 to 2018. Prior to that, he served as the Executive Vice President of Human Resources and Risk Management from 2007 to August 2016. Mr. Whyte joined Intrepid Mining LLC as Vice President of Human Resources and Risk Management in 2004. Prior to joining Intrepid, Mr. Whyte spent 17 years in the property and casualty insurance industry including roles with Marsh and McLennan, Incorporated, American Re-Insurance, and a private insurance brokerage firm he founded. Mr. Whyte was a director of American Eagle Energy Corporation from November 2013 to October 2016. Mr. Whyte earned a Bachelors of Business Administration from Southern Methodist University and a Masters of Business Administration from the University of Denver.

Mr. Whyte was not appointed pursuant to any arrangement or understanding with any other person, and there are no transactions with Mr. Whyte that would be reportable under Item 404(a) of Regulation S-K.

On April 22, 2019, the Company entered into an employment agreement with Mr. Whyte (the “Whyte Employment Agreement”). The Whyte Employment Agreement provides Mr. Whyte with an initial base salary of $285,000 per year; eligibility to receive cash-based incentive compensation pursuant to the Company’s short-term incentive programs as in effect from time to time with a target amount equal to 50% of his annual base salary; and eligibility to receive grants of equity-based incentive compensation in the form of restricted stock units and performance-based restricted stock units. The Whyte Employment Agreement also provides Mr. Whyte with other benefits, including health insurance and the opportunity to participate in a 401(k) plan, to the same extent as such benefits are available to the Company’s other salaried employees.

The Whyte Employment Agreement provides that either the Company or Mr. Whyte can terminate his employment relationship. The Company’s right to terminate the employment relationship is subject to its obligation to make certain severance payments and provide certain other benefits to Mr. Whyte, depending upon the circumstances under which the employment relationship is terminated. Under the Whyte Employment Agreement, the Company is generally not obligated to provide any severance payments or benefits if Mr. Whyte is terminated for cause or if Mr. Whyte resigns without good reason, and the Company is generally obligated to

provide the severance payments and benefits if the Company terminates him without cause, or if he resigns with good reason (each, as defined in the Whyte Employment Agreement). In the event Mr. Whyte’s employment is terminated by the Company without cause, or in the event Mr. Whyte resigns for good reason, the Company will be obligated (subject to Mr. Whyte’s timely execution and non-revocation of a release of claims) to provide Mr. Whyte with the following severance benefits: (i) payment of any accrued but unpaid compensation as of the termination date, (ii) payment of a portion of Mr. Whyte’s annual cash incentive compensation based on the Company’s actual performance at the conclusion of the performance period without proration, (iii) a lump-sum payment equal to Mr. Whyte’s then-current annual base salary, and (iv) continued coverage under the Company’s health and welfare benefits programs for the shorter of (x) 12 months following Mr. Whyte’s termination and (y) the date on which Mr. Whyte is eligible for comparable coverage under a subsequent employer.

The Whyte Employment Agreement also contains various other ordinary and customary covenants for the Company’s benefit by Mr. Whyte with respect to inventions, non-competition, non-solicitation, non-disparagement, confidentiality, and cooperation and assistance with respect to litigation or other adjudicatory proceedings.

The foregoing description of the Whyte Employment Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Whyte Employment Agreement, of which a copy is attached hereto as Exhibit 10.3 and is incorporated herein by reference.

On April 17, 2019, in connection with Mr. Whyte’s appointment as Chief Human Resources Officer, the Company granted an aggregate of 72,000 restricted stock units (“RSUs”) to Mr. Whyte, effective April 22, 2019, pursuant to a restricted stock unit grant agreement (the “Whyte RSU Grant Agreement”). The Whyte RSU Grant Agreement is subject to the terms and conditions of the Company’s 2017 Stock Incentive Plan, as amended and restated, and generally provides for the following terms:

The foregoing description of the Whyte RSU Grant Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the form of RSU Grant Agreement, of which a copy was filed as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed on May 9, 2019.

On April 15, 2019, the Board of Directors of the Company appointed Mr. Kason D. Kerr as Vice President, General Counsel and Corporate Secretary of the Company, effective April 22, 2019. Mr. Kerr, age 35, previously worked at Halcon Resources Corporation, a publicly traded exploration and production company, from September 2012 to April 1019. He most recently served as Halcon’s Deputy General Counsel, Corporate, where he worked primarily on the company’s capital markets transactions, acquisitions and divestitures, upstream and midstream activities. Prior to that, he was a capital markets attorney at the law firm of Latham & Watkins LLP and a corporate attorney at the law firm of Bracewell LLP. Mr. Kerr holds a B.B.A. degree in finance, with honors, from the University of Texas at Austin and a J.D. from the University of Houston Law Center.

Mr. Kerr was not appointed pursuant to any arrangement or understanding with any other person, and there are no transactions with Mr. Kerr that would be reportable under Item 404(a) of Regulation S-K.

On April 22, 2019, the Company entered into an employment agreement with Mr. Kerr (the “Kerr Employment Agreement”). The Kerr Employment Agreement provides Mr. Kerr with an initial base salary of $350,000 per year; eligibility to receive cash-based incentive compensation pursuant to the Company’s short-term incentive programs as in effect from time to time with a target amount equal to 75% of his annual base salary; and eligibility to receive grants of equity-based incentive compensation in the form of restricted stock units and performance-based restricted stock units. The Kerr Employment Agreement also provides Mr. Kerr with other benefits, including health insurance and the opportunity to participate in a 401(k) plan, to the same extent as such benefits are available to the Company’s other salaried employees.

The Kerr Employment Agreement provides that either the Company or Mr. Kerr can terminate his employment relationship. The Company’s right to terminate the employment relationship is subject to its obligation to make certain severance payments and provide certain other benefits to Mr. Kerr, depending upon the circumstances under which the employment relationship is terminated. Under the Kerr Employment Agreement, the Company is generally not obligated to provide any severance payments or benefits if Mr. Kerr is terminated for cause or if Mr. Kerr resigns without good reason, and the Company is generally obligated to provide the severance payments and benefits if the Company terminates him without cause, or if he resigns with good reason (each, as defined in the Kerr Employment Agreement). In the event Mr. Kerr’s employment is terminated by the Company without cause, or in the event Mr. Kerr resigns for good reason, the Company will be obligated (subject to Mr. Kerr’s timely execution and non-revocation of a release of claims) to provide Mr. Kerr with the following severance benefits: (i) payment of any accrued but unpaid compensation as of the termination date, (ii) payment of a portion of Mr. Kerr’s annual cash incentive compensation based on the Company’s actual performance at the conclusion of the performance period without proration, (iii) a lump-sum payment equal to Mr. Kerr’s then-current annual base salary, and (iv) continued coverage under the Company’s health and welfare benefits programs for the shorter of (x) 12 months following Mr. Kerr’s termination and (y) the date on which Mr. Kerr is eligible for comparable coverage under a subsequent employer.

The Kerr Employment Agreement also contains various other ordinary and customary covenants for the Company’s benefit by Mr. Kerr with respect to inventions, non-competition, non-solicitation, non-disparagement, confidentiality, and cooperation and assistance with respect to litigation or other adjudicatory proceedings.

The foregoing description of the Kerr Employment Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the Kerr Employment Agreement, of which a copy is attached hereto as Exhibit 10.2 and is incorporated herein by reference.

On April 17, 2019, in connection with Mr. Kerr’s appointment as General Counsel and Corporate Secretary, the Company granted an aggregate of 255,000 restricted stock units (“RSUs”) to Mr. Kerr, effective April 22, 2019, pursuant to a restricted stock unit grant agreement (the “Kerr RSU Grant Agreement”). The Kerr RSU Grant Agreement is subject to the terms and conditions of the Company’s 2017 Stock Incentive Plan, as amended and restated, and generally provides for the following terms:

The foregoing description of the Kerr RSU Grant Agreement does not purport to be complete and is qualified in its entirety by reference to the full text of the form of the RSU Grant Agreement, of which a copy was filed as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q filed on May 9, 2019.

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)

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements	3

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	33

ITEM 4.	Controls and Procedures	35

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	36

ITEM 1A.	Risk Factors	36

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

ITEM 3.	Defaults upon Senior Securities	37

ITEM 4.	Mine Safety Disclosures	37

ITEM 5.	Other Information	37

ITEM 6.	Exhibits	41

	Signatures	43

	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

	June 30,			December 31,
	2019			2018
Proven properties:
Acquisition, equipment, exploration, drilling and abandonment costs	$	11,755,535		$	11,577,281
Less: Accumulated depletion, depreciation and amortization		(10,178,996	)		(10,079,554	)
Total Oil and gas properties, net	$	1,576,539		$	1,497,727

	June 30, 2019
	Principal repayment obligation (1)			Unamortized DFC and discounts (2)			Unamortized premium		Carrying value
Credit Facility, secured, due January 2022	$	59,000		$	—		$	—	$	59,000
Term Loan, secured, due April 2024		973,247			(24,722	)		—		948,525
Second Lien Notes, secured, due July 2024		578,072			—			225,085		803,157
6.875% Notes, unsecured, due April 2022		150,439			(13,201	)		—		137,238
7.125% Notes, unsecured, due April 2025		225,000			(13,712	)		—		211,288
Total debt	$	1,985,758		$	(51,635	)	$	225,085	$	2,159,208
Less: Current maturities		(9,750	)		—			—		(9,750	)
Total long-term debt, net	$	1,976,008		$	(51,635	)	$	225,085	$	2,149,458

	For the Three Months Ended					For the Six Months Ended
	June 30,					June 30,
	2019		2018			2019		2018
	(Share amounts in 000's)
Net income (loss)	$	57,105	$	(20,555	)	$	97,780	$	26,933
Weighted average common shares outstanding - basic		197,514		197,054			197,449		196,803
Effect of dilutive instruments		555		—			640		—
Weighted average common shares outstanding - diluted		198,069		197,054			198,089		196,803
Net income (loss) per common share - basic	$	0.29	$	(0.10	)	$	0.50	$	0.14
Net income (loss) per common share - fully diluted	$	0.29	$	(0.10	)	$	0.49	$	0.14
Number of contingently issuable shares, including warrants, that are not included in the diluted earnings per share denominator as the performance or market criteria have not been met		20,218		2,636			20,109		2,636

	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

	For the Three Months				For the Six Months Ended
	Ended June 30,				Ended June 30,
	2019		2018		2019		2018
Total cost of share-based payment plans	$	745	$	2,263	$	1,872	$	13,173
Amounts capitalized in oil and gas properties and equipment	$	64	$	952	$	351	$	3,051
Amounts charged against income, before income tax benefit	$	681	$	1,311	$	1,521	$	10,122
Amount of related income tax benefit recognized in income before valuation allowance	$	143	$	275	$	319	$	2,126

Type/Year	Index	Total Volumes		Weighted Average (“WA”) Price per Unit			Fair Value - June 30, 2019
		(in millions)					Asset (Liability)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2019 (July through December)	NYMEX-Henry Hub		90.5	$	2.78		$	37,790
2020	NYMEX-Henry Hub		24.6		2.78			2,979

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2019 (July through December)	NW Rockies Basis Swap		63.5	$	(0.54	)	$	(13,336	)
2020	NW Rockies Basis Swap		11.4		(0.17	)		1,114

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2019 (July through December)	NYMEX-WTI		0.7	$	59.06		$	601
2020	NYMEX-WTI		0.5		60.31			1,727

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	58,198	$	—	$	58,198
Long-term derivative asset (1)		—		11,571		—		11,571
Total derivative instruments	$	—	$	69,769	$	—	$	69,769
Liabilities:
Current derivative liability	$	—	$	20,692	$	—	$	20,692
Long-term derivative liability (2)		—		9,382		—		9,382
Total derivative instruments	$	—	$	30,074	$	—	$	30,074

	June 30, 2019				December 31, 2018
	Principal		Estimated		Principal		Estimated
	repayment obligation		Fair Value		repayment obligation		Fair Value
Credit Facility, secured, due January 2022	$	59,000	$	59,000	$	104,000	$	104,000
Term Loan, secured, due April 2024		973,247		729,935		975,000		858,000
Second Lien Notes, secured, due July 2024		578,072		235,854		545,000		395,125
6.875% Notes, unsecured, due April 2022		150,439		16,548		195,035		68,262
7.125% Notes, unsecured, due April 2025		225,000		22,500		225,000		69,750
Total	$	1,985,758	$	1,063,837	$	2,044,035	$	1,495,137

	June 30, 2019
Operating Leases
Operating lease right-of-use assets	$	125,110

Operating lease liabilities	$	11,489
Long-term operating lease liabilities		113,642
Total operating lease liabilities	$	125,131

Weighted Average Remaining Lease Term
Operating leases	8.5 years
Weighted Average Discount Rate
Operating leases		7.91	%

	Six Months Ended
	June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	10,455

	Operating Leases
For the year ending December 31,
2019 (remaining)	$	10,434
2020		20,853
2021		20,750
2022		20,327
2023		19,719
Thereafter		78,239
Total lease payments	$	170,322
Less: imputed interest		(45,191	)
Total	$	125,131

Period	Total Number of Shares Purchased (1)		Weighted Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Program
April 2019		—		—	—	—
May 2019		190,872		0.39	—	—
June 2019		—		—	—	—
Total		190,872		0.39	—	—

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		Restated Articles of Reorganization of Ultra Petroleum Corp.

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 dated as of April 22, 2019 by and between Ultra Petroleum Corp. and Kason Kerr.
*#10.3		Employment Agreement dated as of April 22, 2019 by and between Ultra Petroleum Corp. and Jamie Whyte.

#10.4		Employment Agreement dated as of June 17, 2019 by and between Ultra Petroleum Corp. and Mark Solomon (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on June 20, 2019).

#10.5		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Form 10-Q filed by Ultra Petroleum Corp. on May 9, 2019).

#10.6		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.5 to the Form 10-Q filed by Ultra Petroleum Corp. on May 9, 2019).
*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: August 9, 2019

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

Date: August 9, 2019

	By:	/s/ Mark T. Solomon
		Name:	Mark T. Solomon
		Title:	Vice President – Controller and Chief Accounting Officer
Date: August 9, 2019