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

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

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

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)~~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 ~~25, 2018~~31, 2019 was ~~197,054,917.~~

	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,
	2018			2017			2018			2017			For the Three Months Ended June 30,						For the Six Months Ended June 30,
	(Unaudited)												2019			2018			2019			2018
	(Amounts in thousands of U.S. dollars, except per share data)												(In thousands, except per share data)
Revenues:
Natural gas sales	$	141,255		$	179,997		$	322,716		$	368,848		$	125,915		$	141,255		$	371,903		$	322,716
Oil sales		43,167			30,732			84,451			62,081			27,301			43,167			50,767			84,451
Other revenues		5,716			1,928			8,344			2,687			2,190			5,716			4,197			8,344
Total operating revenues		190,138			212,657			415,511			433,616			155,406			190,138			426,867			415,511
Expenses:
Lease operating expenses		23,645			23,089			45,409			46,225			15,889			23,645			33,114			45,409
Facility lease expense		6,526			5,226			12,682			10,452			6,543			6,526			13,188			12,682
Production taxes		18,883			21,754			42,153			43,887			16,443			18,883			46,618			42,153
Gathering fees		24,181			20,642			47,238			41,571			20,320			24,181			40,200			47,238
Depletion, depreciation and amortization		51,742			38,673			102,282			70,427			55,768			51,742			107,422			102,282
General and administrative		2,063			25,009			14,752			26,061			7,433			2,063			14,485			14,752
Other operating expenses, net														15,281			639			16,085			853
Total operating expenses		127,040			134,393			264,516			238,623			137,677			127,679			271,112			265,369
Operating income		63,098			78,264			150,995			194,993			17,729			62,459			155,755			150,142
Other income (expense), net:
Interest expense		(37,715	)		(29,425	)		(73,552	)		(114,872	)		(32,376	)		(37,715	)		(65,703	)		(73,552	)
(Loss) gain on commodity derivatives		(47,271	)		20,717			(53,803	)		7,499
Gain (loss) on commodity derivatives														71,654			(47,271	)		7,316			(53,803	)
Deferred gain on sale of liquids gathering system		2,638			2,638			5,276			5,276			—			2,638			—			5,276
Contract settlement expense		—			—			—			(52,707	)
Other income (expense), net		(1,296	)		27			(1,541	)		(119	)		(43	)		(657	)		243			(688	)
Total other (expense) income, net		(83,644	)		(6,043	)		(123,620	)		(154,923	)		39,235			(83,005	)		(58,144	)		(122,767	)
Reorganization items, net		—			426,816			—			369,270
(Loss) income before income tax provision		(20,546	)		499,037			27,375			409,340
Income tax provision		9			—			442			2
Net (loss) income	$	(20,555	)	$	499,037		$	26,933		$	409,338
Basic (loss) earnings per share:
Net (loss) income per common share - basic	$	(0.10	)	$	2.76		$	0.14		$	3.13
Fully diluted (loss) earnings per share:
Net (loss) income per common share - fully diluted	$	(0.10	)	$	2.76		$	0.14		$	3.12
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		197,054			180,964			196,803			130,770			197,514			197,054			197,449			196,803
Weighted average common shares outstanding - fully diluted		197,054			181,033			196,803			131,078			198,069			197,054			198,089			196,803

~~See~~The accompanying notes toare an integral part of these unaudited condensed consolidated financial statements.

CONDENSED CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

June 30,

December 31,

2018

2017

(Unaudited)

(Amounts in thousands of
U.S. dollars, except share data)

ASSETS

Current Assets:

Cash and cash equivalents

$
5,685

$
16,631

Restricted cash

1,688

1,638

Oil and gas revenue receivable

64,123

86,487

Joint interest billing and other receivables

20,865

16,616

Derivative assets

14,480

16,865

Income tax receivable

6,431

10,091

Inventory

17,747

13,450

Other current assets

3,143

5,647

Total current assets

134,162

167,425

Oil and gas properties, net, using the full cost method of accounting:

Proven

1,485,980

1,325,068

Property, plant and equipment, net

10,887

9,569

Other assets

10,831

10,920

Total assets

$
1,641,860

$
1,512,982

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:

Accounts payable

$
41,426

$
59,951

Accrued liabilities

75,806

80,268

Production taxes payable

55,048

51,352

Current portion of long-term debt

2,438

—

Interest payable

20,759

24,406

Derivative liabilities

54,891

—

Capital cost accrual

18,030

32,513

Total current liabilities

268,398

248,490

Long-term debt

2,176,408

2,116,211

Deferred gain on sale of liquids gathering system

99,912

105,189

Other long-term obligations

211,968

197,728

Total liabilities

2,756,686

2,667,618

Commitments and contingencies (Note 9)

Shareholders' equity:

Common stock - no par value; authorized - unlimited; issued and outstanding - 197,053,583 and 196,346,736 at June 30, 2018 and December 31, 2017, respectively

2,129,191

2,116,018

Treasury stock

(49
)

(49
)
Retained loss

(3,243,968
)

(3,270,605
)
Total shareholders' deficit

(1,114,826
)

(1,154,636
)
Total liabilities and shareholders' equity

$
1,641,860

$
1,512,982

	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	)

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

		Six Months Ended June 30,
		2018				2017				Six Months Ended June 30,
		(Unaudited)								2019			2018
		(Amounts in thousands of U.S. dollars)								(In thousands)
Operating activities - cash provided by (used in):					��
Net income for the period		$	26,933			$	409,338			$	97,780		$	26,933
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization			102,282				70,427				107,422			102,282
Unrealized loss (gain) on commodity derivatives			61,539				(8,367	)			(82,527	)		61,539
Deferred gain on sale of liquids gathering system			(5,276	)			(5,276	)			—			(5,276	)
Stock compensation			10,122				26,264				1,521			10,122
Non-cash reorganization items, net			—				(431,579	)
Payable-in-kind (“PIK”) interest payable											6,722			—
Amortization of premium on debt exchange											(20,572	)		—
Amortization of deferred financing costs			5,510				2,224				6,308			5,510
Other			207				(1,060	)			1,915			207
Net changes in operating assets and liabilities:
Accounts receivable			17,738				283				86,645			17,738
Other current assets			3,783				7,972				(636	)		3,783
Other non-current assets			338				144				59			338
Accounts payable			(18,525	)			30,245				(1,449	)		(18,525	)
Accrued liabilities			(4,116	)			(3,368	)			(5,519	)		(4,116	)
Production taxes payable			3,696				869				(3,214	)		3,696
Interest payable			(3,647	)			32,438				6,052			(3,647	)
Other long-term obligations			(1,647	)			3,808				8,187			(1,647	)
Income taxes payable/receivable			6,844				2,099				6,431			6,844
Net cash provided by operating activities			205,781				136,461				215,125			205,781
Investing Activities - cash provided by (used in):
Oil and gas property expenditures			(250,966	)			(225,057	)			(176,791	)		(250,966	)
Change in capital cost accrual			(14,483	)			7,740
Change in capital cost accrual and accounts payable											(2,743	)		(14,483	)
Inventory			(4,140	)			(2,276	)			1,567			(4,140	)
Purchase of capital assets			(2,389	)			(756	)			(373	)		(2,389	)
Net cash used in investing activities			(271,978	)			(220,349	)			(178,340	)		(271,978	)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement			450,000				144,000				431,000			450,000
Payments under Credit Agreement			(392,000	)			(67,000	)			(476,000	)		(392,000	)
Borrowings under Term Loan			—				800,000
Extinguishment of long-term debt - (chapter 11)			—				(2,459,000	)
Proceeds from issuance of Senior Notes			—				1,200,000
Payments under Term Loan											(2,438	)		—
Deferred financing costs			(638	)			(61,861	)			(488	)		(638	)
Shares issued, net of transaction costs			—				573,774
Repurchased shares/net share settlements			(2,061	)			(9,581	)			(71	)		(2,061	)
Net cash provided by financing activities			55,301				120,332
Net cash used in financing activities											(47,997	)		55,301
(Decrease) increase in cash during the period			(10,896	)			36,444				(11,212	)		(10,896	)
Cash, cash equivalents, and restricted cash, beginning of period			18,269				405,049				19,305			18,269
Cash, cash equivalents and restricted cash, end of period	Cash, cash equivalents and restricted cash, end of period	$	7,373			$	441,493		Cash, cash equivalents and restricted cash, end of period	$	8,093		$	7,373

~~See~~The accompanying notes toare 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).~~noted.

Ultra Petroleum Corp. ~~(the~~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. ~~The Company~~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 ~~other than the balance sheet data as of December 31, 2017, are unaudited and were~~have been prepared ~~from the Company’s records, but do not include all disclosures required by~~in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”)~~. Balance sheet data as~~ for interim financial information and with the instructions to Form 10-Q and Article 10 of ~~December 31, 2017 was derived from~~Regulation S-X. Accordingly, they do not include all of the ~~Company’s audited~~information and footnotes required by U.S. GAAP for complete financial statements. ~~The Company’s~~In the opinion of management, ~~believes that these financial statements include~~ all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by GAAP and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

~~(a)~~ ~~Basis of Presentation and Principles of Consolidation:~~ The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The Company presents its financial statements in accordance with GAAP. All inter-company transactions and balances have been ~~eliminated upon consolidation.~~

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

~~(c)~~ ~~Restricted Cash:~~ Restricted cash represents cash received by the Company from production sold where the final division of ownership of the production is unknown or in dispute. Restricted cash at June 30, 2017 also includes the funds deposited in the $400.0 million reserve fund, pending resolution of make-whole and post-petition interest claims (see Note 9) and funds deposited in the $35.0 million reserve fundincluded. Operating results for the ~~purpose of paying allowed and unpaid professional fees under the Plan (see Note 10).~~

~~The Company follows ASU 2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash~~ and reports the change in cash, cash equivalents, and restricted cash in total on the Consolidated Statements of Cash Flows. See the following table for a reconciliation of cash, cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statements of Cash Flows.

~~(d)~~ ~~Accounts Receivable, net:~~ Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

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

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

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

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

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down during the six months ended June 30, 2018 or 2017.

~~(g)~~ ~~Inventories:~~ Inventory primarily includes $16.4 million in pipe and production equipment that will be utilized during the 2018 drilling program and $1.3 million in crude oil inventory as of June 30, 2018. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market.

~~(h)~~ ~~Deferred Financing Costs:~~ ~~The Company follows ASU No. 2015-3,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs~~ and includes the costs for issuing debt, including issuance discounts, except those related to the Revolving Credit Facility (as defined below), as a direct deduction from the carrying amount of the related debt liability. Costs related to the issuance of the Revolving Credit Facility are recorded as an asset in the Consolidated Balance Sheets.

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

~~(j)~~ ~~Income Taxes:~~ Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are recorded related to deferred tax assets based on the “more likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

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

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. For the quarterthree and six months ended June 30, ~~2018 and 2017, the Company had 2.6 million and 4.2 million contingently issuable shares that~~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 ~~diluted earnings per share denominator as~~Company’s annual report on Form 10-K for the ~~performance or market criteria have not been met. See~~year ended December 31, 2018.

Significant Accounting Policies: The significant accounting policies followed by the Company are set forth in Note ~~5 for additional details.~~

~~(l)~~ ~~Use of Estimates:~~ ~~Preparation of~~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 accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of thethis report. These unaudited condensed consolidated financial statements ~~and~~should be read in conjunction with the ~~reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.~~

~~(m)~~ ~~Accounting for Share-Based Compensation:~~ ~~The Company measures and recognizes compensation expense for all share-based payment awards made~~2018 Form 10-K. Refer to ~~employees and directors, including employee stock options, based on estimated fair values in accordance with FASB ASC Topic 718, Compensation – Stock Compensation.~~

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

~~(o)~~ ~~Asset Retirement Obligation:~~ ~~The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties~~11, Leases, for the asset retirement cost. Accretion expense is recognized over the estimated productive life of the related assets. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

~~(p)~~ ~~Revenue Recognition:~~ The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. On January 1, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosuresupdated policies related to the ~~Company’s adoption~~implementation of ~~this standard.~~

~~(q)~~ASU 2016-02, ~~Other revenues~~: ~~Other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed~~Leases (Topic 842).

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

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

~~(t)~~ ~~Recent~~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) ~~(“ASU No. 2016-02”~~, and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as ��ASC 842”). The guidance requires ~~that~~ lessees ~~will be required~~ 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. ~~The ASU will~~ASC 842 also ~~require~~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. ~~To facilitate compliance with this ASU,~~ The Company adopted ASC 842 and applicable amendments on January 1, 2019, using the modified retrospective approach. The Company ~~has formed an implementation work team, developed a project plan, educated departments affected by~~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 ~~begun~~had an effect on the ~~process~~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 ~~reviewing its contract portfolio~~ROU assets and ~~continues~~lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to ~~evaluate its systems, processes, and internal controls during 2018.~~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 ~~January~~August 2018, the FASB issued ASU No. ~~2018-01,~~2018-13, ~~Land Easement Practical Expedient~~Fair Value Measurements (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for ~~Transition to Topic 842~~Fair Value Measurement (“ASU ~~No. 2018-01”~~2018-13”)~~, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired before~~. The amendments in ASU 2018-13 modify the ~~entity’s~~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 ~~that were not previously accounted for as leases. For public companies,~~ the ~~standards will take effect~~timing of when such losses are recorded. ASU 2016-13 is effective for fiscal years, and interim periods within those ~~fiscal~~ years, beginning after December 15, ~~2018 with earlier application permitted.~~2019. Early adoption is permitted for fiscal years, and interim periods ~~Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.~~ within those years, beginning after December 15, 2018. The Company is ~~still evaluating~~currently assessing the impact of ASU ~~No. 2016-02 and ASU No. 2018-01~~2016-13 on its consolidated financial ~~statements~~.

~~Stock Compensation. In May 2017, the FASB issued ASU 2017-09,~~ ~~Compensation-Stock Compensation (Topic 718)~~ ~~(“ASU No. 2017-09”)~~, which is intended to clarify and reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s consolidated financial statements.

~~Derivatives.~~ ~~In August 2017, the FASB issued ASU 2017-12,~~ ~~Derivatives and Hedging (Topic 815)~~ (“ASU No. 2017-12”), which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company does not expect the adoption of ASU No. 2017-12 to have a material impact on its consolidated financial statements.

requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.

On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the cumulative impact of adopting Topic 606, with the impact related to changing from the entitlements method to the sales method to account for wellhead imbalances. The impact to revenues for the six months ended June 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

~~In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our consolidated income statement for the six months ended June 30, 2018 is as follows:~~

The change to sales of natural gas is due to the change from using the entitlements method for production imbalances to the sales method. The Company evaluated the contracts for sales of oil and natural gas utilizing the principal versus agent indicators, noting no change in revenue recognition resulted from the analysis.

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) ~~the~~a lease automatic custody transfer ~~(LACT)~~ meter, ~~for Wyoming condensate,~~ (b) ~~the~~a tank battery, ~~for Utah wax/condensate,~~ 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. In conjunction with the adoption of ASC 606, for the six months ended June 30, 2018, there was no change to the method used to recognize oil sales and there was no impact to the consolidated financial statements for oil sales.

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. In conjunction with the adoption of ASC 606, for the six months ended June 30, 2018, there was no change to the method used to recognize other processing revenues and there was no impact to the consolidated financial statements for other revenues.

Previously, the Company elected to utilize the entitlements method to account for natural gas imbalances, which is no longer allowed under ASC 606. In conjunction with the adoption of ASC 606, for the six months ended June 30, 2018, there was no material impact to the consolidated financial statements due to this change in accounting for our production imbalances.

A significant number of our product sales are short-term in nature with a contract term of one year or ~~less.~~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, ~~2018,~~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. ~~In April 2017,~~ Ultra Resources Inc., a Delaware corporation and wholly-owned subsidiary of the Company, (“Ultra Resources”)~~, as the borrower,~~ entered into a Credit Agreement ~~(as amended,~~as the ~~“Credit Agreement”)~~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”) ~~for an aggregate amount of $400.0 million and an initial~~subject to a borrowing base ~~of $1.2 billion (which~~redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and ~~the~~ Term Loan Agreement ~~(defined~~(as defined below)). ~~In September 2017, the administrative agent and the other lenders approved an increase~~

The semi-annual redetermination in ~~the~~February 2019 resulted in a borrowing base ~~under~~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 ~~Agreement from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments~~Facility. At June 30, 2019, Ultra Resources had $59.0 million of outstanding borrowings under the Revolving Credit Facility, ~~to an aggregate amount~~and with total commitments of ~~$425.0~~$325.0 million. ~~In April 2018, the administrative agent and the other lenders reaffirmed the~~The next scheduled borrowing base ~~at $1.4 billion. There are no~~redetermination is scheduled ~~borrowing base~~for October 1, 2019.

redeterminations until October 1, 2018. At June 30, 2018, Ultra Resources had $58.0 million in outstanding borrowings under the Revolving Credit Facility, total commitments under the Revolving Credit Facility of $425.0 million and a borrowing base of $1.4 billion.

The Revolving Credit Facility has capacity for Ultra Resources to increase the commitments subject to certain conditions and has $50.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. ~~If borrowings~~ ~~are outstanding during a period that~~The applicable margin increases by 25 basis points in the event the Company’s consolidated net leverage ratio, ~~exceeds 4.00 to 1.00 at the end of any fiscal quarter~~ as ~~described below, the interest rate on such borrowings shall be at a~~ ~~per annum~~ ~~rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer~~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~~The Revolving Credit Facility requires Ultra Resources to maintain (i) ana 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; (iii) a consolidated net leverage ratio that does not exceed (a) 4.50 to 1.00, during the period ending on the last day of the fiscal quarter ending June 30, 2019, (b) 4.25 to 1.00, during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ~~ending on the last day of the fiscal quarter ending December 31, 2019, and (c) 4.00 to 1.00 beginning on the last day of the fiscal quarter ending on March 31, 2020; and (iv)~~(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, ~~2018,~~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 ~~all~~each of its debt covenants under the ~~Revolving~~ Credit ~~Facility.~~ 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 ~~Company expects to comply with these requirements prior to September 29, 2019 and to remain in compliance with these requirements while the requirements remain effective.~~

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

The Revolving Credit Facility also contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments, hedging requirements ~~and other customary covenants.~~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. In ~~April 2017~~,As of June 30, 2019, the Ultra ~~Resources, as borrower, entered into a~~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 ~~Agreement”~~Amendment”)~~, providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in~~ with the ~~amount of $600.0 million~~Term Loan Administrative Agent and ~~an incremental term loan in~~ the ~~amount of $200.0 million~~Term Loan Lenders party thereto. Pursuant to ~~be drawn immediately after~~ the ~~funding of~~Term Loan Amendment, the ~~initial term loan. In September 2017, the Company closed an incremental senior secured term loan offering of $175.0 million, increasing total borrowings under~~parties agreed, among other things, to amend the Term Loan Agreement to ~~$975.0 million. As part~~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, ~~Ultra Resources agreed to pay an original issue discount equal to one percent~~including, but not limited to:

Borrowings under the Term Loan Agreement ~~bears~~bear interest ~~either~~ at a rate equal to either (a) a customary London interbank offered rate plus ~~300~~400 basis points or (b) the base rate plus ~~200~~300 basis ~~points.~~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 ~~amortizes~~amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the initial aggregate principal amount beginning on June 30, 2019. ~~The~~Borrowings under the Term Loan Agreement ~~matures~~mature on April 12, 2024.

~~The~~Borrowings under the Term Loan Agreement isare subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain ~~exceptions,~~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, ~~2018,~~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. ~~In April 2017, the Company issued~~ ~~$700.0~~At June 30, 2019, Ultra Resources had approximately $150.4 million of ~~its~~the 6.875% ~~senior notes~~Senior Notes due 2022 (the “2022 Notes”) and ~~$500.0~~$225.0 million ~~of its~~with respect to the 7.125% ~~senior notes~~Senior Notes due 2025 (the “2025 ~~Notes,”~~Notes”, and together with the 2022 Notes, the ~~“Notes”~~“Unsecured Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, and the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture..

The Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Notes may be resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act.

The 2022 Notes will mature on April 15, 2022. ~~The~~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. ~~The~~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.

~~Prior~~Refer to ~~April 15, 2019, Ultra Resources may, at any time or from time to time, redeem~~Note 6 Long Term Debt in the ~~aggregate up to 35%~~2018 Form 10-K for additional details on the terms of the aggregate principal amount of the 2022 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022Unsecured Notes.

Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

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

The Indenture contains customary covenants that restrict the ability of Ultra Resources and the guarantors and certain of its subsidiaries to: (i) sell assets and subsidiary equity; (ii) incur indebtedness; (iii) create or incur certain liens; (iv) enter into affiliate agreements; (v) enter into agreements that restrict distributions from certain restricted subsidiaries and the consummation of mergers and consolidations; (vi) consolidate, merge or transfer all or substantially all of the assets of the Company or any Restricted Subsidiary (as defined in the Indenture); and (vii) create unrestricted subsidiaries. The covenants in the Indenture are subject to important exceptions and qualifications. Subject to conditions, the Indenture provides that the Company and its subsidiaries will no longer be subject to certain covenants when the Notes receive investment grade ratings from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At June 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Notes.

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

~~Other long-term obligations:~~ ~~These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.~~

	For the Quarter Ended				For the Six Months Ended				For the Three Months				For the Six Months Ended
	Ended June 30,				Ended June 30,				Ended June 30,				Ended June 30,
	2018		2017		2018		2017		2019		2018		2019		2018
Total cost of share-based payment plans	$	2,263	$	34,679	$	13,173	$	35,890	$	745	$	2,263	$	1,872	$	13,173
Amounts capitalized in oil and gas properties and equipment	$	952	$	9,266	$	3,051	$	9,626	$	64	$	952	$	351	$	3,051
Amounts charged against income, before income tax benefit	$	1,311	$	25,413	$	10,122	$	26,264	$	681	$	1,311	$	1,521	$	10,122
Amount of related income tax benefit recognized in income before valuation allowance	$	275	$	10,114	$	2,126	$	10,453	$	143	$	275	$	319	$	2,126

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 ~~other employees~~consultants of the Company (the “Reserve”). During 2017, ~~Management Incentive Plan Grants~~management incentive plan grants (the “Initial MIP Grants”) were made to members of the ~~board of directors (the “Board”),~~Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% ~~of $6.0~~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 ~~the fifth anniversary of the Effective Date, as defined in Note 10,~~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.

OnIn June 8, 2018, ~~each of~~ the Board ~~and the Compensation Committee of the Board (the “Committee”)~~ approved an amendment and restatement of the Ultra Petroleum Corp. 2017 Stock Incentive Plan (as amended and restated, the “A&R Stock Incentive Plan”). The A&R Stock Incentive Plan amends and restates the 2017 Stock Incentive Plan to, among other things:

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

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

Long Term Incentive Awards. In 2018 and March 2019, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The awards cover a performance period of three years and 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~~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)~~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. ~~During the six months ended June 30, 2017, the Company recognized $26.3 million in pre-tax compensation expense, of which $25.2 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 ~~recorded~~ a valuation allowance recorded against all deferred tax assets as of June 30, ~~2018.~~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 ~~(“TCJA”~~(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 legislation, which became effective on January 1, 2018, decreased the U.S. corporate federal income tax rate from 35% to 21%. The TCJA also included a number of provisions, including the elimination of loss carrybacksregulations and ~~limitations~~analyze their applicability and impact on the use of future losses, repeal of the Alternative Minimum Tax regime, the limitation on the deductibility of certain expenses, including interest expense, and changes in the way that capital costs are recovered.Company.

Given the significant complexity of the TCJA and anticipated additional implementation guidance from the Internal Revenue Service, further implications of TCJA may be identified in future periods. Amounts recorded in the consolidated financial statements are provisional.

Objectives and Strategy: The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

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

~~The Company’s~~Under the Revolving Credit Facility, the Company is subject to the following minimum hedging ~~policy limits~~requirements: through September 29, 2019, the Company is required to hedge a minimum of 65% of the quarterly projected volumes ~~hedged~~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 ~~not be greater than~~hedge a minimum of 50% of ~~its forecasted production~~the quarterly projected volumes ~~without Board approval. During~~of natural gas from PDP reserves. Beginning April 1, 2020, the ~~quarter and six months ended June 30, 2018, the Board approved all commodity derivative hedge contracts for volumes exceeding 50% of forecasted production volumes.~~Company will no longer be subject to a minimum hedging requirement.

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

~~Derivative~~derivative contracts ~~that do not qualify for hedge accounting treatment~~ are recorded at fair value as derivative assets and liabilities ~~at fair value~~ on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense inon 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.~~instruments and do not impact operating cash flows on the Condensed Consolidated Statements of Cash Flows.

Commodity Derivative Contracts: At June 30, ~~2018,~~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.

Year

Index

Total Volumes

Weighted Average Price per Unit

Fair Value -
June 30, 2018

(in millions)

Asset (Liability)

Natural gas fixed price swaps

(Mmbtu)

($/Mmbtu)

2018 (July through December)

NYMEX-Henry Hub

141.1

$
2.89

$
(9,430
)
2019

NYMEX-Henry Hub

167.3

$
2.85

(4,557
)
2020

NYMEX-Henry Hub

15.5

$
2.76

(2,662
)

Natural gas basis swaps (1)

(Mmbtu)

($/Mmbtu)

2018 (July through December)

NW Rockies Basis Swap

94.6

$
(0.68
)

$
(3,176
)
2019

NW Rockies Basis Swap

84.5

$
(0.70
)

(848
)
2020

NW Rockies Basis Swap

—

$
—

—

Crude oil fixed price swaps

(Bbl)

($/Bbl)

2018 (July through December)

NYMEX-WTI

1.2

$
60.53

$
(12,050
)
2019

NYMEX-WTI

1.7

$
58.83

(11,645
)
2020

NYMEX-WTI

.09

$
60.05

(204
)

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

~~Subsequent to June 30, 2018 and through July 24, 2018, the Company has 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 ~~Consolidated Statements~~condensed consolidated statements of ~~Operations~~operations for the ~~quarter and six~~three months ended June 30, ~~2018~~2019 and ~~2017:~~2018:

	For the Quarter Ended						For the Six Months						For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,						Ended June 30,						Ended June 30,
Commodity Derivatives:	2018			2017			2018			2017
Commodity Derivatives (in thousands):													2019			2018			2019			2018
Realized gain (loss) on commodity derivatives - natural gas (1)	$	10,982		$	(868	)	$	12,426		$	(868	)	$	3,936		$	10,982		$	(77,267	)	$	12,426
Realized loss on commodity derivatives - oil (1)		(4,320	)		—			(4,690	)		—
Realized gain (loss) on commodity derivatives - oil (1)														(516	)		(4,320	)		2,056			(4,690	)
Unrealized gain (loss) on commodity derivatives (1)		(53,933	)		21,585			(61,539	)		8,367			68,234			(53,933	)		82,527			(61,539	)
Total gain (loss) on commodity derivatives	$	(47,271	)	$	20,717		$	(53,803	)	$	7,499		$	71,654		$	(47,271	)	$	7,316		$	(53,803	)

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.

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

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

	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	14,480	$	—	$	14,480	$	—	$	58,198	$	—	$	58,198
Long-term derivative asset (1)		—		3,692		—		3,692		—		11,571		—		11,571
Total derivative instruments	$	—	$	18,172	$	—	$	18,172	$	—	$	69,769	$	—	$	69,769
Liabilities:
Current derivative liability	$	—	$	54,891	$	—	$	54,891	$	—	$	20,692	$	—	$	20,692
Long-term derivative liability (2)		—		7,853		—		7,853		—		9,382		—		9,382
Total derivative instruments	$	—	$	62,744	$	—	$	62,744	$	—	$	30,074	$	—	$	30,074

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, ~~2018,~~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.~~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 ~~(defined below)~~ provides for the treatment of claims against our bankruptcy estates, including claims for prepetition liabilities that have not otherwise been satisfied or addressed before we emerged from chapter 11 proceedings. ~~As noted in this Quarterly Report on Form 10-Q, the~~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 ~~as described in Note 10~~ 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, ~~(as defined in Note 10),~~ asserting ~~various claims against us, including~~ 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. ~~We disputed~~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 ~~the~~ holders of the Ultra Resources’ indebtedness for certain make-whole amounts and ~~post-petition~~postpetition interest at the default rates provided for in the ~~prepetition~~ debt agreements. ~~As previously disclosed, on~~

On September 22, 2017, the Bankruptcy Court denied ~~our~~the Company’s objection to the pending make-whole and postpetition interest claims. ~~Further, on~~On October 6, 2017, the Bankruptcy Court entered an order requiring usthe Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, wethe Company distributed $399.0 million from ~~a $400.0 million~~the reserve fund ~~set up in connection with our emergence from chapter 11 proceedings~~ to the parties asserting the make-whole and ~~post-petition~~postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims ~~described above~~ and $175.2 million representing postpetition interest at the default rate. The Company ~~is appealing~~appealed the court order denying its objections to these claims ~~but it~~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 ~~dispute~~disputed the preliminary determination and the proof of claim. ~~We have notified~~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 ~~several~~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 ~~we believe ONRR may not have considered in preparing~~settled.

During the ~~preliminary determination notice,~~quarter ended June 30, 2019, the Company settled and ~~we continue to be in discussions with ONRR~~funded a dispute related to ~~these matters.~~a net profits interest in certain of its operated leases in the Pinedale field. This ~~claim and the preliminary determination notice could ultimately result~~settlement resulted in ~~us being ordered to pay additional royalty to ONRR for prior, current and future periods.~~a payment of $3.5 million. The Company is

~~not able to determine~~had previously accrued for this item; therefore, no additional expense was recognized during the ~~likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.~~

~~On April 29, 2016,~~quarter. Additionally, the Company ~~received~~agreed in principle the settlement of a ~~letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for~~separate overriding royalty interest dispute and has recognized an expense of $1.5 million as an estimate of the purchase and sale of crude oil between Ultra Resources and SPMT and (2) the contract was terminated. In the letter, SPMT demanded payment for damages resulting from the breach in the amount of $38.6 million. On August 31, 2016, SPMT filed a proof of claim with the Bankruptcy Court for $16.9 million. On December 13, 2016, we filed an objection to SPMT’s proof of claim, and on December 14, 2016, we filed an adversary proceeding against SPMT related to matters we believe constitute breach of contract by SPMT during the prepetition period (as amended, the “Sunoco Adversary”). In its April 25, 2017 reply to the Sunoco Adversary complaint, Sunoco asserted a counterclaim for matters addressed in its proof of claim. Litigation related to this matter is proceeding in the Bankruptcy Court. At this time, we are not able to determine the likelihood or range of damages owed to SPMT, if any, related to this matter, or, if and when such amounts are assessed, whether such amounts would be material.

We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in the Pinedale ~~Wyoming.~~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 ~~all~~ these ~~claims~~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 ~~routine disputes and allegations~~additional pending or threatened litigation is not likely to have a material adverse effect on our financial position or results of operations.

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States 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 February 13, 2017, the Bankruptcy Court approved our amended Disclosure Statement (by order subsequently amended on February 21, 2017), 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 (the “Effective Date”), we emerged from bankruptcy.~~

~~Pursuant to the Plan, the significant transactions that occurred upon our emergence from chapter 11 proceedings were as follows:~~

As previously disclosed, we were not required to apply fresh start accounting to our financial statements in connection with our emergence from bankruptcy because the reorganization value of our assets immediately prior to confirmation of the Plan exceeded our aggregate postpetition liabilities and allowed claims.

The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims are not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

As a part of the claims resolution process, we are working to resolve differences between amounts we listed in information filed during our bankruptcy proceedings and the amounts of claims filed by our creditors. We have filed, and we will continue to file, objections with the Bankruptcy Court as necessary with respect to claims we believe should be disallowed.

During 2017, we incurred significant costs associated with our reorganization and the chapter 11 proceedings. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

~~The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the quarter and six months ended June 30, 2017:~~

The Company has evaluated the period subsequent to June 30, ~~2018~~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:

~~ULTRA PETROLEUM CORP.~~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. ~~(the~~and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, “us”) is an independent ~~oil and gas company engaged in the development, production, operation,~~ exploration and ~~acquisition of oil~~production company focused on developing and ~~natural gas properties. The Company is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are developing~~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 ~~the Company’s~~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 into improved operational efficiencies.~~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.~~operations or capital investment program.

The Company currently generates its revenue, earnings and cash flow ~~primarily~~ from the production and sales of natural gas and crude oil and condensate from its ~~properties~~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 ~~southwest Wyoming~~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 ~~portion~~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 ~~revenues coming from oil sales from~~initial 2019 capital investment guidance. The Company will continue to evaluate the commodity price environment and the projected investment returns, as it manages its ~~properties in the Uinta Basin in Utah.~~

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. See Note 7~~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.

~~During~~ the ~~quarter~~Company in the quarters ended June 30, 2019 and 2018, ~~the~~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 ~~$2.28~~$2.17 per Mcf, including realized gains and losses on commodity derivatives, compared ~~with $2.84~~to $2.28 per Mcf during the quarter ended June 30, ~~2017.~~2018. The ~~Company’s~~ average price realization for the Company’s natural gas ~~was $2.11 per Mcf,~~during the each of the quarters ended June 30, 2019 and 2018, excluding ~~the~~ 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, ~~2018, as compared with $2.85 per Mcf during the quarter ended June 30, 2017.~~

~~During the quarter ended June 30, 2018, the average price realization for the Company’s oil~~2019 was ~~$58.24~~$59.65 per barrel, including realized gains and losses on commodity derivatives, compared to ~~$45.51~~$58.24 per barrel during the quarter ended June 30, ~~2017.~~2018. The ~~Company’s~~ average price realization for the Company’s crude oil ~~was $64.71 per barrel,~~and condensate during the quarter ended June 30, 2019, excluding ~~the~~ realized gains and losses on commodity derivatives, ~~during the quarter ended June 30, 2018, as~~was $60.80 per barrel, compared ~~with $45.51~~to $64.71 per barrel during the quarter ended June 30, ~~2017.~~2018.

As ~~discussed in Note 10,~~of June 30, 2019, the Company ~~emerged from chapter 11 proceedings during the year ended December 31, 2017. The effects of the Plan (defined below) were included~~operated two rigs in the ~~Consolidated Financial Statements as~~Pinedale field with a primary focus of ~~December 31, 2017 and the related adjustments thereto were recorded~~drilling vertical wells. The Company has also participated in ~~our Consolidated Statement of Operations as reorganization items for the quarter and six months ended June 30, 2018.~~

~~On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”)~~wells drilled by other operators in the ~~United States 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.).~~

The claims filed against us during our chapter 11 proceedings were voluminous. In addition, claimants may file amended or modified claims in the future, which modifications or amendments may be material. The claims resolution process is on-going, and the ultimate number and amount of prepetition claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

~~The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the quarter and six months ended June 30, 2017:~~

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

~~Derivative Instruments and Hedging Activities.~~ The Company follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations.

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

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

settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

~~Share-Based Payment Arrangements.~~ The Company applies FASB ASC Topic 718, Compensation – Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognizedproperties was $176.8 million for the six months ended June 30, ~~2018 and 2017 was $10.1 million and $26.3 million, respectively. See Note 5 for additional details.~~

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

~~Full Cost Method of Accounting.~~ The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and FASB ASC Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive2019. During this period, there were 53 gross (52.5 net) vertical wells and ~~overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly~~1 gross (0.9 net) horizontal wells, together with 16 gross (5.3 net) vertical wells operated by others ~~and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.~~

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

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The Company did not have any write-downs related to the full cost ceiling limitation during the six months ended June 30, 2018 or 2017.

~~Revenue Recognition.~~ The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. During the six months ended June 30, 2018, the Company adopted the new accounting standard, ASC 606, Revenue from Contracts with Customers and all related amendments. See Note 2 for additional details and disclosures related to the Company’s adoption of this standard.

~~Valuation of Deferred Tax Assets.~~ The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax basis (temporary differences).

To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

During the year ended December 31, 2017, the Company recorded an expected benefit for the recovery of the Company’s carryforward Alternative Minimum Tax (“AMT”) credits. During the six months ended June 30, 2018, the Company recorded

~~income tax expense of approximately $0.4 million related to the Internal Revenue Service effect of a 6.6% sequestration rate on the expected AMT credit.~~

~~The Company has recorded a valuation allowance against all of its deferred tax assets~~vertical well costs as of June 30, ~~2018. Some or all~~2019 averaged $3.19 million. This stabilization of ~~this valuation allowance may be reversed in future periods against future income. On December 22, 2017,~~capital cost from the Tax Cuts and Jobs Act (“TCJA”) was enacted into law. The new legislation, which became effective on January 1, 2018, decreased the U.S. corporate federal income tax rate from 35% to 21%. The TCJA also included a number of provisions, including the elimination of loss carrybacks and limitations on the use of future losses, repeal of the AMT regime, the limitation on the deductibility of certain expenses, including interest expense, and changeshigher well cost levels in the ~~way that capital costs are recovered.~~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 ~~Company follows ASU No. 2015-3,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,~~ ~~and includes the costs for issuing debt, including issuance discounts, except those related to the~~borrowing base under our Revolving Credit Facility ~~as a direct deduction from the carrying amount of the related debt liability. Costs related to the issuance of~~is currently $1.3 billion, and lender commitments under the Revolving Credit Facility are ~~recorded~~$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 ~~an asset~~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 ~~Consolidated Balance Sheets~~.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.

~~Conversion of Barrels of Oil~~Moreover, while the Company’s current borrowing base and the amount outstanding under the Revolving Credit Facility indicate sufficient liquidity to ~~Mcfe of Gas~~. The Company converts Bbls of oil and other liquid hydrocarbons to Mcfe at a ratio of one Bbl of oil or liquids to six Mcfe. This conversion ratio, which is typically used in the oil and gas industry, represents the approximate energy equivalent of a barrel of oil or other liquids to an Mcf of natural gas. The sales price of one Bbl of oil or liquids has been much higher than the sales price of six Mcf of natural gas over the last several years, so a six to one conversion ratio does not represent the economic equivalency of six Mcf of natural gas to a Bbl of oil or other liquids.

~~Leases.~~ ~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases~~ ~~(“ASU No. 2016-02”). The guidance requires that lessees will be required to recognize assets and liabilities on the balance sheet~~execute our business plan for the ~~rights and obligations created by all leases with terms of more than 12 months. The ASU will also require disclosures designed to give financial statement users information on~~foreseeable future, the amount ~~timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information.~~ ~~To facilitate~~that we may borrow under the Revolving Credit Facility is governed by compliance with ~~this ASU,~~ the consolidated net leverage covenant as discussed in Note 6. A sustained decline in commodity prices could cause the Company ~~has formed an implementation work team, developed a project plan, educated departments affected by the standard, begun the process~~to be out of ~~reviewing its contract portfolio~~ ~~and continues to evaluate its systems, processes, and internal controls during 2018.~~ ~~In January 2018, the FASB issued ASU No. 2018-01,~~ ~~Land Easement Practical Expedient for Transition to Topic 842~~ ~~(“ASU No. 2018-01”),~~compliance with future consolidated net leverage covenant ratios, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired before the entity’s adoption of this ASU and that were not previously accounted for as leases. For public companies, the standards will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. ~~Ultra will adopt this ASU on January 1, 2019. As permitted by ASU 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements, the Company does not expect to adjust comparative-period financial statements.~~ ~~The Company is still evaluating the impact of ASU No. 2016-02 and ASU No. 2018-01 on its consolidated financial statements~~.

~~Stock Compensation. In May 2017, the FASB issued ASU 2017-09,~~ ~~Compensation-Stock Compensation (Topic 718)~~ ~~(“ASU No. 2017-09”)~~, ~~which is intended to clarify and~~could reduce diversity in practice and cost and complexity when applying the guidance in Topic 718, Compensation-Stock Compensation, to a change to the terms or conditions of a share-based payment award. The Company adopted ASU 2017-09 on January 1, 2018 and the implementation of this ASU did not have a material impact on the Company’s ~~consolidated financial statements.~~effective liquidity.

~~Revenue from Contracts with Customers.~~ ~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~ ~~and in 2016, the FASB issued ASU 2016-08,~~ ~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU 2016-10,~~ ~~Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing~~, which supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities - Oil and Gas - Revenue Recognition. The new standard requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.

On January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers and all the related amendments (the “new revenue standard”) to all contracts entered into in 2017 using the modified retrospective method. We recorded a net addition to beginning retained earnings of $1.8 millionCONSOLIDATED RESULTS OF OPERATIONS:

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 ~~due~~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 ~~cumulative impact~~overhead rates set by the Council of ~~adopting Topic 606,~~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 ~~impact related to changing from the entitlements method to the sales method to account for wellhead imbalances.~~ Company’s total administrative costs.

The ~~impact to revenues~~following table summarizes our unaudited condensed consolidated statement of operations for the six months ended June 30, 2018 is immaterial to the overall consolidated financial statements as a result of applying Topic 606. The comparative information has not been restated and continues to be reported under the accounting standards for those periods. See Note 2 for further details related to the adoption of this standard. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an on-going basis.

	For the Quarter Ended									For the Six Months									For the Quarter Ended								For the Six Months
	Ended June 30,						%			Ended June 30,						%			Ended June 30,					%			Ended June 30,						%
	2018			2017			Variance			2018			2017			Variance			2019		2018			Variance			2019			2018			Variance
	(Amounts in thousands, except per unit data)																		(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)		66,892			63,067			6	%		135,128			123,056			10	%		59,805		66,892			(11	)%		119,380			135,128			(12	)%
Crude oil and condensate (Bbl)		667			675			(1	)%		1,345			1,338			1	%		449		667			(33	)%		886			1,345			(34	)%
Total production (Mcfe)		70,894			67,118			6	%		143,198			131,084			9	%		62,499		70,894			(12	)%		124,696			143,198			(13	)%

Commodity Prices:
Natural gas ($/Mcf, excluding hedges)	$	2.11		$	2.85			(26	)%	$	2.39		$	3.00			(20	)%	$	2.11	$	2.11			—		$	3.12		$	2.39			31	%
Natural gas ($/Mcf, including realized hedges)	$	2.28		$	2.84			(20	)%	$	2.48		$	2.99			(17	)%	$	2.17	$	2.28			(5	)%	$	2.47		$	2.48			(1	)%
Oil and condensate ($/Bbl, excluding hedges)	$	64.71		$	45.51			42	%	$	62.79		$	46.39			35	%	$	60.80	$	64.71			(6	)%	$	57.30		$	62.79			(9	)%
Oil and condensate ($/Bbl, including realized hedges)	$	58.24		$	45.51			28	%	$	59.31		$	46.39			28	%	$	59.65	$	58.24			2	%	$	59.62		$	59.31			1	%

Revenues:
Natural gas sales	$	141,255		$	179,997			(22	)%	$	322,716		$	368,848			(13	)%	$	125,915	$	141,255			(11	)%	$	371,903		$	322,716			15	%
Oil sales		43,167			30,732			40	%		84,451			62,081			36	%		27,301		43,167			(37	)%		50,767			84,451			(40	)%
Other revenues		5,716			1,928			196	%		8,344			2,687			211	%		2,190		5,716			(62	)%		4,197			8,344			(50	)%
Total operating revenues	$	190,138		$	212,657			(11	)%	$	415,511		$	433,616			(4	)%	$	155,406	$	190,138			(18	)%	$	426,867		$	415,511			3	%

Derivatives:
Realized gain (loss) on commodity derivatives	$	6,662		$	(868	)		(868	)%	$	7,736		$	(868	)		(991	)%	$	3,420	$	6,662			(49	)%	$	(75,211	)	$	7,736			(1072	)%
Unrealized gain (loss) on commodity derivatives		(53,933	)		21,585			(350	)%		(61,539	)		8,367			(835	)%		68,234		(53,933	)		(227	)%		82,527			(61,539	)		(234	)%
Total gain (loss) on commodity derivatives	$	(47,271	)	$	20,717			(328	)%	$	(53,803	)	$	7,499			(817	)%
Total Gain (loss) on commodity derivatives																			$	71,654	$	(47,271	)		(252	)%	$	7,316		$	(53,803	)		(114	)%

Operating Costs and Expenses:
Lease operating expenses	$	23,645		$	23,089			2	%	$	45,409		$	46,225			(2	)%	$	15,889	$	23,645			(33	)%	$	33,114		$	45,409			(27	)%
Facility lease expense	$	6,526		$	5,226			25	%	$	12,682		$	10,452			21	%	$	6,543	$	6,526			0	%	$	13,188		$	12,682			4	%
Production taxes	$	18,883		$	21,754			(13	)%	$	42,153		$	43,887			(4	)%	$	16,443	$	18,883			(13	)%	$	46,618		$	42,153			11	%
Gathering fees	$	24,181		$	20,642			17	%	$	47,238		$	41,571			14	%	$	20,320	$	24,181			(16	)%	$	40,200		$	47,238			(15	)%
Depletion, depreciation and amortization	$	51,742		$	38,673			34	%	$	102,282		$	70,427			45	%	$	55,768	$	51,742			8	%	$	107,422		$	102,282			5	%
General and administrative expenses	$	2,063		$	25,009			(92	)%	$	14,752		$	26,061			(43	)%	$	7,433	$	2,063			260	%	$	14,485		$	14,752			(2	)%

Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.33		$	0.34			(3	)%	$	0.32		$	0.35			(9	)%	$	0.25	$	0.33			(24	)%	$	0.27		$	0.32			(16	)%
Facility lease expense	$	0.09		$	0.08			13	%	$	0.09		$	0.08			13	%	$	0.10	$	0.09			11	%	$	0.11		$	0.09			22	%
Production taxes	$	0.27		$	0.32			(16	)%	$	0.29		$	0.33			(12	)%	$	0.26	$	0.27			(4	)%	$	0.37		$	0.29			28	%
Gathering fees	$	0.34		$	0.31			10	%	$	0.33		$	0.32			3	%	$	0.33	$	0.34			(3	)%	$	0.32		$	0.33			(3	)%
Depletion, depreciation and amortization	$	0.73		$	0.58			26	%	$	0.71		$	0.54			31	%	$	0.89	$	0.73			22	%	$	0.86		$	0.71			21	%
General and administrative expenses	$	0.03		$	0.37			(92	)%	$	0.10		$	0.20			(50	)%	$	0.12	$	0.03			300	%	$	0.12		$	0.10			20	%

Production. During the quarter ended June 30, ~~2018,~~2019, total production ~~increased~~decreased on a gas equivalent basis to ~~70.9~~62.5 Bcfe compared to ~~67.1~~70.9 Bcfe for the same period in ~~2017.~~2018. The ~~increase~~decrease is primarily attributable to ~~an increase~~a decrease in capital investment which occurred over the second half of 2018 and ~~development activity, partially offset by a decrease~~resulted in ~~Mcf/day due to~~lower production in the current period. Additionally, the sale of the non-core assets in ~~Pennsylvania~~Utah during the ~~fourth~~third quarter of ~~2017.~~2018 resulted in a decrease in production on a comparative basis.

Commodity Prices – Natural Gas. ~~During the quarter ended June 30, 2018, realized~~Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased ~~20%~~5% to ~~$2.28~~$2.17 per Mcf during the quarter ended June 30, 2019, as compared to ~~$2.84~~$2.28 per Mcf for the same period in ~~2017.~~2018. The Company has entered into various natural gas price commodity derivative contracts with contract periods extending through the ~~first~~fourth quarter of 2020. See Note 79 for additional ~~details.~~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, ~~for natural gas~~ was $2.11 per ~~Mcf as compared to $2.85 per Mcf for the same period in 2017.~~Mcf.

Commodity Prices – Oil. ~~During the quarter ended June 30, 2018, the average price realization for the Company’s~~Realized oil prices, including realized gains and losses on commodity derivatives, increased to ~~$58.24~~$59.65 per barrel during the quarter ended June 30, 2019, as compared to ~~$45.51~~$58.24 per barrel for the same period in ~~2017.~~2018. The Company has entered into various oil price commodity derivative contracts with contract periods extending through ~~the first quarter of~~ 2020. See Note 79 for additional details relating to these derivative contracts. During the ~~quarter~~three months ended June 30, ~~2018,~~2019, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was ~~$64.71~~$60.80 per barrel as compared to ~~$45.51~~$64.71 per barrel for the same period in ~~2017.~~2018.

Revenues.During the quarter ended June 30, ~~2018,~~2019, revenues decreased to ~~$190.1~~$155.4 million as compared to ~~$212.7~~$190.1 million for the same period in ~~2017.~~2018. This decrease is primarily attributable to the decrease in ~~average natural gas prices and partially offset by the increase in~~ total production and ~~average oil~~the decrease natural gas prices.

Lease Operating Expense.Lease operating expense (“LOE”) ~~increased slightly~~decreased to ~~$23.6~~$15.9 million during the quarter ended June 30, ~~2018~~2019 as compared to ~~$23.1~~$23.6 million during the same period in ~~2017.~~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 ~~$0.33~~$0.25 per Mcfe during the quarter ended June 30, ~~2018~~2019 as compared with ~~$0.34~~$0.33 per Mcfe during the same period in ~~2017, primarily due to increased total production during the period ended June 30,~~ 2018.

Facility Lease Expense. ~~During December~~In 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale ~~Anticline in Wyoming.~~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. ~~The lease is classified as an operating lease.~~ For the ~~quarter~~quarters ended June 30, 2019 and 2018, the Company recognized ~~operating lease~~ expense associated with the Lease Agreement of $6.5 ~~million, or $0.09 per Mcfe, as compared to $5.2 million, or $0.08 per Mcfe for the same period in 2017.~~million.

Production Taxes.During the quarter ended June 30, ~~2018,~~2019, production taxes decreased to ~~$18.9~~$16.4 million compared to ~~$21.8~~$18.9 million during the same period in ~~2017,~~2018, or ~~$0.27~~$0.26 per Mcfe compared to ~~$0.32~~$0.27 per Mcfe, respectively. Production taxes in Wyoming are primarily calculated based on a percentage of revenue from the physical production ~~in Wyoming~~ and ~~Utah~~realized revenues, excluding derivative hedge settlements, after certain deductions and were ~~9.9%~~10.6% of revenues for the quarter ended June 30, ~~2018~~2019 and ~~10.2%~~9.9% of revenues for the same period in ~~2017. The decrease in per unit taxes was primarily attributable to decreased natural gas prices during the quarter ended June 30, 2018 as compared to the same period in 2017.~~2018.

Gathering Fees.During the quarter ended June 30, ~~2018,~~2019, gathering fees ~~increased~~decreased to ~~$24.2~~$20.3 million compared to ~~$20.6~~$24.2 million during the same period in ~~2017, largely~~2018, related to ~~increased production.~~decreased production volumes. On a per unit basis, gathering fees ~~increased~~decreased slightly to ~~$0.34~~$0.33 per Mcfe for the quarter ended June 30, ~~2018~~2019 as compared ~~with $0.31~~to $0.34 per Mcfe ~~for~~in the same period in ~~2017.~~2018.

Depletion, Depreciation and Amortization.During the quarter ended June 30, ~~2018,~~ 2019, depletion, depreciation and amortization (“DD&A&A”) expense increased to ~~$51.7~~$55.8 million compared to ~~$38.7~~$51.7 million for the same period in ~~2017.~~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 ~~due to a higher depletable base from~~per unit is greater than the ~~increase in capital expenditures as part of the Company’s drilling program~~current oil and ~~as a result of increased~~gas property value per unit, offset slightly by decreased production volumes during the ~~quarter~~three months ended June 30, ~~2018.~~2019. On a unit of production basis, the DD&A rate increased to ~~$0.73~~$0.89 per Mcfe for the quarter ended June 30, ~~2018~~2019 compared to ~~$0.58~~$0.73 per Mcfe for the same period in ~~2017.~~2018.

General and Administrative Expenses.During the quarter ended June 30, ~~2018,~~2019, general and administrative expenses ~~decreased~~increased to ~~$2.1~~$7.4 million as compared to ~~$25.0~~$2.1 million for the same period in ~~2017.~~2018. The ~~decrease~~increase is primarily attributable to the ~~$25.4 million~~revision in estimate of ~~non-cash stock incentive~~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 ~~that was incurred~~recognized during the ~~quarter ended June 30, 2017 as part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date. See Note 5 for additional details.~~quarter. On a per unit basis, general and administrative expenses ~~decreased~~increased to ~~$0.03~~$0.12 per Mcfe for the quarter ended June 30, ~~2018~~2019 compared to ~~$0.37~~$0.03 per Mcfe for the same period in ~~2017.~~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. ~~During~~Interest expense decreased to $32.4 million during the quarter ended June 30, ~~2018, interest expense of $37.7 million increased~~2019 as compared to ~~$29.4~~$37.7 million during the same period in ~~2017.~~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 ~~increase is primarily attributable to an increase~~table below reflects the comparative amounts in each period presented (in thousands). The cash interest expense ~~on the Term Loan as the amount borrowed~~and PIK interest increased ~~year over year and increased borrowings on the Revolving Credit Facility during~~for the quarter ended June 30, ~~2018. See Note 4 for additional details related to~~2019, as a result of the ~~Revolving Credit Facility, Term Loan Agreement, and~~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.~~System (“LGS”). During the ~~quarters~~quarter ended June 30, 2018, ~~and 2017,~~ the Company recognized $2.6 million in deferred gain on the 2012 sale of the LGS and certain associated real property ~~rights~~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 ~~Pinedale Anticline~~Company’s bankruptcy filing in ~~Wyoming during December 2012.~~2016 and are described in more detail in Note 12.

Gain (Loss) on Commodity Derivatives. During the quarter ended June 30, ~~2018,~~2019, the Company recognized a ~~loss~~gain of ~~$47.3~~$71.7 million, as compared to a ~~gain~~loss of ~~$20.7~~$47.3 million related to commodity derivatives for the same period in ~~2017.~~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 ~~quarter ended June 30, 2018 compared with $0.9 million related to a realized loss on commodity derivatives during the~~ same period in ~~2017.~~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 ~~loss~~gain of ~~$53.9~~$68.2 million on commodity derivatives during the quarter ended June 30, ~~2018,~~2019, as compared to an unrealized ~~gain~~loss of ~~$21.6~~$53.9 million during the same period in ~~2017.~~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 7~~

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 ~~additional details.~~

~~Reorganization Items, Net.~~ ~~Reorganization items,~~the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives, offset by the decreased net ~~was~~ ~~$426.8 million~~interest expense were the primary elements for the increase in net income during the quarter ended June 30, 2017. The $426.8 million incurred is comprised of expenses of $4.3 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 proceedings and a gain of $431.1 million on the debt for equity exchanged of the 2018 Notes and 2024 Notes. See Note 10 for additional details.

~~Pretax Income.~~ ~~During the quarter ended June 30, 2018, the Company recognized loss before income taxes of $20.5 million~~2019, as compared to ~~income before income taxes of $499.0 million for~~ the same period in 2017. The decrease in earnings is largely attributable to the gain on the debt for equity exchange of the 2018 Notes and 2024 Notes recognized in the second quarter of 2017 related to the Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.2018.

Income Taxes. The Company has recorded a valuation allowance against all deferred tax assets as of June 30, ~~2018.~~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, ~~2018,~~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, as compared to net income of $499.0 million, or $2.76~~$(0.10) per diluted share, for the same period in ~~2017.~~2018. The ~~decrease in earnings is largely attributable to~~operating income and operating expense elements together with the gain on commodity derivatives, offset by the ~~debt~~decreased interest expense were the primary elements for ~~equity exchange of~~ the ~~2018 Notes and 2024 Notes recognized~~increase in net income during the ~~second~~ quarter ~~of 2017 related~~ended June 30, 2019, as compared to the ~~Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.~~same period in 2018.

Six Months Ended June 30, ~~2018~~2019 vs. Six Months Ended June 30, ~~2017~~2018

Production. During the six months ended June 30, ~~2018,~~2019, total production ~~increased~~decreased by 9%13% on a gas equivalent basis to ~~143.2~~124.7 Bcfe compared to ~~131.1~~143.2 Bcfe for the same period in ~~2017,~~2018, primarily attributable to ~~an increase~~a decrease in capital investment which occurred over the second half of 2018 and ~~development activity and partially offset by~~resulted in lower production in the current period. Additionally, the sale of the non-core assets in ~~Pennsylvania~~Utah during the ~~fourth~~third quarter of ~~2017.~~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 ~~17%~~ to ~~$2.48~~$2.47 per Mcf during the six months ended June 30, ~~2018~~2019, as compared to ~~$2.99~~$2.48 per Mcf for the same period in ~~2017.~~2018. During the six months ended June 30, ~~2018,~~2019, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through ~~the first quarter of~~ 2020. See Note 79 for additional details. During the six months ended June 30, ~~2018,~~2019, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was ~~$2.39~~$3.12 per Mcf as compared to ~~$3.00~~$2.39 per Mcf for the same period in ~~2017.~~2018.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased slightly to ~~$59.31~~$59.62 per barrel during the six months ended June 30, ~~2018~~2019 as compared to ~~$46.39~~$59.31 per barrel for the same period in ~~2017.~~2018. During the six months ended June 30, ~~2018,~~2019, the Company entered into additional oil price commodity derivative contracts with contract periods extending through ~~the first quarter of~~ 2020. See Note 79 for additional details. During the six months ended June 30, ~~2018,~~2019, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was ~~$62.79~~$57.30 per barrel as compared to ~~$46.39~~$62.79 per barrel for the same period in ~~2017.~~2018.

Revenues. ~~Decreased~~Increased average natural gas prices, partially offset by ~~increased~~decreased production, ~~and average oil prices,~~ resulted in revenues ~~decreasing~~increasing to ~~$415.5~~$426.9 million for the six months ended June 30, ~~2018~~2019 as compared to ~~$433.6~~$415.5 million for the same period in ~~2017.~~2018.

Lease Operating Expense. LOE decreased to ~~$45.4~~$33.1 million during the six months ended June 30, ~~2018~~2019 compared to ~~$46.2~~$45.4 million during the same period in ~~2017,~~2018, primarily related to ~~field efficiencies~~the exclusion of the Utah production and related expenses in ~~Wyoming and~~2019 which approximated $5.8 million for the six months ended June 30, 2019. The sale of ~~non-core~~the Utah assets was completed in ~~Pennsylvania during~~September 2018. Additionally, beginning in 2019, the ~~fourth quarter of 2017.~~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 ~~$0.32~~$0.27 per Mcfe during the six months ended June 30, ~~2018~~2019 compared to ~~$0.35~~$0.32 per Mcfe during the same period in ~~2017.~~2018.

Facility Lease Expense. During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale ~~Anticline in Wyoming~~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, ~~2018,~~2019, the Company recognized operating lease expense associated with the Lease Agreement of ~~$12.7~~$13.2 million, or ~~$0.09~~$0.11 per Mcfe, as compared to ~~$10.5~~$12.7 million, or ~~$0.08~~$0.09 per Mcfe, for the same period in ~~2017.~~2018.

Production Taxes. During the six months ended June 30, ~~2018,~~2019, production taxes were ~~$42.2~~$46.6 million compared to ~~$43.9~~$42.2 million during the same period in ~~2017,~~2018, or ~~$0.29~~$0.37 per Mcfe compared to ~~$0.33~~$0.29 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming ~~and Utah~~ after certain deductions and were ~~10.1%~~10.9% of revenues for the six months ended June 30, ~~2018~~2019 and 10.1% of revenues for the same period in ~~2017.~~2018. The ~~decrease~~increase in per unit taxes is primarily attributable to ~~decreased~~increased natural gas prices during the six months ended June 30, ~~2018~~2019, as compared to the same period in ~~2017.~~2018.

Gathering Fees. Gathering fees ~~increased~~decreased to ~~$47.2~~$40.2 million for the six months ended June 30, ~~2018~~2019, compared to ~~$41.6~~$47.2 million during the same period in ~~2017,~~2018, largely related to ~~increased~~decreased production. On a per unit basis, gathering fees ~~increased~~decreased slightly to ~~$0.33~~$0.32 per Mcfe for the six months ended June 30, ~~2018~~2019 compared to ~~$0.32~~$0.33 per Mcfe for the same period in ~~2017.~~2018.

Depletion, Depreciation and Amortization. DD&A expenses increased to ~~$102.3~~$107.4 million during the six months ended June 30, ~~2018~~2019, from ~~$70.4~~$102.3 million for the same period in ~~2017,~~2018. The increase in 2019 is primarily attributable to ~~a higher depletion rate due to a higher depletable base from the increase in~~projected capital ~~expenditures as part of the Company’s drilling program and the recognition of~~costs associated with proved undeveloped properties ~~for~~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, ~~2018 as compared to the same period in 2017 as the Company did not emerge from chapter 11 proceedings until the second quarter of 2017.~~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~~2018.

General and Administrative Expenses. General and administrative expenses decreased to $14.5 million for the six months ended June 30, 2019 compared to ~~$0.54~~$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, ~~2017.~~

~~General and Administrative Expenses.~~ ~~General and administrative expenses decreased to $14.8 million for the six months ended June 30, 2018~~2019 compared to $26.1 million for the same period in 2017. The decrease is primarily attributable to the $25.2 million of non-cash stock incentive compensation expense that was incurred during the quarter ended June 30, 2017 as part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date. See Note 5 for additional details. On a per unit basis, general and administrative expenses decreased to $0.10 per Mcfe for the six months ended June 30, ~~2018 compared to $0.20 per Mcfe~~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, ~~2017.~~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 ~~$73.6~~$65.7 million during the six months ended June 30, ~~2018~~2019 compared to ~~$114.9~~$73.6 million during the same period in ~~2017. The decrease in interest~~2018. Interest expense is ~~primarily attributable to recurring~~comprised of four primary elements: (i) cash interest ~~expense on~~expense; (ii) PIK interest expense; (iii) amortization of deferred premium; and (iv) amortization of deferred financing costs. The table below reflects the ~~Revolving Credit Facility, Term Loan Agreement, and the Notes incurred during the six months ended June 30, 2018, as compared to non-recurring accrued postpetition interest for the~~comparative amounts in each period beginning from April 29, 2016 through April 12, 2017, which related to our chapter 11 proceedings, recognized in the six months ended June 30, 2017. See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Notes, and see Note 10 for additional details related to our chapter 11 proceedings.presented (in thousands):

~~Contract Settlement Expense.~~ During the six months ended June 30, 2017, the Company incurred $52.7 million in expense primarily related to the Sempra Rockies Marketing, LLC (“Sempra”) settlement. Sempra filed a claim in 2016 against the Company in regard to an alleged breach of contract, and the Company reached a settlement in April 2017. There were no material contract settlement expenses for the same period in 2018.

Deferred Gain on Sale of Liquids Gathering System. During the six months ended June 30, 2018, ~~and 2017,~~ the Company recognized $5.3 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale ~~Anticline in Wyoming~~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, ~~2018,~~2019, the Company recognized a ~~loss~~gain of ~~$53.8~~$7.3 million related to commodity derivatives as compared to ~~$7.5~~a loss of $53.8 million related to commodity derivatives during the same period in ~~2017.~~2018. Of this total, the Company recognized ~~$7.7 million related to realized gain on commodity derivatives during the six months ended June 30, 2018 as compared with $0.9~~$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 ~~2017.~~2018. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain ~~or loss~~(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 ~~six months ended June 30, 2018 as compared to a $8.4 million unrealized gain on commodity derivatives for the~~ same period in ~~2017.~~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 79 for additional details.

~~Reorganization Items, Net.~~ Reorganization items, net was $369.3 million for the six months ended June 30, 2017. The $369.3 million is primarily comprised of expenses of $61.8 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 proceedings and a gain of $431.1 million, which represents the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes. See Note 10 for additional details.

Pretax Income. The Company recognized income before income taxes of ~~$27.4~~$97.6 million for the six months ended June 30, ~~2018~~2019 compared to ~~$409.3~~$27.4 million for the same period in ~~2017.~~2018. The ~~decrease in earnings is primarily attributable to~~operating income and operating expense elements together with the gain on commodity derivatives, offset by the ~~debt~~decreased net interest expense were the primary elements for ~~equity exchange related to~~ the ~~2018 Notes and 2024 Notes recognized~~increase in net income during the six months ended June 30, ~~2017~~2019, as ~~part of~~compared to the ~~Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.~~same period in 2018.

Income Taxes. The Company recorded a ~~$0.4~~current tax benefit of $0.2 million ~~tax expense~~ for the six months ended June 30, ~~2018 related to the revised sequestration rate of 6.6% on the expected AMT credit.~~2019. The Company has recorded a valuation allowance against all deferred tax assets as of June 30, ~~2018.~~2019. Some or all of this valuation allowance may be reversed in future periods against future income.

At December 31, 2017, the Company had approximately $2.1 billion of U.S. federal tax net operating loss carryforwards that expire at various dates from 2033 through 2037 and approximately $102.2 million of Utah state tax net operating loss carryforwards that expire at various dates from 2033 through 2037.

Net Income. For the six months ended June 30, ~~2018,~~2019, the Company recognized net income of ~~$26.9~~$97.8 million, or ~~$0.14~~$0.49 per diluted share, as compared to ~~$409.3~~$26.9 million, or ~~$3.12~~$0.14 per diluted share, for the same period in ~~2017.~~2018. The ~~decrease~~increase in earnings is ~~primarily attributable to~~driven by the operating income and operating expense elements together with the gain on commodity derivatives, offset by the ~~debt~~decreased interest expense were the primary elements for ~~equity exchange related to~~ the ~~2018 Notes and 2024 Notes recognized~~increase in net income during the six months ended June 30, ~~2017~~2019, as ~~part of~~compared to the ~~Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.~~same period in 2018.

Overview. During the six months ended June 30, ~~2018,~~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, ~~2018,~~2019, the Company ~~reported a~~has cash ~~position~~and cash equivalents of ~~$5.7 million. At June 30, 2018, the Company had $58.0~~$5.2 million inand $59.0 million outstanding borrowings ~~and $367.0 million of available borrowing capacity~~ 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 ~~capital spending.~~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 ~~month period~~months ended June 30, ~~2018,~~2019, total capital expenditures were ~~$251.0~~$176.8 million. During this period, the Company participated in 7653 gross ~~(53.3 net) wells in Wyoming that were drilled to total depth and cased. The wells drilled to total depth and cased included 61 gross (42.3~~(52.5 net) vertical wells and 151 gross ~~(11.0~~(0.9 net) horizontal ~~wells. No~~ wells, ~~are scheduled to be drilled in Utah during 2018.~~together with 16 gross (5.3 net) vertical wells operated by others.

~~2018~~2019 Capital Investment Plan. ~~For 2018, our~~Based on the decision in the third quarter to move to a one rig operated drilling program, the Company’s 2019 capital ~~expenditures are expected~~investment forecast has been adjusted to bea range of $260 million to $290 million, a reduction of approximately ~~$400.0~~$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 ~~these~~future capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility, ~~(defined below),~~ and cash on hand. We expect to allocate ~~nearly~~ all of the ~~budget~~capital to development activities in our Pinedale ~~field~~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 ~~Wyoming.~~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 ~~the~~February 2019 resulted in a borrowing base ~~under~~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 from $1.2 billion to $1.4 billion as requested by the Company, which included an increase in the commitments under the Revolving Credit Facility to an aggregate amount of $425.0 million. In April 2018, the administrative agent and the other lenders reaffirmed the borrowing base at $1.4 billion. There are no scheduled borrowing base redeterminations until October 1, 2018.Facility. At June 30, ~~2018,~~2019, Ultra Resources had ~~$58.0~~$59.0 million inof outstanding borrowings under the Revolving Credit Facility, and with total commitments ~~under the Revolving Credit Facility~~ of ~~$425.0.0 million and a~~$325.0 million. The next borrowing base ~~of $1.4 billion.~~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. ~~If borrowings are outstanding during a period that~~The applicable margin is increased by 25 basis points in the event the Company’s ~~consolidated net~~ leverage ratio, as defined, exceeds 4.00 to ~~1.00 at~~1.00. Ultra Resources is required to pay a commitment fee on the ~~end~~average daily unused portion of ~~any fiscal quarter,~~ the ~~interest rate on such borrowings shall be at~~Revolving Credit Facility, which varies based upon a ~~per annum~~ ~~rate that~~borrowing base utilization grid. Ultra Resources is ~~0.25% higher than the rate that would otherwise~~

~~apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00~~also required to ~~1.00.~~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) ana 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; (iii) a consolidated net leverage ratio that does not exceed (a) 4.50 to 1.00, during the period ending on the last day of the fiscal quarter ending June 30, 2019, (b) 4.25 to 1.00, during the period beginning on the last day of the fiscal quarter ending September 30, 2019 and ~~ending on the last day of the fiscal quarter ending December 31, 2019, and (c) 4.00 to 1.00 beginning on the last day of the fiscal quarter ending on March 31, 2020; and (iv)~~(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, ~~2018,~~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 ~~all~~each of its debt covenants under the ~~Revolving~~ Credit ~~Facility.~~ 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 Company expects to ~~comply with these requirements prior to September 29, 2019 and to remain~~be in compliance with these requirements while the requirements remain effective.

~~Ultra Resources is required to pay a commitment fee on the average daily unused portion~~The duration 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.~~

Term Loan. In ~~April 2017~~,As of June 30, 2019, the Ultra ~~Resources, as borrower, entered into a~~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 signedwith 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”).

Borrowings under the Term Loan Agreement to $975.0 million. As part of the Term Loan Agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount, which is included in deferred financing costs noted in the table above. The Term Loan Agreement has capacity to increase the commitments subject to certain conditions. At June 30, 2018, Ultra Resources had $975.0 million in outstanding borrowings under the Term Loan Agreement, including current maturities.

~~The Term Loan Agreement bears~~bear interest ~~either~~ at a rate equal to either (a) a customary London interbank offered rate plus ~~300~~400 basis points or (b) the base rate plus ~~200~~300 basis ~~points. The~~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 ~~amortizes~~amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the initial aggregate principal amount beginning on June 30, 2019. ~~The~~Borrowings under the Term Loan Agreement ~~matures~~mature on April 12, 2024.

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~~at June 30, ~~2018,~~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.

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~~. In April 2017,~~ (“Second Lien Notes”) pursuant to the Indenture, dated December 21, 2018 (the “Second Lien Notes Indenture”), with Ultra Resources, as issuer, the Company ~~issued~~ and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral agent (the “Trustee”).

Unsecured Notes~~$700.0~~. At June 30, 2019, Ultra Resources had approximately $150.4 million of ~~its~~the 6.875% ~~senior notes~~Senior Notes due 2022 (the “2022 Notes”) and ~~$500.0~~$225.0 million ~~of its~~with respect to the 7.125% ~~senior notes~~Senior Notes due 2025 (the “2025 ~~Notes,”~~Notes”, and together with the 2022 Notes, the ~~“Notes”~~“Unsecured Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, and the Company and its subsidiaries, as guarantors. The Notes are treated as a single class of securities under the Indenture..

~~Prior~~ Refer to ~~April 15, 2019, Ultra Resources may, at any time or from time to time, redeem~~Note 6 Long Term Debt in the ~~aggregate up to 35%~~2018 Form 10-K for additional details on the terms of the aggregate principal amount of the 2022 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 106.875% of the principal amount of the 2022 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2022 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.438% for the twelve-month period beginning on April 15, 2019, 101.719% for the twelve-month period beginning April 15, 2020, and 100.000% for the twelve-month period beginning April 15, 2021 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2022Unsecured Notes.

Prior to April 15, 2020, Ultra Resources may, at any time or from time to time, redeem in the aggregate up to 35% of the aggregate principal amount of the 2025 Notes, in an amount no greater than the net cash proceeds of certain equity offerings at a redemption price of 107.125% of the principal amount of the 2025 Notes, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the original principal amount of the 2025 Notes remains outstanding and the redemption occurs within 180 days of the closing of such equity offering. In addition, before April 15, 2020, Ultra Resources may redeem all or a part of the 2025 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, on or after April 15, 2019, Ultra Resources may redeem all or a part of the 2025 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.344% for the twelve-month period beginning on April 15, 2020, 103.563% for the twelve-month period beginning April 15, 2021, 101.781% for the twelve-month period beginning April 15, 2022, and 100.000% for the twelve-month period beginning April 15, 2023 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 2025 Notes.

~~from any two of S&P Global Ratings, Moody’s Investors Service, Inc., and Fitch Ratings, Inc. At June 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Notes.~~

~~Other long-term obligations:~~ ~~These costs primarily relate to the long-term portion of production taxes payable and asset retirement obligations.~~

Operating Activities.During the six months ended June 30, ~~2018,~~2019, net cash provided by operating activities was ~~$205.8~~$215.1 million compared to ~~$136.5~~$205.8 million for the same period in ~~2017.~~2018. The increase in net cash provided by operating activities is ~~largely~~ attributable to ~~the timing of nonrecurring expenses related to the Company’s reorganization under chapter 11 proceedings~~an increase in net income and ~~partially offset by decreased oil and natural gas prices.~~an increase in working capital.

Investing Activities.During the six months ended June 30, ~~2018,~~2019, net cash used in investing activities was ~~$272.0~~$178.3 million as compared to ~~$220.3~~$272.0 million for the same period in ~~2017.~~2018. The ~~increase~~decrease in net cash used in investing activities is largely related to ~~increased~~decreased capital investments associated with the Company’s drilling ~~activities during~~activities. In 2018, the ~~six months ended June 30, 2017.~~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, ~~2018,~~2019, net cash used in financing activities was $48.0 million as compared to net cash provided by financing activities ~~was~~of $55.3 ~~million as compared to $120.3~~ million for the same period in ~~2017.~~2018. The ~~change~~increase in net cash ~~provided by~~used in financing activities is ~~primarily due~~attributable to the ~~restructuring of debt and equity as part~~payments on the Revolving Credit Facility from operating cash flows in excess of the ~~Company’s emergence from chapter 11 proceedings during~~borrowings for the six months ended June 30, ~~2017. See~~2019.

Please refer to the corresponding section in Part II, Item 7 and to Note 101, Significant Accounting Policies, included in Part II, Item 8 of our 2018 Form 10-K for ~~additional details.~~ 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, ~~2018.~~2019.

~~CAUTIONARY STATEMENT PURSUANT TO SAFE HARBOR PROVISION OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995~~

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of 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. All statements other than statements of historical facts 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, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and increased financing costs due to a significant increase in interest rates. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 ~~for additional risks related to the Company’s business~~.

ITEM 3 - — QUANTITATIVE AND ~~QUALITATIVE~~QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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, ~~2018,~~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.

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

Hedging (“ASC 815”). Derivative contracts that do not qualify for hedge accounting treatment are recorded at fair value as derivative assets and liabilities ~~at fair value~~ on the Condensed Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense ~~or income in~~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 ~~cash flow statement.~~Condensed Consolidated Statements of Cash Flows. The Company does not apply hedge accounting to any of its derivative instruments. See Note 710 of this report for ~~the detail of~~details regarding the fair value of the ~~following derivatives.~~derivative contracts described below.

Commodity Derivative Contracts: At June 30, ~~2018,~~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 ~~quarter~~three and six months ended June 30, ~~2018~~2019 and ~~2017:~~2018:

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 ~~our~~its management, including ~~our Interim~~its Chief Executive Officer and Chief Financial Officer, of the effectiveness of ~~our~~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 ~~Interim~~ 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 ~~Interim~~ Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of June 30, ~~2018.~~2019.

There were no changes in the Company’s internal control over financial reporting during the quarter ended June 30, ~~2018~~2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~Other Claims~~: See Note 912 for ~~additional~~ discussion of on-going claims and disputes inthat arose during our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of ~~operations.~~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. ~~There~~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, ~~2017.~~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.

~~None.~~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)

~~400 North Sam Houston Parkway~~116 Inverness Drive East, Suite ~~1200, Houston, Texas~~400 Englewood, Colorado	~~77060~~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	2523

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	3933

ITEM 4.	Controls and Procedures	4035

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	4136

ITEM 1A.	Risk Factors	4136

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4137

ITEM 3.	Defaults upon Senior Securities	4137

ITEM 4.	Mine Safety Disclosures	4137

ITEM 5.	Other Information	4137

ITEM 6.	Exhibits	4241

	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,
	2018			2017
Proven Properties:
Acquisition, equipment, exploration, drilling and abandonment costs	$	11,471,499		$	11,215,563
Less: Accumulated depletion, depreciation and amortization		(9,985,519	)		(9,890,495	)
	$	1,485,980		$	1,325,068

	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

	Shares Issued and Outstanding (000's)			Common Stock		Retained Loss			Treasury Stock			Total Shareholders' (Deficit) Equity
Balances at December 31, 2016		80,017		$	510,063	$	(3,438,165	)	$	(49	)	$	(2,928,151	)
Equitization of Holdco Notes		70,579			978,230		—			—			978,230
Rights Offering, including Backstop		44,390			573,774		—			—			573,774
Employee stock plan grants		10			—		—			—			—
Stock plan grants		2,191			26,673		—			—			26,673
Net share settlements		(840	)		—		(9,580	)		—			(9,580	)
Fair value of employee stock plan grants		—			27,278		—			—			27,278
Net income		—			—		177,140			—			177,140
Balances at December 31, 2017		196,347		$	2,116,018	$	(3,270,605	)	$	(49	)	$	(1,154,636	)
Stock plan grants		1,226			—		—			—			—
Net share settlements		(519	)		—		(2,061	)		—			(2,061	)
Fair value of employee stock plan grants		—			13,173		—			—			13,173
Net income		—			—		26,933			—			26,933
Initial adoption of ASC 606		—			—		1,765			—			1,765
Balances at June 30, 2018		197,054		$	2,129,191	$	(3,243,968	)	$	(49	)	$	(1,114,826	)

Current Presentation	June 30, 2018		June 30, 2017
Cash and Cash Equivalents	$	5,685	$	5,992
Restricted Cash		1,688		435,501
Total cash, cash equivalents, and restricted cash	$	7,373	$	441,493

	For the Six Months Ended June 30, 2018
	Under ASC 606		Under ASC 605		Increase/ (Decrease)
	(Amounts in 000's)
Revenues:
Natural gas sales	$	322,716	$	322,879	$	(163	)
Oil sales		84,451		84,451		—
Other revenues		8,344		8,344		—
Total operating revenues		415,511		415,674		(163	)
Costs and expenses:
Production taxes		42,153		42,169		(16	)
Gathering fees		47,238		47,257		(19	)
Net income	$	26,933	$	27,061	$	(128	)

	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

	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

	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

Year	Index	Total Volumes		Weighted Average Price per Unit			Fair Value - June 30, 2018
		(in millions)					Asset (Liability)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2018 (July through December)	NYMEX-Henry Hub		141.1	$	2.89		$	(9,430	)
2019	NYMEX-Henry Hub		167.3	$	2.85			(4,557	)
2020	NYMEX-Henry Hub		15.5	$	2.76			(2,662	)

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2018 (July through December)	NW Rockies Basis Swap		94.6	$	(0.68	)	$	(3,176	)
2019	NW Rockies Basis Swap		84.5	$	(0.70	)		(848	)
2020	NW Rockies Basis Swap		—	$	—			—

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2018 (July through December)	NYMEX-WTI	1.2		$	60.53		$	(12,050	)
2019	NYMEX-WTI	1.7		$	58.83			(11,645	)
2020	NYMEX-WTI	.09		$	60.05			(204	)

Type	Index	Total Volumes	Weighted Average Price per Unit
		(in millions)
Natural gas basis swaps (1)		(Mmbtu)	($/Mmbtu)
2018 (August through October)	NYMEX-Henry Hub	6.4	$	(0.48	)

	June 30, 2018				December 31, 2017
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
Term loan, secured, due April 2024	$	972,563	$	889,895	$	975,000	$	975,000
6.875% Notes, unsecured, due April 2022, issued 2017		700,000		530,432		700,000		701,750
7.125% Notes, unsecured, due April 2025, issued 2017		500,000		351,250		500,000		505,000
Credit Facility, secured, due January 2022		58,000		58,000		—		—
Long-term debt	$	2,230,563	$	1,829,577	$	2,175,000	$	2,181,750

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

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

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

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

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

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

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

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

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

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

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

10.1		~~Second~~Fourth Amendment to Credit Agreement dated ~~April 19, 2018, by and~~as of February 14, 2019, among Ultra Resources, Inc. as ~~a Borrower,~~borrower, Bank of Montreal, as ~~Administrative Agent for the Lenders,~~administrative agent, and each of the ~~Lenders~~lenders and other parties party ~~thereto.~~thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on ~~April 20, 2018)~~February 19, 2019).

~~10.2~~*#10.2		Employment Agreement dated as of ~~Jerald J. “Jay” Stratton~~April 22, 2019 by and between Ultra Petroleum Corp. and Kason Kerr.
*#10.3		Employment Agreement dated ~~May 31, 2018~~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 ~~1, 2018)~~20, 2019).
~~10.3~~		Ultra Petroleum Corp. 2017 Stock Incentive Plan, as amended and restated June 8, 2018 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on June 14, 2018).
~~10.4~~#10.5		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit ~~10.2~~10.4 to the ~~Current Report on~~ Form ~~8-K~~10-Q filed by Ultra Petroleum Corp. on ~~June 14, 2018)~~May 9, 2019).

*31.1 #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 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***101.INS		XBRL Instance Document.

101.SCH***101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL***101.CAL		XBRL Taxonomy Calculation Linkbase Document.

101.LAB***101.LAB		XBRL Label Linkbase Document.

101.PRE***101.PRE		XBRL Presentation Linkbase Document.

101.DEF***101.DEF		XBRL Taxonomy Extension Definition.

	ULTRA PETROLEUM CORP.

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

Date: August 9, ~~2018~~2019

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

Date: August 9, ~~2018~~2019

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