UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, ~~2017~~2018

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

For the transition period fromto

Commission file number001-33614

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)


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

400 North Sam Houston Parkway East, Suite 1200, Houston, Texas		77060
(Address of principal executive offices)		(Zip code)

(281) 876-0120

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T 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, anon-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”,~~filer,” “smaller reporting ~~company”,~~company,” and “emerging growth company” in Rule12b-2 of the Exchange Act. (Check one):


Large accelerated filer	☐ ☑	Accelerated filer	☒ ◻

Non-accelerated filer	☐ ◻ (Do not check if a smaller reporting company)	Smaller reporting company	☐ ◻

		Emerging growth company	☐ ◻

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 inRule 12b-2 of the Act). YES ☐ NO ☒☑

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

The number of shares, ~~outstanding,~~ without par value, of Ultra Petroleum Corp., outstanding as of ~~August 2, 2017~~July 25, 2018 was ~~196,315,182.~~197,054,917.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION


ITEM 1.	Financial Statements			3


ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
		25

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk			37
		39

ITEM 4.	Controls and Procedures			38	40

PART II — OTHER INFORMATION


ITEM 1.	Legal Proceedings			39
		41

ITEM 1A.	Risk Factors			39
		41

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds			39
		41

ITEM 3.	Defaults upon Senior Securities			39
		41

ITEM 4.	Mine Safety Disclosures			39
		41

ITEM 5.	Other Information			39
		41

ITEM 6.	Exhibits		~~Exhibits~~			40	42

	Signatures			42	43

PART I – ~~FINANCIAL~~FINANCIAL INFORMATION

ITEM1 – FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,						For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(Unaudited)												(Unaudited)
	(Amounts in thousands of U.S. dollars, except per share data)												(Amounts in thousands of U.S. dollars, except per share data)
Revenues:
Natural gas sales	$	179,997		$	116,780		$	368,848		$	254,882		$	141,255		$	179,997		$	322,716		$	368,848
Oil sales		30,732			29,811			62,081			51,095			43,167			30,732			84,451			62,081
Other revenues		1,928			—			2,687			—			5,716			1,928			8,344			2,687

Total operating revenues		212,657			146,591			433,616			305,977			190,138			212,657			415,511			433,616

Expenses:
Lease operating expenses		23,089			21,836			46,225			47,230			23,645			23,089			45,409			46,225
Liquids gathering system operating lease expense		5,226			5,171			10,452			10,343
Facility lease expense														6,526			5,226			12,682			10,452
Production taxes		21,754			13,474			43,887			28,706			18,883			21,754			42,153			43,887
Gathering fees		20,642			21,504			41,571			43,954			24,181			20,642			47,238			41,571
Transportation charges		—			146			—			23,701
Depletion, depreciation and amortization		38,673			31,234			70,427			62,083			51,742			38,673			102,282			70,427
General and administrative		25,009			1,381			26,061			5,600			2,063			25,009			14,752			26,061

Total operating expenses		134,393			94,746			238,623			221,617			127,040			134,393			264,516			238,623
Operating income		78,264			51,845			194,993			84,360			63,098			78,264			150,995			194,993

Other income (expense), net:
Interest expense		(29,425	)		(16,662	)		(114,872	)		(66,565	)		(37,715	)		(29,425	)		(73,552	)		(114,872	)
Gain on commodity derivatives		20,717			—			7,499			—
(Loss) gain on commodity derivatives														(47,271	)		20,717			(53,803	)		7,499
Deferred gain on sale of liquids gathering system		2,638			2,638			5,276			5,276			2,638			2,638			5,276			5,276
Restructuring expenses		—			(1,569	)		—			(7,148	)
Contract settlement expense		—			—			(52,707	)		—			—			—			—			(52,707	)
Other income (expense) , net		27			(227	)		(119	)		(1,922	)

Other income (expense), net														(1,296	)		27			(1,541	)		(119	)
Total other (expense) income, net		(6,043	)		(15,820	)		(154,923	)		(70,359	)		(83,644	)		(6,043	)		(123,620	)		(154,923	)
Reorganization items, net		426,816			(22,183	)		369,270			(22,183	)		—			426,816			—			369,270

Income (loss) before income tax (benefit) provision		499,037			13,842			409,340			(8,182	)
Income tax (benefit) provision		—			(160	)		2			(350	)

Net income (loss)	$	499,037		$	14,002		$	409,338		$	(7,832	)

Basic income (loss) per share:
Net income (loss) per common share - basic	$	2.76		$	0.18		$	3.13		$	(0.10	)

Fully diluted income (loss) per share:
Net income (loss) per common share - fully diluted	$	2.76		$	0.17		$	3.12		$	(0.10	)

(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
Weighted average common shares outstanding - basic		180,964			80,002			130,770			79,984			197,054			180,964			196,803			130,770

Weighted average common shares outstanding - fully diluted		181,033			80,333			131,078			79,984			197,054			181,033			196,803			131,078

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,			June 30,			December 31,
	2017			2016			2018			2017
	(Unaudited)						(Unaudited)
	(Amounts in thousands of U.S. dollars, except share data)						(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	5,992		$	401,478		$	5,685		$	16,631
Restricted cash		435,501			3,571			1,688			1,638
Oil and gas revenue receivable		76,094			79,179			64,123			86,487
Joint interest billing and other receivables		14,590			10,781			20,865			16,616
Deposits and retainers		—			13,359
Derivative assets		8,367			—			14,480			16,865
Income tax receivable		—			2,099			6,431			10,091
Inventory		7,533			4,906			17,747			13,450
Other current assets		11,220			6,020			3,143			5,647

Total current assets		559,297			521,393			134,162			167,425
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,186,073			1,010,466			1,485,980			1,325,068
Property, plant and equipment, net		7,737			7,695			10,887			9,569
Other		8,896			1,374

Other assets								10,831			10,920
Total assets	$	1,762,003		$	1,540,928		$	1,641,860		$	1,512,982


LIABILITIES AND SHAREHOLDERS’ EQUITY

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	59,736		$	28,171		$	41,426		$	59,951
Accrued liabilities		237,466			53,348			75,806			80,268
Production taxes payable		45,198			44,329			55,048			51,352
Current portion of long-term debt								2,438			—
Interest payable		20,625			—			20,759			24,406
Derivative liabilities								54,891			—
Capital cost accrual		20,178			12,360			18,030			32,513

Total current liabilities		383,203			138,208			268,398			248,490
Long-term debt		2,016,914			—			2,176,408			2,116,211
Deferred gain on sale of liquids gathering system		110,465			115,742			99,912			105,189
Other long-term obligations		191,524			177,088			211,968			197,728

Total liabilities not subject to compromise		2,702,106			431,038
Liabilities subject to compromise		—			4,038,041
Commitments and contingencies (Note 8)
Shareholders’ equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 196,315,182 and 80,017,020 at June 30, 2017 and December 31, 2016, respectively		2,098,355			510,063
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	)		(49	)		(49	)
Retained loss		(3,038,409	)		(3,438,165	)		(3,243,968	)		(3,270,605	)

Total shareholders’ deficit		(940,103	)		(2,928,151	)

Total liabilities and shareholders’ equity	$	1,762,003		$	1,540,928

Total shareholders' deficit								(1,114,826	)		(1,154,636	)
Total liabilities and shareholders' equity							$	1,641,860		$	1,512,982

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

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

   Shares
Issued and
Outstanding
(000’s) Common
Stock    Retained
Loss Treasury
Stock Total
Shareholders’
(Deficit)
Equity
Balances at December 31, 2015
   79,933 $ 502,050    $ (3,493,811 ) $ (176 ) $ (2,991,937 )
Employee stock plan grants
   145 —      —   —   —
Sharesre-issued from treasury
   —   —      (127 ) 127 —
Net share settlements
   (61 ) —      (379 ) —   (379 )
Fair value of employee stock plan grants
   —   8,014    —   —   8,014
Net income
   —   —      56,151 —   56,151




Balances at December 31, 2016
   80,017 $ 510,064    $ (3,438,166 ) $ (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
   2,160 26,417    —   —   26,417
Net share settlements
   (841 ) —      (9,581 ) —   (9,581 )
Fair value of employee stock plan grants
   —   9,870    —   —   9,870
Net income
   —   —      409,338 —   409,338




Balances at June 30, 2017
   196,315 $ 2,098,355    $ (3,038,409 ) $ (49 ) $ (940,103 )

~~See accompanying notes to consolidated financial statements~~

~~Shareholders’ Equity Explanatory Note~~:

~~In conjunction with emergence from chapter 11, the Company issued new Common Shares to holders of existingpre-petition~~ Common Shares (the “Existing Common Shares”) at a conversion ratio of 0.521562 (the “New Equity”). As a result, the share counts have been adjusted to reflect this conversion as if it had occurred as of January 1, 2016.

~~Consistent with the Plan, 194,991,656 shares of New Equity were issued as follows:~~

•

~~70,579,367 shares of New Equity were issued pro rata to holders of the HoldCo Notes with claims allowed under the~~~~Debtors~~’ ~~Second Amended Joint Chapter 11 Plan of Reorganization~~;

~~80,022,410 shares of New Equity were issued pro rata to holders of Existing Common Shares;~~

	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	)

~~2,512,623 shares of New Equity were issued to commitment parties under the Backstop Commitment Agreement in respect of the commitment premium due thereunder;~~

~~18,844,363 shares of New Equity were issued to commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder; and~~

~~23,032,893 shares of New Equity were issued to participants in the Rights Offering.~~

~~ULTRA PETROLEUM CORP.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

   Six Months Ended
   June 30,
   2017 2016
   (Unaudited)
   (Amounts in thousands of U.S. dollars)
Operating activities - cash provided by (used in):

Net income (loss) for the period
   $ 409,338 $ (7,832 )
Adjustments to reconcile net income (loss) to cash provided by operating activities:

Depletion, depreciation and amortization
   70,427 62,083
Deferred income tax benefit
   —   1
Unrealized gain on commodity derivatives
   (8,367 ) —
Deferred gain on sale of liquids gathering system
   (5,276 ) (5,276 )
Stock compensation
   26,264 2,704
Non-cash reorganization items, net
   (431,579 ) 22,324
Other
   1,160 5,907
Net changes in operating assets and liabilities:

Restricted cash
   (18,194 ) (3,219 )
Accounts receivable
   283 5,382
Other current assets
   7,972 (13,277 )
Othernon-current assets
   144 (818 )
Accounts payable
   30,245 (70,552 )
Accrued liabilities
   (8,654 ) (11,596 )
Production taxes payable
   869 (7,467 )
Interest payable
   32,438 57,118
Other long-term obligations
   3,808 (3,465 )
Income taxes payable/receivable
   2,099 (279 )


Net cash provided by operating activities
   112,977 31,738


Investing Activities - cash provided by (used in):

Oil and gas property expenditures
   (225,057 ) (121,542 )
Change in capital cost accrual
   7,740 (13,500 )
Inventory
   (2,276 ) (196 )
Purchase of capital assets
   (756 ) 122


Net cash used in investing activities
   (220,349 ) (135,116 )


Financing activities - cash provided by (used in):

Borrowings under Credit Agreement
   144,000 369,000
Borrowings under Term Loan
   800,000 —
Extinguishment of long-term debt - (chapter 11)
   (2,459,000 ) —
Payments under Credit Agreement
   (67,000 ) —
Proceeds from issuance of Senior Notes
   1,200,000 —
Deferred financing costs
   (70,071 ) —
Shares issued, net of transaction costs
   573,774 (307 )
Repurchased shares/net share settlements
   (9,581 ) —
Reserve Fund
   (400,236 ) —


Net cash (used in) provided by financing activities
   (288,114 ) 368,693


(Decrease) increase in cash and cash equivalents during the period
   (395,486 ) 265,315
Cash and cash equivalents, beginning of period
   401,478 4,143


Cash and cash equivalents, end of period
   $ 5,992 $ 269,458

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2018				2017
	(Unaudited)
	(Amounts in thousands of U.S. dollars)
Operating activities - cash provided by (used in):				��
Net income for the period	$	26,933			$	409,338
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		102,282				70,427
Unrealized loss (gain) on commodity derivatives		61,539				(8,367	)
Deferred gain on sale of liquids gathering system		(5,276	)			(5,276	)
Stock compensation		10,122				26,264
Non-cash reorganization items, net		—				(431,579	)
Amortization of deferred financing costs		5,510				2,224
Other		207				(1,060	)
Net changes in operating assets and liabilities:
Accounts receivable		17,738				283
Other current assets		3,783				7,972
Other non-current assets		338				144
Accounts payable		(18,525	)			30,245
Accrued liabilities		(4,116	)			(3,368	)
Production taxes payable		3,696				869
Interest payable		(3,647	)			32,438
Other long-term obligations		(1,647	)			3,808
Income taxes payable/receivable		6,844				2,099
Net cash provided by operating activities		205,781				136,461
Investing Activities - cash provided by (used in):
Oil and gas property expenditures		(250,966	)			(225,057	)
Change in capital cost accrual		(14,483	)			7,740
Inventory		(4,140	)			(2,276	)
Purchase of capital assets		(2,389	)			(756	)
Net cash used in investing activities		(271,978	)			(220,349	)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement		450,000				144,000
Payments under Credit Agreement		(392,000	)			(67,000	)
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
Deferred financing costs		(638	)			(61,861	)
Shares issued, net of transaction costs		—				573,774
Repurchased shares/net share settlements		(2,061	)			(9,581	)
Net cash provided by financing activities		55,301				120,332
(Decrease) increase in cash during the period		(10,896	)			36,444
Cash, cash equivalents, and restricted cash, beginning of period		18,269				405,049
Cash, cash equivalents and restricted cash, end of period	$	7,373			$	441,493

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(All amounts in this Quarterly Report on Form10-Q are expressed in thousands of U.S. dollars (except per share data) unless otherwise noted).

DESCRIPTION OF THE BUSINESS:

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

~~Chapter 11 Proceedings~~

~~Voluntary Reorganization Under Chapter 11~~

On April 29, 2016 (the “Petition Date”), the Company and its subsidiaries (collectively, the “Debtors”) 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, CaseNo. 16-32202~~ ~~(MI) (Bankr. S.D. Tex.).~~

~~On February 21, 2017, the Bankruptcy Court approved our amended Disclosure Statement, 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.~~

As a result of our improved financial condition and successful emergence from chapter 11, we believe we now have sufficient liquidity to fund our future cash requirements for operations, capital expenditures and working capital purposes. As a result, substantial doubt no longer exists regarding the Company’s ability to meet its obligations as they become due within one year after the date that the financial statements are issued.

Because we emerged from bankruptcy during the quarter ended June 30, 2017 and because we continue our work to reconcile, resolve and pay certain prepetition claims asserted against us during our chapter 11 cases, certain aspects of our chapter 11 cases are described below to provide context to our financial condition and results of operations for the period presented in this Quarterly Report on Form~~10-Q.~~ ~~Information about our chapter 11 cases is available at a website maintained by our claims agent, Epiq Systems(http://dm.epiq11.com/UPT/Docket)~~.

In addition, because our operations and ability to execute our business remain subject to various risks and uncertainties, including risks and uncertainties related to our chapter 11 cases, readers are encouraged to review and consider the items described in Item 1A, “Risk Factors” in this report.

~~Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing Commitment Letter~~

~~As previously disclosed:~~

On November 21, 2016, we entered into a Plan Support Agreement (as amended, the “PSA”) with certain holders of the Company’s prepetition indebtedness and outstanding common stock as well as a Backstop Commitment Agreement (“BCA”). Pursuant to the BCA, we agreed to conduct a rights offering for new common stock in the Company to be issued upon the effectiveness of the Plan for an aggregate purchase price of $580.0 million (the “Rights Offering”).

On February 8, 2017, we entered into a commitment letter with Barclays Bank PLC (“Barclays”) (as amended, the “Commitment Letter”) pursuant to which, in connection with the consummation of the Plan, Barclays agreed to provide us with secured and unsecured financings in an aggregate amount of up to $2.4 billion (the “Debt Financings”).

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

On the Effective Date, the principal obligations outstanding of $999.0 million under the Prepetition Credit Agreement and $1.46 billion under the Prepetition Senior Notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under the Prepetition Credit Agreement and the Prepetition Senior Notes were cancelled and extinguished as provided in the Plan.

On the Effective Date, the claims of $450.0 million related to the unsecured 2018 Notes and $850.0 million related to the unsecured 2024 Notes were allowed in full, each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of the holders’ applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan.

~~On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.~~

~~Fresh Start Accounting~~

As previously disclosed, we are 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.

~~Liabilities Subject to Compromise~~

~~The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through the six months ended June 30, 2017:~~

   June 30, 2017
Liabilities subject to compromise at December 31, 2016
   $ 4,038,041
Debt extinguishment - cash
   (2,521,493 )
Debt extinguishment -non-cash
   (1,339,740 )
Contract settlement
   (17,350 )
Reclassified to accrued liabilities
   (159,458 )


Liabilities subject to compromise at June 30, 2017
   $ —

~~Bankruptcy Claims Resolution Process~~

The claims filed against us during our chapter 11 proceedings are 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.~~

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.

~~Costs of Reorganization~~

We have incurred significant costs associated with our reorganization and the chapter 11 proceedings. We expect these costs, which are being expensed as incurred, have affected and may continue to significantly affect our results of operations. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

Wyoming.

~~The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the six months ended June 30, 2017 and 2016:~~1. SIGNIFICANT ACCOUNTING POLICIES:

   For the Three Months Ended    For the Six Months Ended
   June 30, 2017    June 30, 2016    June 30, 2017    June 30, 2016
Professional fees(1)
   $ (4,313 )    $ (3,582 )    $ (62,004 )    $ (3,582 )
Gains (losses)(2)
   431,107    —      431,107    —
Deferred financing costs
   —      (18,742 )    —      (18,742 )
Other(3)
   22    141    167    141








Total Reorganization items, net
   $ 426,816    $ (22,183 )    $ 369,270    $ (22,183 )

⁽¹⁾	~~The six months ended June 30, 2017 includes $23.0 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings.~~

⁽²⁾	~~Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 and 2024 Notes.~~

⁽³⁾	~~Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.~~

1.	~~SIGNIFICANT ACCOUNTING POLICIES:~~

The accompanying financial statements, other than the balance sheet data as of December 31, ~~2016,~~2017, are unaudited and were prepared from the Company’s records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, ~~2016~~2017 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments 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 andRegulation ~~S-X.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 onForm 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 onForm 10-K.

(a) Basis of ~~presentation~~Presentation and ~~principles~~Principles of ~~consolidation:~~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 the funds we deposited in the $400.0 million reserve account, pending resolution of make-whole and post-petition interest claims (the “Reserve Fund”), as described in Note 8, funds we deposited in the $35.0 million reserve account for the purpose of paying allowed and unpaid professional fees under the Plan agreement, and 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 fund 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.

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

(d)Accounts ~~Receivable:~~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.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(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”) ReleaseNo. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC ReleaseNo. 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

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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 theunits-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 SECRegulation ~~S-XRule~~S-X Rule 4-10. The ceiling test is performed quarterly, on acountry-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding ~~twelve month~~twelve-month period in accordance with SEC ReleaseNo. 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 anon-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 ~~for~~during the six months ended June 30, ~~2017~~2018 or ~~2016.~~2017.

(g)Inventories: ~~At June 30, 2017 and 2016, inventory of $7.5 million and $4.1 million, respectively,~~ Inventory primarily includes ~~the cost of~~$16.4 million in pipe and production equipment that will be utilized during the ~~2017~~2018 drilling program and $1.3 million in crude oil ~~inventory.~~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 ASUNo. 2015-3,Interest – Imputation of Interest (Subtopic835-30): Simplifying the Presentation of Debt Issuance Costsand includes the costs for issuing debt, including issuance discounts, except those related to the ~~revolving credit facility,~~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~~Revolving Credit Facility are recorded as an asset in the Consolidated Balance Sheets.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(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~~See Note 67 for ~~more information).~~

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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)~~Equity Interests:~~ In accordance with the Plan, each of the Company’s equity interests outstanding prior to the Effective Date were cancelled and each such equity interest has no further force or effect after the Effective Date. Pursuant to the Plan, the holders of the Company’s common shares outstanding prior to the Effective Date (the “Existing Common Shares”) received (i) their proportionate distribution of New Equity and (ii) the right to participate in the Rights Offering. The holders of all other equity interests in the Company received no distribution under the Plan in respect thereof.

~~(l)~~Earnings ~~(Loss)~~ Per Share: Basic earnings ~~(loss)~~ per share is computed by dividing net earnings ~~(loss)~~ attributable to common stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings ~~(loss)~~ 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.

In conjunction with our emergence from chapter 11, on April 12, 2017, the Company issued shares of New Equity to holders of Existing Common Shares at a conversion ratio of 0.521562. As a result, the basic and fully diluted share counts have been presented to reflect this conversion as if it had occurred as of January 1, 2016.

~~Share based~~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 quarter and six months ended June 30, 2018 and 2017, the Company had 2.6 million and 4.2 million contingently issuable shares that are not included in the diluted earnings per share denominator as the performance or market criteria have not been ~~met (See~~met. See Note ~~4). There were no contingently issuable shares outstanding~~5 for ~~the quarter and six months ended June 30, 2016.~~additional details.

   Three Months    Six Months
   Ended June 30,    Ended June 30,
   2017    2016    2017    2016
   (Share amounts in 000’s)
Net income (loss)
   $ 499,037    $ 14,002    $ 409,338    $ (7,832 )








Weighted average common shares outstanding - basic
   180,964    80,002    130,770    79,984
Effect of dilutive instruments
   69    331    308    —








Weighted average common shares outstanding - diluted
   181,033    80,333    131,078    79,984








Net income (loss) per common share - basic
   $ 2.76    $ 0.18    $ 3.13    $ (0.10 )








Net income (loss) per common share - diluted
   $ 2.76    $ 0.17    $ 3.12    $ (0.10 )








Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares (1)
   —      749    —      —

~~(1)~~

~~Due to the net loss for the six months ended June 30, 2016, 0.8 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.~~

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

	For the Quarter Ended					For the Six Months Ended
	June 30,					June 30,
	2018			2017		2018		2017
	(Share amounts in 000's)
Net (loss) income	$	(20,555	)	$	499,037	$	26,933	$	409,338
Weighted average common shares outstanding - basic		197,054			180,964		196,803		130,770
Effect of dilutive instruments		—			69		—		308
Weighted average common shares outstanding - diluted		197,054			181,033		196,803		131,078
Net (loss) income per common share - basic	$	(0.10	)	$	2.76	$	0.14	$	3.13
Net (loss) income per common share - diluted	$	(0.10	)	$	2.76	$	0.14	$	3.12

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

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

~~(o)~~(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 78 for additional ~~information.~~details.

~~(p)~~9

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(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 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.

~~(q)~~(p) Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. ~~The~~On January 1, 2018, the Company ~~recognizes revenues when~~adopted the ~~oil~~new accounting standard, ASC 606, Revenue from Contracts with Customers and ~~natural gas is delivered, which occurs when the customer has taken title~~all related amendments. See Note 2 for additional details and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upondisclosures related to the Company’s ~~ownership share~~adoption of volumes sold, regardless of whether it has taken its ownership share of such volumes. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable.this standard.

(q) ~~Make-up~~ provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. The Company’s imbalance obligations as of June 30, 2017 and December 31, 2016 were immaterial.

~~(r)~~Other revenues: Other ~~revenues are~~revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed ~~in exchange for the liquids removed from our production.~~.

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

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

~~(u)~~~~Deposits and Retainers:~~ ~~Deposits and retainers primarily consist of payments related to surety bonds.~~

~~(v)~~(t) Recent Accounting ~~Pronouncements~~Pronouncements:

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~In November 2016, the FASB issued ASU~~Leases.~~2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash~~ ~~(“ASUNo. 2016-18”).~~ The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. ASU~~No. 2016-18~~ also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company is still evaluating the impact of ASU~~No. 2016-18~~ ~~on its consolidated financial statements.~~

~~In August 2016, the FASB issued ASU2016-15,~~ ~~Statement of Cash Flows (Topic 230)~~ ~~(“ASUNo. 2016-15”).~~ The guidance requires that debt prepayment or debt extinguishment costs, including third-party costs, premiums paid, and other fees paid to lenders, be classified as cash outflows for financing activities. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company does not expect the adoption of ASU~~No. 2016-15~~ ~~to have a material impact on its consolidated financial statements.~~

In February 2016, the FASB issued ASU 2016-02, Leases~~2016-02,~~~~Leases~~ (“ASUNo. 2016-02”). 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 also require 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 has formed an implementation work team, developed a project plan, educated departments affected by the standard, begun the process 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”), 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 ~~standard~~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 ASUNo. 2016-02 and ASU No. 2018-01 on its consolidated financial ~~statements.~~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.

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU2014-09,Revenue from Contracts with Customers (Topic 606)and in 2016, the FASB issued ASU2016-08,Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), and ASU2016-10,Revenues from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which supersede the revenue recognition

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic932-605, Extractive~~Activities-Oil~~ Activities - Oil and~~Gas-Revenue~~ 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 ~~are currently evaluating~~recorded a net addition to beginning retained earnings of $1.8 million as of January 1, 2018 due to the ~~provisions~~cumulative impact of ~~ASU2014-09~~ ~~and assessing~~adopting Topic 606, with the impact ~~if any, it may have on our~~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 ~~position~~statements as a result of applying Topic 606. The comparative information has not been restated and ~~results~~continues to be reported under the accounting standards for those periods. See Note 2 for additional details related to the adoption of ~~operations. As part~~this standard. We expect the impact of ~~our assessment work to date, we have completed training~~the adoption of the new ~~ASU’s~~ revenue ~~recognition model, dedicated resources~~standard to ~~its implementation, and initiated contract review and documentation; including analyzing~~be immaterial to our net income on an on-going basis.

2. IMPACT OF ASC 606 ADOPTION

In accordance with the ~~standard’s~~new revenue standard requirements, the disclosure of the impact of adoption on our ~~contract portfolio, comparing historical accounting policies and practices~~consolidated income statement for the six months ended June 30, 2018 is as follows:

	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	)

The change to sales of natural gas is due to the ~~requirements of the new standard, and identifying differences~~change from applying the requirements of the new standards to our contracts. We are evaluating the expanded disclosure requirements under the new standard and are also reviewing our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures. While we are continuing to assess all potential impacts of the standard, we currently believe the most significant impacts relate to principal versus agent considerations and the use ofusing the entitlements method for production imbalances to the sales method. The Company evaluated the contracts for sales of oil and natural gas ~~sales, both~~utilizing the principal versus agent indicators, noting no change in revenue recognition resulted from the analysis.

Revenue Recognition

Revenue from Contracts with Customers

Sales of ~~which~~oil and natural gas are ~~continuing to be evaluated by the Company.~~

The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the ~~date~~point control of ~~initial application (the modified retrospective method).~~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.

Natural gas sales

We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point at the net price received. For these contracts, we have concluded that the Company ~~currently anticipates adopting~~is the ~~standard using~~principal for our net revenue interest share of the ~~modified retrospective method.~~volumes being sold. Gathering fees are

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 Consolidated Statement of Operations.

2.	~~OIL AND GAS PROPERTIES AND EQUIPMENT:~~

   June 30,    December 31,
   2017    2016
Proven Properties:

Acquisition, equipment, exploration, drilling and abandonment costs
   $ 10,992,163    $ 10,752,642
Less: Accumulated depletion, depreciation and amortization
   (9,806,090 )    (9,742,176 )




   $ 1,186,073    $ 1,010,466

3.	~~DEBT AND OTHER LONG-TERM OBLIGATIONS:~~

   June 30,    December 31,
   2017    2016
Total Debt:

Term loan, secured, due 2024
   $ 800,000    $ —
6.875% Senior, unsecured Notes due 2022
   700,000    —
7.125% Senior, unsecured Notes due 2025
   500,000    —
6.125% Senior Notes due 2024
   —      850,000
5.75% Senior Notes due 2018
   —      450,000
Senior Notes issued by Ultra Resources, Inc.
   —      1,460,000
Credit Agreement
   77,000    999,000




Total long-term debt
   2,077,000    3,759,000
Less: Deferred financing costs
   (60,086 )    —
Less: Liabilities subject to compromise(1) (See Note 1)
   —      (3,759,000 )




Total long-term debt not subject to compromise
   $ 2,016,914    $ —




Other long-term obligations:

Other long-term obligations
   $ 191,524    $ 177,088

⁽¹⁾

All of our indebtedness that was outstanding at December 31, 2016 was classified as liabilities subject to compromise in the Consolidated Balance Sheets. See below for information about the indebtedness we incurred in connection with, and that is now outstanding following, our emergence from bankruptcy.

~~As previously disclosed~~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.

Oil sales

We sell oil production at (a) the lease automatic custody transfer (LACT) meter for Wyoming condensate, (b) the tank battery for Utah wax/condensate, or (c) a ~~Current Report on Form8-K~~ ~~filed~~delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect (i) an agreed upon index price, net of pricing differentials or (ii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Consolidated Statement of Operations. In conjunction with the ~~SEC on April 18, 2017, on the Effective Date, all principal, prepetition interest, and other undisputed amounts were paid in full~~adoption of ASC 606, for the ~~amounts owed under~~six months ended June 30, 2018, there was no change to the ~~prepetition Credit Agreement~~method used to recognize oil sales and there was no impact to the ~~prepetition Senior Notes shown~~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 ~~table above~~production.

Other revenues

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 ~~Company’s obligations under~~point in time that the ~~prepetition Credit Agreement and~~control is transferred. In conjunction with the ~~prepetition Senior Notes were cancelled and extinguished. The claims related~~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.

Production imbalances

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.

Transaction price allocated to remaining performance obligations

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

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and ~~2024 Notes, shown~~disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract balances

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

Prior-period performance obligations

We record revenue in the ~~table above were allowed in full, each claim holder~~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 ~~distribution of our common stock in~~result, we are required to estimate the amount of production delivered to the ~~applicable claim,~~purchaser and the ~~Company’s~~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, revenue recognized in the reporting period related to performance obligations ~~under the 2018 and 2024 Notes were cancelled and extinguished.~~satisfied in prior reporting periods was not material.

3. OIL AND GAS PROPERTIES AND EQUIPMENT:

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

4. DEBT AND OTHER LONG-TERM OBLIGATIONS:

June 30,

December 31,

2018

2017

Total Debt:

Current portion of long-term debt

$
2,438

$
—

Term loan, secured due 2024

$
972,563

$
975,000

6.875% Senior, unsecured Notes due 2022

700,000

700,000

7.125% Senior, unsecured Notes due 2025

500,000

500,000

Credit Agreement

58,000

—

Long-term debt

2,230,563

2,175,000

Less: Deferred financing costs

(54,155
)

(58,789
)
Total long-term debt

$
2,176,408

$
2,116,211

Other long-term obligations:

Other long-term obligations

$
211,968

$
197,728

Ultra Resources, Inc.

Credit Agreement. On In April ~~12,~~ 2017, Ultra Resources, Inc. (“Ultra Resources”), as athe borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto ~~(as amended, the “RBL Credit Agreement”),~~from time to time, providing for a revolving credit facility (the “Revolving Credit ~~Facility,” and together with the Term Loan Facility (defined below), the “Credit Facilities”~~Facility”) for an aggregate amount of $400.0 ~~million. At June 30, 2017, Ultra Resources had $77.0~~ million ~~in outstanding borrowings under the RBL Credit Agreement.~~

~~The~~and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan ~~Facility) is~~Agreement (defined below)). In September 2017, the administrative agent and the other lenders approved an increase in the borrowing base under the Credit Agreement 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 ~~there~~the other lenders reaffirmed the borrowing base at $1.4 billion. There are no scheduled borrowing base ~~redeterminations until October 1, 2017.~~

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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. ~~The weighted average~~If borrowings are outstanding during a period that the Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter as described below, the interest rate on such borrowings shall be at ~~June 30, 2017 was 3.93%.~~a per annum rate that is 0.25% higher than the rate that would otherwise apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022.

The ~~RBL~~Revolving Credit ~~Agreement~~Facility requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, of 1.00 to 1.00; (iii) a consolidated net leverage ratio ~~of (A) 4.25~~that does not exceed (a) 4.50 to 1.00, ~~as of~~during the period ending on the last day of ~~any~~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 ~~or before December~~March 31, ~~2017 and (B) 4.00 to 1.00, as of the last day of any fiscal quarter thereafter;~~2020; and (iv) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At June 30, ~~2017,~~2018, Ultra Resources was in compliance with all of its debt covenants under the ~~RBL~~Revolving Credit ~~Agreement.~~Facility.

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

The ~~RBL~~Revolving Credit ~~Agreement~~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 ~~RBL~~Revolving Credit ~~Agreement,~~Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the ~~RBL~~Revolving Credit ~~Agreement~~Facility and any outstanding unfunded commitments may be terminated.

Term Loan.On In April ~~12,~~ 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans ~~(the “Term Loan Facility”)~~ for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of 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 the Term Loan Agreement to $975.0 million. As part of the Term Loan ~~agreement,~~Agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal ~~amount. The original issue discount of $8.0 million~~amount, which is included in the deferred financing costs noted ~~above and is a direct deduction from the carrying amount of long-term debt.~~above. The Term Loan ~~Facility~~Agreement has capacity to increase the commitments subject to certain conditions. At June 30, ~~2017,~~2018, Ultra Resources had ~~$800.00~~$975.0 million in outstanding borrowings under the Term Loan ~~Facility.~~Agreement, including current maturities.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Term Loan ~~Facility~~Agreement bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points. The Term Loan ~~Facility~~Agreement amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan ~~Facility~~Agreement matures ~~seven years after the Effective Date.~~on April 12, 2024.

The Term Loan ~~Facility~~Agreement is subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain exceptions, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments are applied to prepay the Term Loan ~~Facility.~~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, ~~2017,~~2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan ~~Facility.~~

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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.

Senior Notes. OnIn April ~~12,~~ 2017, the Company issued ~~$700.0~~$700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “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 tonon-U.S. persons pursuant to Regulation S under the Securities Act.

The 2022 Notes will mature on April 15, 2022. The interest payment dates for the 2022 Notes are April 15 and October 15 of each ~~year, commencing on October 15, 2017.~~year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Notes from the issue date until maturity.

Prior to April 15, 2019, 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 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 2022 Notes.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

5. SHARE BASED COMPENSATION:

Valuation and Expense Information

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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Performance Share Plans:

2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established pursuant to which 7.5% of the equity in the Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, and other employees of the Company (the “Reserve”). During 2017, Management Incentive Plan Grants (the “Initial MIP Grants”) were made to members of the board of directors (the “Board”), officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before the fifth anniversary of the Effective Date, as defined in Note 10, such Initial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time.

On June 8, 2018, each of the Board and the Compensation Committee of the Board (the “Committee”) approved an amendment and restatement of the 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:

provide that consultants, independent contractors and advisors are eligible to participate and receive equity awards in the A&R Stock Incentive Plan;

limit the aggregate incentive awards available to be granted to any outside director during a single calendar year ~~commencing~~to a maximum of $750,000;

revise the definition of a Change of Control to exclude a change in a majority of the members on the Board;

provide that, with respect to awards granted on or after June 8, 2018, no such awards will vest solely as a result of a Change of Control (as defined in the A&R Stock Incentive Plan) unless expressly provided otherwise in the applicable grant agreement or unless otherwise determined by the Committee; and

make certain other changes related to revisions to the U.S. Internal Revenue Code.

Stock-Based Compensation Cost:

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

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

Expense. For the 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.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6. INCOME TAXES:

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

The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2018. 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”) 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 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.

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.

7. DERIVATIVE FINANCIAL INSTRUMENTS:

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 capital investment program. These types of instruments may include fixed price swaps, costless collars, 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 hedging policy limits the volumes hedged to not be greater than 50% of its forecasted production volumes without Board approval. During 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.

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

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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Commodity Derivative Contracts: At June 30, 2018, 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. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

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	)

⁽¹⁾	Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period.

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.

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	)

⁽¹⁾	Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period.

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the quarter and six months ended June 30, 2018 and 2017:

	For the Quarter Ended						For the Six Months
	Ended June 30,						Ended June 30,
Commodity Derivatives:	2018			2017			2018			2017
Realized gain (loss) on commodity derivatives - natural gas (1)	$	10,982		$	(868	)	$	12,426		$	(868	)
Realized loss on commodity derivatives - oil (1)		(4,320	)		—			(4,690	)		—
Unrealized gain (loss) on commodity derivatives (1)		(53,933	)		21,585			(61,539	)		8,367
Total gain (loss) on commodity derivatives	$	(47,271	)	$	20,717		$	(53,803	)	$	7,499

⁽¹⁾	Included in (Loss) gain on commodity derivatives in the Consolidated Statements of Operations.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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.

8. FAIR VALUE MEASUREMENTS:

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:

Level 1:

Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.

Level 2:

Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3:

Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	14,480	$	—	$	14,480
Long-term derivative asset (1)		—		3,692		—		3,692
Total derivative instruments	$	—	$	18,172	$	—	$	18,172
Liabilities:
Current derivative liability	$	—	$	54,891	$	—	$	54,891
Long-term derivative liability (2)		—		7,853		—		7,853
Total derivative instruments	$	—	$	62,744	$	—	$	62,744

⁽¹⁾	Included in other assets in the Consolidated Balance Sheet.

⁽²⁾	Included in other long-term obligations in the Consolidated Balance Sheet.

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, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Fair Value of Financial Instruments

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 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 Company uses available market data and valuation methodologies to estimate the fair value of its debt. 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 financial position, results of operations or cash flows.

	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

9. COMMITMENTS AND CONTINGENCIES:

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 claims resolution process associated with our chapter 11 proceedings is on-going, and we expect it to continue for an indefinite period of time.

Pending Claims – Ultra Resources Indebtedness

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 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 the claims made by the holders of the Ultra Resources’ indebtedness for certain make-whole amounts and post-petition interest at the default rates provided for in the prepetition debt agreements. As previously disclosed, on September 22, 2017, the Bankruptcy Court denied our objection to the pending make-whole and postpetition interest claims. Further, on October 6, 2017, the Bankruptcy Court entered an order requiring us to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, we distributed $399.0 million from a $400.0 million reserve fund set up in connection with our emergence from chapter 11 proceedings to the parties asserting the make-whole and post-petition 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 the court order denying its objections to these claims, but it is not possible to determine the ultimate disposition of these matters at this time.

Royalties

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 the preliminary determination and the proof of claim. We have notified ONRR of several matters we believe ONRR may not have considered in preparing the preliminary determination notice, and we continue to be in discussions with ONRR related to these matters. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods. The Company is

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

Oil Sales Contract

On April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for 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.

Other Claims

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

10. CHAPTER 11 PROCEEDINGS

Voluntary Reorganization Under Chapter 11

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.

Plan of Reorganization

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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

•

On the Effective Date, the principal obligations outstanding of $999.0 million under the prepetition credit agreement and $1.46 billion under the prepetition senior notes, as well as prepetition interest and other undisputed amounts, were paid in full. The Company’s obligations under the prepetition credit agreement and the prepetition senior notes were cancelled and extinguished as provided in the Plan.

On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 million related to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full, each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan.

On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.

Fresh Start Accounting

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.

Bankruptcy Claims Resolution Process

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.

Costs of Reorganization

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:

	For the Quarter Ended			For the Six Months Ended
	June 30, 2017			June 30, 2017
Professional fees	$	(4,313	)	$	(62,004	)
Gains (losses) (1)		431,107			431,107
Other (2)		22			167
Total Reorganization items, net	$	426,816		$	369,270

⁽¹⁾	Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 Notes and 2024 Notes.

⁽²⁾	Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

11. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to June 30, 2018 for 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

•

On July 27, 2018, UPL Three Rivers Holdings, LLC, a subsidiary of the Company entered into a Purchase and Sale Agreement with an unnamed third party. Under the agreement, the Company agreed to sell all of its Utah assets to the third party for cash consideration of $75.0 million, subject to customary closing adjustments. The agreement contains representations and warranties, covenants and indemnification provisions that are typical for this type of transaction. The effective date of the proposed sale is May 1, 2018, and the transaction is expected to close during the third quarter of 2018. The closing is subject to satisfaction or waiver of specified conditions, including the material accuracy of the representations and warranties of the Company and the third party. There can be no assurance that these closing conditions will be satisfied. During the fiscal quarter ended June 30, 2018, the Company’s Utah assets produced approximately 2,000 barrels of oil equivalent per day.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION 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 consolidated financial statements and related notes. Except as otherwise indicated, all amounts are expressed in U.S. dollars.

Overview

Substantially all of the Company’s 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. Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with a portion of the Company’s revenues coming from oil sales from its properties in the Uinta Basin in Utah.

DESCRIPTION OF THE BUSINESS:

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, from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas and oil. See Note 7 for additional details.

During the quarter ended June 30, 2018, the average price realization for the Company’s natural gas was $2.28 per Mcf, including realized gains and losses on commodity derivatives, compared with $2.84 per Mcf during the quarter ended June 30, 2017. The Company’s average price realization for natural gas was $2.11 per Mcf, excluding the realized gains and losses on commodity derivatives 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 was $58.24 per barrel, including realized gains and losses on commodity derivatives, compared to $45.51 per barrel during the quarter ended June 30, 2017. The Company’s average price realization for oil was $64.71 per barrel, excluding the realized gains and losses on commodity derivatives during the quarter ended June 30, 2018, as compared with $45.51 per barrel during the quarter ended June 30, 2017.

2017 Chapter 11 Proceedings

As discussed in Note 10, the Company emerged from chapter 11 proceedings during the year ended December 31, 2017. The effects of the Plan (defined below) were included in the Consolidated Financial Statements as of December 31, 2017 and the related adjustments thereto were recorded in our Consolidated Statement of Operations as reorganization items for the quarter and six months ended June 30, 2018.

Voluntary Reorganization Under Chapter 11

Plan of Reorganization

Pursuant to the Plan:

On the Effective Date, the claims of $450.0 million related to the unsecured 5.75% Senior Notes due 2018 (the “2018 Notes”) and $850.0 million related to the unsecured 6.125% Senior Notes due 2024 (the “2024 Notes”) were allowed in full. Each holder of a claim related to the 2018 Notes and the 2024 Notes received a distribution of common stock in the amount of such holder’s applicable claim, and the Company’s obligations under the 2018 Notes and the 2024 Notes were cancelled and extinguished as provided in the Plan.

On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.

Fresh Start Accounting

Bankruptcy Claims Resolution Process

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.

Costs of Reorganization

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:

	For the Quarter Ended			For the Six Months Ended
	June 30, 2017			June 30, 2017
Professional fees	$	(4,313	)	$	(62,004	)
Gains (losses) (1)		431,107			431,107
Other (2)		22			167
Total Reorganization items, net	$	426,816		$	369,270

⁽¹⁾	Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 Notes and 2024 Notes.

⁽²⁾	Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.

Critical Accounting Policies

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.

	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	14,480	$	—	$	14,480
Long-term derivative asset (1)		—		3,692		—		3,692
Total derivative instruments	$	—	$	18,172	$	—	$	18,172
Liabilities:
Current derivative liability	$	—	$	54,891	$	—	$	54,891
Long-term derivative liability (2)		—		7,853		—		7,853
Total derivative instruments	$	—	$	62,744	$	—	$	62,744

⁽¹⁾	Included in other assets in the Consolidated Balance Sheet.

⁽²⁾	Included in other long-term obligations in the Consolidated Balance Sheet.

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 recognized 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-productive wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with 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.

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 as of June 30, 2018. 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”) 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 changes in the way that capital costs are recovered.

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 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.

Conversion of Barrels of Oil 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.

Recent accounting pronouncements:

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 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 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 has formed an implementation work team, developed a project plan, educated departments affected by the standard, begun the process 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”), 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.

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 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 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.

RESULTS OF OPERATIONS:

	For the Quarter Ended									For the Six Months
	Ended June 30,						%			Ended June 30,						%
	2018			2017			Variance			2018			2017			Variance
	(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	%
Crude oil and condensate (Bbl)		667			675			(1	)%		1,345			1,338			1	%
Total production (Mcfe)		70,894			67,118			6	%		143,198			131,084			9	%
Commodity Prices:
Natural gas ($/Mcf, excluding hedges)	$	2.11		$	2.85			(26	)%	$	2.39		$	3.00			(20	)%
Natural gas ($/Mcf, including realized hedges)	$	2.28		$	2.84			(20	)%	$	2.48		$	2.99			(17	)%
Oil and condensate ($/Bbl, excluding hedges)	$	64.71		$	45.51			42	%	$	62.79		$	46.39			35	%
Oil and condensate ($/Bbl, including realized hedges)	$	58.24		$	45.51			28	%	$	59.31		$	46.39			28	%
Revenues:
Natural gas sales	$	141,255		$	179,997			(22	)%	$	322,716		$	368,848			(13	)%
Oil sales		43,167			30,732			40	%		84,451			62,081			36	%
Other revenues		5,716			1,928			196	%		8,344			2,687			211	%
Total operating revenues	$	190,138		$	212,657			(11	)%	$	415,511		$	433,616			(4	)%
Derivatives:
Realized gain (loss) on commodity derivatives	$	6,662		$	(868	)		(868	)%	$	7,736		$	(868	)		(991	)%
Unrealized gain (loss) on commodity derivatives		(53,933	)		21,585			(350	)%		(61,539	)		8,367			(835	)%
Total gain (loss) on commodity derivatives	$	(47,271	)	$	20,717			(328	)%	$	(53,803	)	$	7,499			(817	)%
Operating Costs and Expenses:
Lease operating expenses	$	23,645		$	23,089			2	%	$	45,409		$	46,225			(2	)%
Facility lease expense	$	6,526		$	5,226			25	%	$	12,682		$	10,452			21	%
Production taxes	$	18,883		$	21,754			(13	)%	$	42,153		$	43,887			(4	)%
Gathering fees	$	24,181		$	20,642			17	%	$	47,238		$	41,571			14	%
Depletion, depreciation and amortization	$	51,742		$	38,673			34	%	$	102,282		$	70,427			45	%
General and administrative expenses	$	2,063		$	25,009			(92	)%	$	14,752		$	26,061			(43	)%
Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.33		$	0.34			(3	)%	$	0.32		$	0.35			(9	)%
Facility lease expense	$	0.09		$	0.08			13	%	$	0.09		$	0.08			13	%
Production taxes	$	0.27		$	0.32			(16	)%	$	0.29		$	0.33			(12	)%
Gathering fees	$	0.34		$	0.31			10	%	$	0.33		$	0.32			3	%
Depletion, depreciation and amortization	$	0.73		$	0.58			26	%	$	0.71		$	0.54			31	%
General and administrative expenses	$	0.03		$	0.37			(92	)%	$	0.10		$	0.20			(50	)%

Quarter Ended June 30, 2018 vs. Quarter Ended June 30, 2017

Production, Commodity Derivatives and Revenues:

Production. During the quarter ended June 30, 2018, total production increased on a gas equivalent basis to 70.9 Bcfe compared to 67.1 Bcfe for the same period in 2017. The increase is primarily attributable to an increase in capital investment and development activity, partially offset by a decrease in Mcf/day due to the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017.

Commodity Prices – Natural Gas. During the quarter ended June 30, 2018, realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 20% to $2.28 per Mcf as compared to $2.84 per Mcf for the same period in 2017. The Company has entered into various natural gas price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details. During the quarter ended June 30, 2018, the Company’s average price, 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.

Commodity Prices – Oil. During the quarter ended June 30, 2018, the average price realization for the Company’s oil, including realized gains and losses on commodity derivatives, increased to $58.24 per barrel as compared to $45.51 per barrel for the same period in 2017. The Company has entered into various oil price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details During the quarter ended June 30, 2018, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $64.71 per barrel as compared to $45.51 per barrel for the same period in 2017.

Revenues. During the quarter ended June 30, 2018, revenues decreased to $190.1 million as compared to $212.7 million for the same period in 2017. 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 prices.

Operating Costs and Expenses:

Lease Operating Expense. Lease operating expense (“LOE”) increased slightly to $23.6 million during the quarter ended June 30, 2018 as compared to $23.1 million during the same period in 2017. On a unit of production basis, LOE costs decreased to $0.33 per Mcfe during the quarter ended June 30, 2018 as compared with $0.34 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 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which may increase if certain volume thresholds are exceeded. The lease is classified as an operating lease. For the quarter ended June 30, 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.

Production Taxes. During the quarter ended June 30, 2018, production taxes decreased to $18.9 million compared to $21.8 million during the same period in 2017, or $0.27 per Mcfe compared to $0.32 per Mcfe, respectively. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 9.9% of revenues for the quarter ended June 30, 2018 and 10.2% 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.

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

Depletion, Depreciation and Amortization. During the quarter ended June 30, 2018, DD&A expense increased to $51.7 million compared to $38.7 million for the same period in 2017. The increase is primarily attributable to a higher depletion rate due to a higher depletable base from the increase in capital expenditures as part of the Company’s drilling program and as a result of increased production volumes during the quarter ended June 30, 2018. On a unit of production basis, the DD&A rate increased to $0.73 per Mcfe for the quarter ended June 30, 2018 compared to $0.58 per Mcfe for the same period in 2017.

General and Administrative Expenses. During the quarter ended June 30, 2018, general and administrative expenses decreased to $2.1 million as compared to $25.0 million for the same period in 2017. The decrease is primarily attributable to the $25.4 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 $0.03 per Mcfe for the quarter ended June 30, 2018 compared to $0.37 per Mcfe for the same period in 2017.

Other Income and Expenses:

Interest Expense. During the quarter ended June 30, 2018, interest expense of $37.7 million increased as compared to $29.4 million during the same period in 2017. The increase is primarily attributable to an increase in interest expense on the Term Loan as the amount borrowed increased year over year and increased borrowings on the Revolving Credit Facility during the quarter ended June 30, 2018. See Note 4 for additional details related to the Revolving Credit Facility, Term Loan Agreement, and the Notes.

Deferred Gain on Sale of Liquids Gathering System. During the quarters ended June 30, 2018 and 2017, the Company recognized $2.6 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the quarter ended June 30, 2018, the Company recognized a loss of $47.3 million, as compared to a gain of $20.7 million related to commodity derivatives for the same period in 2017. Of this total, the Company recognized $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. 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 of $53.9 million on commodity derivatives during the quarter ended June 30, 2018, as compared to an unrealized gain of $21.6 million during the same period in 2017. 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 for additional details.

Reorganization Items:

Reorganization Items, Net. Reorganization items, net was $426.8 million 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.

Income from Continuing Operations:

Pretax Income. During the quarter ended June 30, 2018, the Company recognized loss before income taxes of $20.5 million 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.

Income Taxes. The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2018. 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, the Company recognized net loss of $20.6 million, or $0.10 per diluted share, as compared to net income of $499.0 million, or $2.76 per diluted share, 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.

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

Production, Commodity Derivatives and Revenues:

Production. During the six months ended June 30, 2018, total production increased by 9% on a gas equivalent basis to 143.2 Bcfe compared to 131.1 Bcfe for the same period in 2017, primarily attributable to an increase in capital investment and development activity and partially offset by the sale of the non-core assets in Pennsylvania during the fourth quarter of 2017.

Commodity Prices – Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 17% to $2.48 per Mcf during the six months ended June 30, 2018 as compared to $2.99 per Mcf for the same period in 2017. During the six months ended June 30, 2018, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details. During the six months ended June 30, 2018, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.39 per Mcf as compared to $3.00 per Mcf for the same period in 2017.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased to $59.31 per barrel during the six months ended June 30, 2018 as compared to $46.39 per barrel for the same period in 2017. During the six months ended June 30, 2018, the Company entered into additional oil price commodity derivative contracts with contract periods extending through the first quarter of 2020. See Note 7 for additional details. During the six months ended June 30, 2018, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was $62.79 per barrel as compared to $46.39 per barrel for the same period in 2017.

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

Operating Costs and Expenses:

Lease Operating Expense. LOE decreased to $45.4 million during the six months ended June 30, 2018 compared to $46.2 million during the same period in 2017, primarily related to field efficiencies in Wyoming and the sale of non-core assets in Pennsylvania during the fourth quarter of 2017. On a unit of production basis, LOE costs decreased to $0.32 per Mcfe during the six months ended June 30, 2018 compared to $0.35 per Mcfe during the same period in 2017.

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

Production Taxes. During the six months ended June 30, 2018, production taxes were $42.2 million compared to $43.9 million during the same period in 2017, or $0.29 per Mcfe compared to $0.33 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% of revenues for the six months ended June 30, 2018 and 10.1% of revenues for the same period in 2017. The decrease in per unit taxes is primarily attributable to decreased natural gas prices during the six months ended June 30, 2018 as compared to the same period in 2017.

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

Depletion, Depreciation and Amortization. DD&A expenses increased to $102.3 million during the six months ended June 30, 2018 from $70.4 million for the same period in 2017, primarily attributable to a higher depletion rate due to a higher depletable base from the increase in capital expenditures as part of the Company’s drilling program and the recognition of proved undeveloped properties for 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. On a unit of production basis, the DD&A rate increased to $0.71 per Mcfe for the six months ended June 30, 2018 compared to $0.54 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 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 for the six months ended June 30, 2017.

Other Income and Expenses:

Interest Expense. Interest expense decreased to $73.6 million during the six months ended June 30, 2018 compared to $114.9 million during the same period in 2017. The decrease in interest expense is primarily attributable to recurring interest expense on 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 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.

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 during December 2012.

Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the six months ended June 30, 2018, the Company recognized a loss of $53.8 million related to commodity derivatives as compared to $7.5 million related to commodity derivatives during the same period in 2017. 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 million related to a realized loss on commodity derivatives during the same period in 2017. 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 on commodity derivatives also includes 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. 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 for additional details.

Reorganization Items:

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.

Income from Continuing Operations:

Pretax Income. The Company recognized income before income taxes of $27.4 million for the six months ended June 30, 2018 compared to $409.3 million for the same period in 2017. The decrease in earnings is primarily attributable to the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes recognized during the six months ended June 30, 2017 as part of the Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.

Income Taxes. The Company recorded a $0.4 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. The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2018. 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, the Company recognized net income of $26.9 million, or $0.14 per diluted share, as compared to $409.3 million, or $3.12 per diluted share, for the same period in 2017. The decrease in earnings is primarily attributable to the gain on the debt for equity exchange related to the 2018 Notes and 2024 Notes recognized during the six months ended June 30, 2017 as part of the Company’s emergence from chapter 11 proceedings. See Note 10 for additional details.

LIQUIDITY AND CAPITAL RESOURCES

During the six months ended June 30, 2018, we funded our operations primarily through cash flows from operating activities and borrowings under the Revolving Credit Facility (defined below). At June 30, 2018, the Company reported a cash position of $5.7 million. At June 30, 2018, the Company had $58.0 million in outstanding borrowings and $367.0 million of available borrowing capacity under the Revolving Credit Facility.

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

Capital Expenditures. For the six month period ended June 30, 2018, total capital expenditures were $251.0 million. During this period, the Company participated in 76 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 net) vertical wells and 15 gross (11.0 net) horizontal wells. No wells are scheduled to be drilled in Utah during 2018.

2018 Capital Investment Plan. For 2018, our capital expenditures are expected to be approximately $400.0 million. We expect to fund these 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 to development activities in our Pinedale field in Wyoming.

Ultra Resources, Inc.

Credit Agreement. In April 2017, Ultra Resources, Inc. (“Ultra Resources”), as the borrower, entered into a Credit Agreement (as amended, the “Credit Agreement”) with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent, and with the other lenders party thereto from time to time, providing for a revolving credit facility (the “Revolving Credit Facility”) for an aggregate amount of $400.0 million and an initial borrowing base of $1.2 billion (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Agreement (defined below)). In September 2017, the administrative agent and the other lenders approved an increase in the borrowing base under 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. 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 $425.0.0 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 Company’s consolidated net leverage ratio exceeds 4.00 to 1.00 at the end of any fiscal quarter, the interest rate on such borrowings shall be at a per annum rate that is 0.25% higher than the rate that would otherwise

apply until the Company has provided financial statements indicating that the consolidated net leverage ratio no longer exceeds 4.00 to 1.00. The Revolving Credit Facility loans mature on January 12, 2022.

The Revolving Credit Facility requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio, including the unused portion of the Revolving Credit Facility, 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) after the Company has obtained investment grade rating, an asset coverage ratio of 1.50 to 1.00. At June 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.

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

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

Term Loan. In April 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of 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 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 interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points. The Term Loan Agreement amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Agreement matures on April 12, 2024.

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

incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At June 30, 2018, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

Senior Notes. In April 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “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 payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Notes from the issue date until maturity.

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.

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

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, 2017, Ultra Resources was in compliance with all of its debt covenants under the Notes.

The Indenture contains customary events of default (each, an “Event 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.~~

4.	~~SHARE BASED COMPENSATION:~~

~~Valuation and Expense Information~~

   Three Months    Six Months
   Ended June 30,    Ended June 30,
   2017    2016    2017    2016
Total cost of share-based payment plans
   $ 34,679    $ 1,322    $ 35,890    $ 4,050
Amounts capitalized in oil and gas properties and equipment
   $ 9,266    $ 415    $ 9,626    $ 1,346
Amounts charged against income, before income tax benefit
   $ 25,413    $ 907    $ 26,264    $ 2,704
Amount of related income tax benefit recognized in income before valuation allowance
   $ 10,114    $ 361    $ 10,453    $ 1,076

~~Changes in Stock Options and Stock Options Outstanding~~

As provided in the Plan, all plans or programs calling for stock grants, stock issuances, stock reserves or stock options were cancelled as of the Effective Date and all outstanding awards established prior to the Effective Date were cancelled and extinguished as of the Effective Date. The following table summarizes the changes in stock options for the six months ended June 30, 2017 and the year ended December 31, 2016:

      Weighted
   Number of    Average
   Options    Exercise Price
   (000’s)    (US Dollars)
Balance, December 31, 2015
   271    $ 94.04 to    $ 189.57






Cancelled or Extinguished
   (90 )    $ 96.15 to    $ 144.14






Balance, December 31, 2016
   181    $ 94.04 to    $ 189.57






Cancelled or Extinguished
   (181 )    $ 94.04 to    $ 144.14






Balance, June 30, 2017
   —      $ 0.00 to    $ 0.00

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Performance Share Plans~~:

~~2017 Stock Incentive Plan.~~ On the Effective Date, the Ultra Petroleum Corp. 2017 Stock Incentive Plan was established pursuant to which 7.5% of the equity in the reorganized Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, and other employees of the reorganized Company (“the Reserve”). Also on the Effective Date, 40% of the Reserve (“Initial MIP Grants”) was granted to members of the board of directors, officers, and other employees of the reorganized 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, thatone-third~~ of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% of $6.0 billion based upon the volume weighted average price of the common stock during a consecutive~~30-day~~ ~~period, and that if any Initial MIP Grants do not vest before the fifth anniversary of the Effective Date, such Initial MIP Grants shall automatically expire.~~

~~The balance of the Reserve is available to be granted by the Board from time to time.~~

~~Stock-Based Compensation Cost~~:

~~Modification.~~On the Effective Date, as provided in the Plan, all outstanding awards established prior to the Effective Date were cancelled and extinguished, and participants received no payment or other distribution on account of the outstanding awards. Under FASB ASC Topic 718, Compensation Cost – Stock Compensation (“FASB 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. 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.

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

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

~~Expense.~~~~For the six months ended June 30, 2017, the Company recognized $26.3 million inpre-tax~~ compensation expense, of which $25.2 million related to the Initial MIP Grants. During the six months ended June 30, 2016, the Company recognized $2.2 million related to the 2014 and 2015 LTIP awards of restricted stock units. The Company expects the total expense associated with the portion of the Initial MIP Grant that vests if the $6.0 billion total enterprise value performance requirement is satisfied to be $22.1 million and the portion of the Initial MIP grant that vests if the $6.6 billion total enterprise value performance requirement is satisfied to be $20.1 million, respectively.~~One-third~~ of the Initial MIP Grants were paid in shares of the Company’s stock to members of its board of directors as well as its officers and other employees during the second quarter and totaled $25.8 million (1,207,111 shares), of which a portion was capitalized in oil and gas properties and equipment as noted in the valuation and expense information above.

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

5.	~~INCOME TAXES:~~

~~The Company’s overall effective tax rate onpre-tax~~ ~~income was different than the statutory rate of 35% due primarily to valuation allowances.~~

~~The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2017. Some or all of this valuation allowance may be reversed in future periods against future income.~~

The reorganization of the Company is considered to have resulted in a change of control for U.S. Income Tax purposes under IRC Section 382. However, pursuant to the special rules under IRC Section 382(h), the Company’s U.S. tax attributes, including its Net Operating Loss (NOL), is not expected to be subject to significant limitations due to the change of control.

6.	~~DERIVATIVE FINANCIAL INSTRUMENTS:~~

~~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. As a result of its hedging activities, the Company may realize prices that are less than or greater than the spot prices that it would have received otherwise.

~~The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval.~~

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

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

~~Commodity Derivative Contracts:~~ At June 30, 2017, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price for the contract and pays the variable price to the counterparty. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

~~Natural Gas:~~

Type
   Commodity
Reference Price    Remaining
Contract Period    Volume -
MMBTU/
Day    Average
Price
/MMBTU    Fair Value -
June 30, 2017
               Asset
Fixed price swap
   NYMEX-Henry Hub    July - Oct 2017    575,000    $ 3.17    $ 8,367

~~The following table summarizes thepre-tax~~ ~~realized and unrealized (loss) gain the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the periods ended June 30, 2017 and 2016:~~

   For the Three Months    For the Six Months
   Ended June 30,    Ended June 30,
Commodity Derivatives:
   2017    2016    2017    2016
Realized loss on commodity derivatives-natural gas (1)
   $ (868 )    $ —      $ (868 )    $ —
Unrealized gain on commodity derivatives (1)
   21,585    —      8,367    —








Total gain on commodity derivatives
   $ 20,717    $ —      $ 7,499    $ —

~~(1)~~

~~Included in gain on commodity derivatives in the Consolidated Statements of Operations.~~

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

7.	~~FAIR VALUE MEASUREMENTS:~~

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:


~~Level 1~~:		~~Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.~~

~~Level 2~~:		Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include~~non-exchange~~ ~~traded derivatives such asover-the-counter~~ ~~forwards and swaps.~~

~~Level 3~~:		~~Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.~~

   Level 1    Level 2    Level 3    Total
Assets:

Current derivative asset
   $ —      $ 8,367    $ —      $ 8,367

~~Fair Value of Financial Instruments~~

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

   June 30, 2017    December 31, 2016(1)
   Carrying    Estimated    Carrying    Estimated
   Amount    Fair Value    Amount    Fair Value
Term loan, secured, due April 2024
   $ 800,000    $ 794,000    $ —      $ —
6.875% Notes, unsecured, due April 2022, issued 2017
   700,000    709,301    —      —
7.125% Notes, unsecured, due April 2025, issued 2017
   500,000    501,599    —      —
Credit Facility due January 2022
   77,000    77,000    —      —
7.31% Notes due March 2016, issued 2009
   —      —      62,000    64,266
4.98% Notes due January 2017, issued 2010
   —      —      116,000    123,967
5.92% Notes due March 2018, issued 2008
   —      —      200,000    224,025
5.75% Notes due December 2018, issued 2013
   —      —      450,000    465,630
7.77% Notes due March 2019, issued 2009
   —      —      173,000    204,854
5.50% Notes due January 2020, issued 2010
   —      —      207,000    233,932
4.51% Notes due October 2020, issued 2010
   —      —      315,000    337,528
5.60% Notes due January 2022, issued 2010
   —      —      87,000    99,983
4.66% Notes due October 2022, issued 2010
   —      —      35,000    38,225
6.125% Notes due October 2024, issued 2014
   —      —      850,000    893,325
5.85% Notes due January 2025, issued 2010
   —      —      90,000    106,299
4.91% Notes due October 2025, issued 2010
   —      —      175,000    193,665
Credit Facility due October 2016
   —      —      999,000    999,000








   $ 2,077,000    $ 2,081,900    $ 3,759,000    $ 3,984,699

⁽¹⁾	~~At December 31, 2016, the debt included in the table above is a component of liabilities subject to compromise in our Consolidated Balance Sheets. See Note 1.~~

8.	~~COMMITMENTS AND CONTINGENCIES:~~

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

~~Pending Claims – Ultra Resources Indebtedness~~

Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest dates, unpaid postpetition interest (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to the 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). Following our emergence from bankruptcy, we have continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the debt agreements. An oral argument related to this dispute was conducted in the Bankruptcy Court on May 16, 2017, and we and the claim holders have each filed various briefs and other pleadings before and after the May 16 hearing. In connection with 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 Effective Date, pending resolution of make-whole and post-petition interest claims. On April 14, 2017, we funded the account. At this time, we are not able to determine the likelihood or range of amounts attributable to claims for postpetition interest, make-whole amounts, or other fees and obligations under the debt agreements.

~~ULTRA PETROLEUM CORP.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)~~

~~(Unaudited)~~

~~Rockies Express Pipeline~~

During our chapter 11 proceedings, Rockies Express Pipeline LLC (“REX”) filed a claim against us for $303.3 million related to our prepetition transportation agreement for service on the Rockies Express Pipeline. As previously disclosed, on January 12, 2017 we entered into a settlement agreement with REX pursuant to which we made a cash payment to REX of $150.0 million on July 12, 2017 (see Note 9).

~~Royalties~~

On April 19, 2016, we received a preliminary determination notice from the Office of Natural Resources Revenue (“ONRR”) asserting that our 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. We dispute the preliminary determination and raised, with ONRR, several matters we believed may not have been considered in the preliminary determination notice. ONRR filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims attributable to these royalty calculations. This claim and the preliminary determination notice could ultimately result in us being ordered to pay additional royalty to ONRR for prior, current and future periods. We are not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

~~Oil Sales Contract~~

On April 29, 2016, we received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) we had breached, by anticipatory repudiation, a contract for 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 its breach of the contract 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. Both parties are currently conducting discovery. 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 anticipate SPMT’s claims will be resolved in connection with our chapter 11 proceedings.

~~Other Claims~~

The Company is party to lawsuits related to disputes with respect to overriding royalty and other interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, or, if such claims are determined, whether any amounts related to these matters would be material. We are defending these cases vigorously, and we expect these claims to be resolved in our chapter 11 proceedings. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine 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.

9.	~~SUBSEQUENT EVENTS:~~

The Company has evaluated the period subsequent to June 30, 2017 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading, except as set forth below.

~~As previously disclosed in a Current Report on Form8-K~~ filed with the SEC on January 17, 2017, we reached an agreement to settle REX’s $303.3 million breach of contract claim. The settlement included a payment of $150.0 million to REX after the Company emerged from chapter 11. On July 12, 2017, we paid the $150.0 million settlement as required by the settlement agreement. The payment was funded through draws on the Revolving Credit Facility.

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

~~Overview~~

Ultra Petroleum Corp. (the “Company”) is an independent exploration and production company focused on developing its long-life natural gas reserves in the Green River Basin of Wyoming - the Pinedale and Jonah fields, its oil reserves in the Uinta Basin in Utah and its natural gas reserves in the Appalachian Basin of Pennsylvania. The Company operates in one industry segment, natural gas and oil exploration and development, within one geographical segment, the United States.

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

The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and this volatility could be detrimental to the Company’s financial performance. As a result, and from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas and oil. (See Note 6).

During the quarter ended June 30, 2017, the average price realization for the Company’s natural gas was $2.84 per Mcf, including realized gains and losses on commodity derivatives compared with $1.76 per Mcf during the quarter ended June 30, 2016. The Company’s average price realization for natural gas was $2.85 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $1.76 per Mcf during the quarter ended June 30, 2016.

~~During the quarter ended June 30, 2017, the average price realization for the Company’s oil was $45.51 per barrel compared to $40.54 per barrel for the quarter ended June 30, 2016.~~

~~Chapter 11 Proceedings~~

~~Voluntary Reorganization Under Chapter 11~~

~~Plan Support Agreement, Rights Offering, Backstop Commitment Agreement and Exit Financing Commitment Letter~~

~~As previously disclosed:~~

~~On the Effective Date, we consummated the Rights Offering and the Debt Financings and, as noted above, emerged from bankruptcy.~~

~~Fresh Start Accounting~~

~~Liabilities Subject to Compromise~~

~~The following table reconciles the settlement of liabilities subject to compromise included in our Consolidated Balance Sheets from December 31, 2016 through the six months ended June 30, 2017:~~

~~Bankruptcy Claims Resolution Process~~

~~Costs of Reorganization~~

~~The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the six months ended June 30, 2017 and 2016:~~

⁽¹⁾	~~The six months ended June 30, 2017 includes $23.0 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings.~~

⁽²⁾	~~Gains (losses) represent the net gain on the debt to equity exchange related to the 2018 and 2024 Notes.~~

⁽³⁾	~~Cash interest income earned for the period after the Petition Date on excess cash over normal invested capital.~~

~~Critical Accounting Policies~~

~~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.

   Level 1    Level 2    Level 3    Total
Assets:

Current derivative asset
   $ —      $ 8,367    $ —      $ 8,367

~~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 recognized for the six months ended June 30, 2017 and 2016 was $26.3 million and $2.7 million, respectively. See Note 4 for additional information.

~~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”) ReleaseNo. 33-8995,~~ ~~Modernization of Oil and Gas Reporting Requirements (“SEC ReleaseNo. 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 onnon-producing~~ ~~properties, costs of drilling both productive andnon-productive~~ wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with 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-XRule 4-10.~~ ~~The ceiling test is performed quarterly, on acountry-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 ReleaseNo. 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.

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, 2017 or 2016.

~~Revenue Recognition.~~ The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes.

~~Make-up~~ provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and natural gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalance. The Company’s imbalance obligations as of June 30, 2017 and December 31, 2016 were immaterial.

~~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).

The Company has recorded a valuation allowance against all of its deferred tax assets as of June 30, 2017. Some or all of this valuation allowance may be reversed in future periods against future income.

~~Deferred Financing Costs.~~ ~~The Company follows ASUNo. 2015-3,~~~~Interest – Imputation of Interest (Subtopic835-30):~~ ~~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 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.

~~Deposits and Retainers.~~ ~~Deposits and retainers primarily consists of payments related to surety bonds as of December 31, 2016.~~

~~Conversion of Barrels of Oil 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.

~~Recent accounting pronouncements.~~

~~In November 2016, the FASB issued ASU2016-18,~~ ~~Statement of Cash Flows (Topic 230): Restricted Cash~~ ~~(“ASUNo. 2016-18”).~~ The guidance requires that an explanation is included in the cash flow statement of the change in the total of (1) cash, (2) cash equivalents, and (3) restricted cash or restricted cash equivalents. ASU~~No. 2016-18~~ also clarifies that transfers between cash, cash equivalents and restricted cash or restricted cash equivalents should not be reported as cash flow activities and requires the nature of the restrictions on cash, cash equivalents, and restricted cash or restricted cash equivalents to be disclosed. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 with earlier application permitted. The Company is still evaluating the impact of ASU~~No. 2016-18~~ ~~on its consolidated financial statements.~~

~~In February 2016, the FASB issued ASU2016-02,~~~~Leases~~ ~~(“ASUNo. 2016-02”).~~ 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 also require 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. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 with earlier application permitted. The Company is still evaluating the impact of ASU~~No. 2016-02~~ ~~on its consolidated financial statements.~~

~~In May 2014, the FASB issued ASU2014-09,~~~~Revenue from Contracts with Customers (Topic 606)~~~~and in 2016, the FASB issued ASU2016-08,~~~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)~~~~, and ASU2016-10,~~~~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 Subtopic932-605,~~ ~~ExtractiveActivities-Oil~~ ~~andGas-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.

~~We are currently evaluating the provisions of ASU2014-09~~ and assessing the impact, if any, it may have on our financial position and results of operations. As part of our assessment work to date, we have completed training of the new ASU’s revenue recognition model, dedicated resources to its implementation, and initiated contract review and documentation; including analyzing the standard’s impact on our contract portfolio, comparing historical accounting policies and practices to the requirements of the new standard, and identifying differences from applying the requirements of the new standards to our contracts. We are evaluating the expanded disclosure requirements under the new standard and are also reviewing our processes, systems, and internal controls over financial reporting to ensure the appropriate information will be available for these disclosures. While we are continuing to assess all potential impacts of the standard, we currently believe the most significant impacts relate to principal versus agent considerations and the use of the entitlements method for oil and natural gas sales, both of which are continuing to be evaluated by the Company.

~~RESULTS OF OPERATIONS:~~

   For the Three Months    For the Six Months
   Ended June 30,    % Ended June 30,    %
   2017 2016    Variance 2017 2016    Variance
   (Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:

Production:

Natural gas (Mcf)
   63,067 66,436    -5 % 123,056 135,041    -9 %
Crude oil and condensate (Bbls)
   675 735    -8 % 1,338 1,525    -12 %





Total production (Mcfe)
   67,118 70,846    -5 % 131,084 144,191    -9 %





Commodity Prices:

Natural gas ($/Mcf, excluding hedges)
   $ 2.85 $ 1.76    62 % $ 3.00 $ 1.89    59 %
Natural gas ($/Mcf, including realized hedges)
   $ 2.84 $ 1.76    61 % $ 2.99 $ 1.89    58 %
Oil and condensate ($/Bbl)
   $ 45.51 $ 40.54    12 % $ 46.39 $ 33.50    38 %
Revenues:

Natural gas sales
   $ 179,997 $ 116,780    54 % $ 368,848 $ 254,882    45 %
Oil sales
   30,732 29,811    3 % 62,081 51,095    22 %
Other revenues
   1,928 —      n/a 2,687 —      n/a





Total operating revenues
   $ 212,657 $ 146,591    45 % $ 433,616 $ 305,977    42 %





Derivatives:

Realized (loss) gain on commodity derivatives-natural gas
   $ (868 ) $ —      n/a $ (868 ) $ —      n/a
Unrealized gain (loss) on commodity derivatives
   21,585 —      n/a 8,367 —      n/a





Total gain (loss) on commodity derivatives
   $ 20,717 $ —      n/a $ 7,499 $ —      n/a





Operating Costs and Expenses:

Lease operating expenses
   $ 23,089 $ 21,836    6 % $ 46,225 $ 47,230    -2 %
Liquids gathering system operating lease expense
   $ 5,226 $ 5,171    1 % $ 10,452 $ 10,343    1 %
Production taxes
   $ 21,754 $ 13,474    61 % $ 43,887 $ 28,706    53 %
Gathering fees
   $ 20,642 $ 21,504    -4 % $ 41,571 $ 43,954    -5 %
Transportation charges
   $ —   $ 146    n/a $ —   $ 23,701    n/a
Depletion, depreciation and amortization
   $ 38,673 $ 31,234    24 % $ 70,427 $ 62,083    13 %
General and administrative expenses
   $ 25,009 $ 1,381    1711 % $ 26,061 $ 5,600    365 %
Per Unit Costs and Expenses ($/Mcfe):

Lease operating expenses
   $ 0.34 $ 0.31    10 % $ 0.35 $ 0.33    6 %
Liquids gathering system operating lease expense
   $ 0.08 $ 0.07    14 % $ 0.08 $ 0.07    14 %
Production taxes
   $ 0.32 $ 0.19    68 % $ 0.33 $ 0.20    65 %
Gathering fees
   $ 0.31 $ 0.30    3 % $ 0.32 $ 0.30    7 %
Transportation charges
   $ —   $ —      n/a $ —   $ 0.16    n/a
Depletion, depreciation and amortization
   $ 0.58 $ 0.44    32 % $ 0.54 $ 0.43    26 %
General and administrative expenses
   $ 0.37 $ 0.02    1750 % $ 0.20 $ 0.04    400 %

~~Quarter Ended June 30, 2017 vs. Quarter Ended June 30, 2016~~

~~Production, Commodity Derivatives and Revenues:~~

~~Production.~~During the quarter ended June 30, 2017, total production decreased on a gas equivalent basis to 67.1 Bcfe compared to 70.8 Bcfe for the same quarter in 2016. The decrease is primarily attributable to decreased capital investment during the year ended December 31, 2016.

~~Commodity Prices – Natural Gas.~~ Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 61% to $2.84 per Mcf in the second quarter of 2017 as compared to $1.76 per Mcf for the same quarter of 2016. The Company’s commodity derivative contracts for natural gas production begin in April 2017 and end in October 2017. During the three months ended June 30, 2017, the Company’s average price for natural gas was $2.85 per Mcf as compared to $1.76 per Mcf for the same period in 2016.

~~Commodity Prices – Oil.~~ During the quarter ended June 30, 2017, the average price realization for the Company’s oil was $45.51 per barrel compared to $40.54 per barrel for the same period in 2016. The Company does not currently have any open derivative contracts for oil production.

~~Revenues.~~ The increase in average natural gas prices, partially offset by the decrease in total production, resulted in revenues increasing to $212.7 million for the quarter ended June 30, 2017 as compared to $146.6 million for the same period in 2016.

~~Operating Costs and Expenses:~~

~~Lease Operating Expense.~~ Lease operating expense (“LOE”) increased to $23.1 million during the second quarter of 2017 compared to $21.8 million during the same period in 2016 largely related to the increase in well count which caused an increase in pumper/roustabout expense and administrative overhead. On a unit of production basis, LOE costs increased to $0.34 per Mcfe during the second quarter of 2017 compared with $0.31 per Mcfe during the second quarter of 2016.

~~Liquids Gathering System Operating Lease Expense.~~ During December 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual 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. The lease is classified as an operating lease. For the three months ended June 30, 2017, the Company recognized operating lease expense associated with the Lease Agreement of $5.2 million, or $0.08 per Mcfe, as compared to $5.2 million, or $0.07 per Mcfe for the same period in 2016.

~~Production Taxes.~~ During the three months ended June 30, 2017, production taxes increased to $21.8 million compared to $13.5 million during the same period in 2016, or $0.32 per Mcfe compared to $0.19 per Mcfe, respectively. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 10.2% of revenues for the quarter ended June 30, 2017 and 9.2% of revenues for the same period in 2016.

~~Gathering Fees.~~ Gathering fees decreased to $20.6 million for the three months ended June 30, 2017 compared to $21.5 million during the same period in 2016 largely related to decreased production. On a per unit basis, gathering fees were $0.31 per Mcfe for the three months ended June 30, 2017 as compared to $0.30 per Mcfe during the same period in 2016.

~~Transportation Charges.~~As a result of termination of the Rockies Express Pipeline (“Rockies Express”) contract during the first quarter of 2016, there were no material transportation charges for the quarter ended June 30, 2017 or 2016.

~~Depletion, Depreciation and Amortization.~~ DD&A expense of $38.7 million during the three months ended June 30, 2017 increased compared to $31.2 million for the same period in 2016, primarily attributable to the recognition of proved undeveloped properties (PUDs) during the three months ended June 30, 2017 as a result of emergence from chapter 11. On a unit of production basis, the DD&A rate increased to $0.58 per Mcfe for the quarter ended June 30, 2017 compared to $0.44 per Mcfe for the quarter ended June 30, 2016.

~~General and Administrative Expenses.~~ General and administrative expenses increased to $25.0 million for the quarter ended June 30, 2017 compared to $1.4 million for the same period in 2016 primarily attributable to the $25.4 million of~~non-cash~~ stock incentive compensation expense that was incurred as part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date. On a per unit basis, general and administrative expenses increased to $0.37 per Mcfe for the quarter ended June 30, 2017 compared to $0.02 per Mcfe for the quarter ended June 30, 2016.

~~Other Income and Expenses:~~

~~Interest Expense.~~ During the quarter ended June 30, 2017, interest expense of $29.4 million was recognized which represents interest incurred on the credit facility, term loan, and senior notes entered into during the three months ended June 30, 2017 compared to $16.7 million related to the interest incurred through the petition date of April 29, 2016 which was recognized in the three months ended June 30, 2016.

~~Restructuring Expenses.~~ ~~During the quarter ended June 30, 2016, the Company incurred $1.6 million in costs and fees in connection with its efforts to restructure its debt prior to filing the chapter 11 petitions.~~

~~Deferred Gain on Sale of Liquids Gathering System.~~ During the quarters ended June 30, 2017 and 2016, the Company recognized $2.6 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

~~Commodity Derivatives:~~

~~Gain/(Loss) on Commodity Derivatives.~~During thequarter ended June 30, 2017, the Company recognized a gain of $20.7 million related to commodity derivatives. There were no open derivative contracts for the same period in 2016. Of this total, the Company recognized $0.9 million related to realized loss on commodity derivatives. 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 on commodity

~~derivatives also includes a $21.6 million unrealized gain on commodity derivatives at June 30, 2017. The unrealized gain or loss on commodity derivatives represents thenon-cash~~ ~~charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract. See Note 6.~~

~~Reorganization Items:~~

~~Reorganization Items, Net.~~Reorganization items, net increased to $426.8 million for the quarter ended June 30, 2017 compared to ($22.2) million during the same period in 2016. The increase is due to the emergence from chapter 11 during the quarter ended June 30, 2017 and is primarily comprised of expenses of $4.3 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 cases and a gain of $431.1 million, which primarily represents the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes. No cash tax is expected to be recognized as the result of this gain.

~~Income from Continuing Operations:~~

~~Pretax Income.~~ The Company recognized income before income taxes of $499.0 million for the quarter ended June 30, 2017 compared with income before income taxes of $13.8 million for the same period in 2016. The increase in earnings is attributable to increased revenues due to increases in the average oil and natural gas prices and due to the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes and partially offset by an increase in LOE, interest expense, DD&A, production taxes, and general and administrative expense during the three months ended June 30, 2017.

~~Income Taxes.~~~~The Company has recorded a valuation allowance against all deferred tax assets as of June 30, 2017. Some or all of this valuation allowance may be reversed in future periods against future income.~~

~~Net Income.~~For the three months ended June 30, 2017, the Company recognized net income of $499.0 million, or $2.76 per diluted share, as compared with a net income of $14.0 million or $0.17 per diluted share, for the same period in 2016. The increase in earnings is attributable to increased revenues due to increases in the average oil and natural gas prices and due to the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes and partially offset by an increase in LOE, interest expense, DD&A, production taxes, and general and administrative expense during the three months ended June 30, 2017.

~~Six Months Ended June 30, 2017 vs. Six Months Ended June 30, 2016~~

~~Production, Commodity Derivatives and Revenues:~~

~~Production.~~During the six months ended June 30, 2017, total production decreased by 9% on a gas equivalent basis to 131.1 Bcfe compared to 144.2 Bcfe for the same period in 2016 primarily as a result of decreased capital investment during 2016.

~~Commodity Prices – Natural Gas.~~ Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 58% to $2.99 per Mcf during the six months ended June 30, 2017 as compared to $1.89 per Mcf for the same period in 2016. The Company’s commodity derivative contracts for natural gas production began in April 2017 and end in October 2017. During the six months ended June 30, 2017, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $3.00 per Mcf as compared to $1.89 per MCF for the same period in 2016.

~~Commodity Prices – Oil.~~During the six months ended June 30, 2017, the average price realization for the Company’s oil was $46.39 per barrel compared with $33.50 per barrel during the same period in 2016. The Company does not currently have any open derivative contracts for oil production.

~~Revenues.~~ The increase in average oil and natural gas prices, partially offset by the decrease in total production, resulted in revenues increasing to $433.6 million for the six months ended June 30, 2017 as compared to $306.0 million for the same period in 2016.

~~Operating Costs and Expenses:~~

~~Lease Operating Expense.~~ LOE decreased to $46.2 million during the six months ended June 30, 2017 compared to $47.2 million during the same period in 2016 largely related to the decrease in production. On a unit of production basis, LOE costs increased to $0.35 per Mcfe during the six months ended June 30, 2017 compared to $0.33 per Mcfe during the same period in 2016.

~~Liquids Gathering System Operating Lease Expense.~~ During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale Anticline in Wyoming 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, 2017, the Company recognized operating lease expense associated with the Lease Agreement of $10.5 million, or $0.08 per Mcfe, as compared to $10.3 million, or $0.07 per Mcfe, for the same period in 2016.

~~Production Taxes.~~ During the six months ended June 30, 2017, production taxes were $43.9 million compared to $28.7 million during the same period in 2016, or $0.33 per Mcfe compared to $0.20 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% of revenues for the six months ended June 30, 2017 and 9.4% of revenues for the same period in 2016. The increase in per unit taxes is primarily attributable to increased oil and natural gas prices during the six months ended June 30, 2017 as compared to the same period in 2016.

~~Gathering Fees.~~ Gathering fees decreased slightly to $41.6 million for the six months ended June 30, 2017 compared to $44.0 million during the same period in 2016. On a per unit basis, gathering fees increased at $0.32 per Mcfe for the six months ended June 30, 2017 compared to $0.30 per Mcfe for the same period in 2016.

~~Transportation Charges.~~As a result of the termination of the Rockies Express Pipeline (“Rockies Express”) contract during the first quarter of 2016, there were no material transportation charges for the six months ended June 30, 2017. Transportation charges were $23.7 million for the same period in 2016. See Note 8 for further discussion of the Rockies Express contract.

~~Depletion, Depreciation and Amortization.~~ DD&A expenses increased to $70.4 million during the six months ended June 30, 2017 from $62.1 million for the same period in 2016, primarily attributable to the recognition of proved undeveloped properties (PUDs) during the six months ended June 30, 2017 as a result of the emergence from chapter 11. On a unit of production basis, the DD&A rate increased to $0.54 per Mcfe for the six months ended June 30, 2017 compared to $0.43 per Mcfe for the six months ended June 30, 2016.

~~General and Administrative Expenses.~~ General and administrative expenses increased to $26.1 million for the six months ended June 30, 2017 compared to $5.6 million for the same period in 2016. The increase in general and administrative expenses is primarily attributable to the $26.3 million of~~non-cash~~ stock incentive compensation expense that was incurred as part of the Management Incentive Plan, in which tranche one became fully vested on the Effective Date. On a per unit basis, general and administrative expenses increased to $0.20 per Mcfe for the six months ended June 30, 2017 compared to $0.04 per Mcfe for the six months ended June 30, 2016.

~~Other Income and Expenses:~~

~~Interest Expense.~~ Interest expense increased to $114.9 million during the six months ended June 30, 2017 compared to $66.6 million during the same period in 2016. The increase in interest expense represents accrued postpetition interest for the period beginning April 29, 2016 through April 12, 2017 and the interest expense incurred on the credit facility, term loan, and senior notes entered into during the six months ended June 30, 2017. (See Note 3).

~~Restructuring Expenses.~~~~During the six months ended June 30, 2016, the Company incurred $7.1 million in costs and fees in connection with its efforts to restructure its debt prior to filing the chapter 11 petitions.~~

~~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 regards to the violation of the Capacity Agreement. The Company reached the settlement on April 10, 2017, the expense was accrued as of March 31, 2017, and was paid in full in May 2017. There were no material contract settlement expenses for the same period in 2016. See Note 8 for further discussion of the settlement.

~~Deferred Gain on Sale of Liquids Gathering System.~~ During the six months ended June 30, 2017 and 2016, the Company recognized $5.3 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

~~Commodity Derivatives:~~

~~Gain (Loss) on Commodity Derivatives.~~During thesix months ended June 30, 2017, the Company recognized a gain of $7.5 million related to commodity derivatives. There were no open derivative contracts for the same period in 2016. Of this total, the Company recognized $0.9 million related to realized loss on commodity derivatives. 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 on commodity derivatives also includes a $8.4 million unrealized gain on commodity derivatives at June 30, 2017. 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 6.~~

~~Reorganization Items:~~

~~Reorganization Items, Net.~~Reorganization items, net increased to $369.3 million for the six months ended June 30, 2017 compared to ($22.2) million for the same period 2016. The increase is due to the emergence from chapter 11 during the six months ended June 30, 2017 and is primarily comprised of expenses of $61.8 million in professional fees, settlements, and interest income associated with the Company’s chapter 11 cases and a gain of $431.1 million, which represents the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes. No cash tax is expected to be recognized as the result of this gain.

~~Income from Continuing Operations:~~

~~Pretax Income.~~ The Company recognized income before income taxes of $409.3 million for the six months ended June 30, 2017 compared with a loss before income taxes of $8.2 million for the same period in 2016. The increase in earnings is attributable to increased revenues due to increases in the average oil and natural gas prices and due to the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes during the six months ended June 30, 2017 and partially offset by an increase in interest expense, DD&A, production taxes, and general and administrative expense during the six months ended June 30, 2017.

~~Net Income.~~For the six months ended June 30, 2017, the Company recognized net income of $409.3 million, or $3.12 per diluted share, as compared with net loss of $7.8 million, or -$0.10 per diluted share, for the same period in 2016. The increase in earnings is largely due to increased revenues due to increases in the average oil and natural gas prices and due to the gain on the debt for equity exchange related to the 2018 and 2024 Senior Notes during the six months ended June 30, 2017 and partially offset by an increase in interest expense, DD&A, production taxes, and general and administrative expenses during the six months ended June 30, 2017.

~~LIQUIDITY AND CAPITAL RESOURCES~~

During the six months ended June 30, 2017, we funded our operations primarily through cash flows from operating activities and borrowings under the RBL Credit Agreement (defined below). The Company plans to fund our operations for the remainder of its fiscal year 2017 primarily through cash on hand and cash flows from operating activities. However, future cash flows are subject to a number of risks, and are highly dependent on the prices we receive for oil and natural gas.

At June 30, 2017, the Company reported a cash position of $6.0 million. Working capital was $176.1 million compared to working capital of $259.4 million at June 30, 2016. At June 30, 2017, the Company had $77.0 million in outstanding borrowings and $323.0 million of available borrowing capacity under the RBL Credit Agreement (defined below).

needs are highly sensitive to changes in each of these and other factors. The Company’s positive cash provided by operating activities, along with availability under the RBL Credit Agreement (defined below), are projected to be sufficient to fund the Company’s budgeted capital investment program for 2017.

~~Capital Expenditures.~~ For the six month period ended June 30, 2017, total capital expenditures were $225.1 million. During this period, the Company participated in 88 gross (73 net) wells in Wyoming that were drilled to total depth and cased. No wells are scheduled to be drilled in Utah or Pennsylvania during 2017.

~~2017 Capital Investment Plan.~~ For 2017, our capital expenditures are expected to be approximately $540.0 million. We expect to fund these capital expenditures through cash flows from operations and cash on hand. We expect to allocate nearly all of the budget to development activities in our Pinedale field.

~~Common stock – NASDAQ Listing.~~ In connection with its emergence from chapter 11, the Company issued 194,991,656 shares of its new common stock. All of the Company’s existing common stock that had been trading under the ticker symbol “UPLMQ” was cancelled and the existing stockholders received new common stock as set forth in the Plan. All of the allowed claims attributable to the prepetition high yield bonds issued by the Company were converted into new common stock as set forth in the Plan. The shares related to the $580.0 million equity rights offering were issued and the fee payable to the commitment parties under the Backstop Commitment Agreement was paid in new common stock as set forth in the Plan. The newly-issued common stock began trading on The NASDAQ Global Select Market on April 13, 2017 under the ticker symbol “UPL”.

~~Ultra Resources, Inc.~~

~~Credit Agreement.~~ On April 12, 2017, Ultra Resources, Inc. (“Ultra Resources”), as a borrower, entered into a Credit Agreement with the Company and UP Energy Corporation, as parent guarantors, Bank of Montreal, as administrative agent, and the other lenders party thereto (as amended, the “RBL Credit Agreement”), providing for a revolving credit facility (the “Revolving Credit Facility,” and together with the Term Loan Facility (defined below), the “Credit Facilities”) for an aggregate amount of $400.0 million. At June 30, 2017, Ultra Resources had $77.0 million in outstanding borrowings under the RBL Credit Agreement.

The initial borrowing base (which limits the aggregate amount of first lien debt under the Revolving Credit Facility and the Term Loan Facility) is $1.2 billion and there are no scheduled borrowing base redeterminations until October 1, 2017.

The RBL Credit Agreement requires Ultra Resources to maintain (i) an interest coverage ratio of 2.50 to 1.00; (ii) a current ratio of 1.00 to 1.00; (iii) a consolidated net leverage ratio of (A) 4.25 to 1.00 as of the last day of any fiscal quarter ending on or before December 31, 2017 and (B) 4.00 to 1.00, as of the last day of any fiscal quarter thereafter; and (iv) after the Company has obtained investment grade rating an asset coverage ratio of 1.50 to 1.00. At June 30, 2017, Ultra Resources was in compliance with all of its debt covenants under the RBL Credit Agreement.

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

The RBL Credit 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 RBL Credit Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Credit Agreement and any outstanding unfunded commitments may be terminated.

~~Term Loan.~~On April 12, 2017, Ultra Resources, as borrower, entered into a Senior Secured Term Loan Agreement with the Company and UP Energy Corporation, as parent guarantors, Barclays Bank PLC, as administrative agent, and the other lenders party thereto (the “Term Loan Agreement”), providing for senior secured first lien term loans (the “Term Loan Facility”) for an aggregate amount of $800.0 million consisting of an initial term loan in the amount of $600.0 million and an incremental term loan in the amount of $200.0 million to be drawn immediately after the funding of the initial term loan. As part of the Term Loan agreement, Ultra Resources agreed to pay an original issue discount equal to one percent of the principal amount. The original issue discount of $8.0 million is included in the deferred financing costs noted above and is a direct deduction from the carrying amount of long-term debt. The Term Loan Facility has capacity to increase the commitments subject to certain conditions. At June 30, 2017, Ultra Resources had $800.00 million in outstanding borrowings under the Term Loan Facility.

The Term Loan Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus 300 basis points or (b) the base rate plus 200 basis points. The Term Loan Facility amortizes in equal quarterly installments in aggregate annual amounts equal to 0.25% of the aggregate principal amount beginning on June 30, 2019. The Term Loan Facility matures seven years after the Effective Date.

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

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, 2017, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Facility.

~~Senior Notes~~. On April 12, 2017, the Company issued $700.0 million of its 6.875% senior notes due 2022 (the “2022 Notes”) and $500.0 million of its 7.125% senior notes due 2025 (the “2025 Notes,” and together with the 2022 Notes, the “Notes”) and entered into an Indenture, dated April 12, 2017 (the “Indenture”), among Ultra Resources, as issuer, 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 payment dates for the 2022 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. The 2025 Notes will mature on April 15, 2025. The interest payment dates for the 2025 Notes are April 15 and October 15 of each year, commencing on October 15, 2017. Interest will be paid on the Notes from the issue date until maturity.

Prior to April 15, 2019, 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 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 2022 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.

If Ultra Resources experiences certain change of control triggering events 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 distributiondistributions 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, ~~2017,~~2018, Ultra Resources was in compliance with all of its debt covenants under the Notes.

The Indenture contains customary events of ~~default (each, an “Event of Default”).~~default. Unless otherwise noted in the Indenture, upon a continuing ~~Event~~event of ~~Default,~~default, the trustee under the Indenture ~~(“the Trustee”~~(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~~event of ~~Default~~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.

Cash flows provided by (used in):

Operating Activities. During the six months ended June 30, ~~2017,~~2018, net cash provided by operating activities was ~~$113.0~~$205.8 million compared to ~~net cash provided by operating activities of $31.7~~$136.5 million for the same period in ~~2016.~~2017. The increase in net cash provided by operating activities is largely attributable to ~~increased revenues as a result~~the timing of ~~increased average~~nonrecurring expenses related to the Company’s reorganization under chapter 11 proceedings and partially offset by decreased oil and natural gas ~~price realizations during the six months ended June 30, 2017, as compared to the same period in 2016, and net changes in working capital.~~prices.

Investing Activities. During the six months ended June 30, ~~2017,~~2018, net cash used in investing activities was ~~$220.3~~$272.0 million as compared to ~~$135.1~~$220.3 million for the same period in ~~2016.~~2017. The increase in net cash used in investing activities is largely related to increased capital investments associated with the Company’s drilling ~~activities.~~

activities during the six months ended June 30, 2017.

Financing Activities. During the six months ended June 30, ~~2017, net cash used in financing activities was $288.1 million compared to~~2018, net cash provided by financing activities ~~of $368.7~~was $55.3 million as compared to $120.3 million for the same period in ~~2016.~~2017. The change in net cash ~~used~~

inprovided by financing activities is primarily due to the movement of $400.0 million from cash to restricted cash for the Reserve Fund, which is pending the resolution of make-whole and post-petition interest claims and the outflow of deferred financing costs associated with the restructuring of debt and equity as part of the Company’s emergence from chapter ~~11.~~11 proceedings during the six months ended June 30, 2017. See Note 10 for additional details.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have anyoff-balance sheet arrangements as of June 30, ~~2017.~~2018.

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 onForm 10-K for the year ended December 31, ~~2016~~ 2017 for additional risks related to the Company’s ~~business.~~business.

ITEM3 -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, ~~2017,~~2018, 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. ~~As a result~~The prices we receive for our production depend on many factors outside of ~~its hedging activities,~~our control, including volatility in the ~~Company may realize~~differences between product prices ~~that are less than or greater than~~at sales points and the ~~spot prices that it would have received otherwise.~~applicable index price.

The Company’s hedging policy limits the ~~amounts of resources~~volumes hedged to not ~~more~~be greater than 50% of its ~~forecast~~forecasted production volumes without Board approval. During 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.

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

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent thenon-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts: At June 30, ~~2017,~~ 2018, the Company had the following open commodity derivative contracts to manage commodity price ~~risk on a portion of its production whereby~~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.~~

~~Natural Gas:~~parties.

Type

Commodity
Reference Price

Remaining
Contract Period
   Volume -
MMBTU/
Day    Average
Price
/MMBTU    Fair Value -
June 30, 2017
               Asset
Fixed price swap
   NYMEX-Henry Hub    July - Oct 2017    575,000    $ 3.17    $ 8,367

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	)

⁽¹⁾Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming and the value of natural gas established on the last trading day of the month by the NYMEX for natural gas swaps for the respective period.

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.

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	)

The following table summarizes thepre-tax realized and unrealized gain (loss) ~~gain~~ the Company recognized related to its derivative instruments in the Consolidated Statements of Operations for the ~~periods~~quarter and six months ended June 30, ~~2017~~2018 and ~~2016:~~2017:

   For the Three Months    For the Six Months
   Ended June 30,    Ended June 30,
Commodity Derivatives:    2017    2016    2017    2016
Realized loss on commodity derivatives-natural gas (1)
   $ (868 )    $ —      $ (868 )    $ —
Unrealized gain on commodity derivatives (1)
   21,585    —      8,367    —








Total gain on commodity derivatives
   $ 20,717    $ —      $ 7,499    $ —

	For the Quarter Ended						For the Six Months
	Ended June 30,						Ended June 30,
Commodity Derivatives:	2018			2017			2018			2017
Realized gain (loss) on commodity derivatives - natural gas (1)	$	10,982		$	(868	)	$	12,426		$	(868	)
Realized loss on commodity derivatives - oil (1)		(4,320	)		—			(4,690	)		—
Unrealized gain (loss) on commodity derivatives (1)		(53,933	)		21,585			(61,539	)		8,367
Total gain (loss) on commodity derivatives	$	(47,271	)	$	20,717		$	(53,803	)	$	7,499

⁽¹⁾	Included in (Loss) gain on commodity derivatives in the Consolidated Statements of Operations.

ITEM4 —CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has performed an evaluation under the supervision and with the participation of our management, including our Interim Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined inRule 13a-15(e) and15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly ~~Report.~~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, ~~2017.~~2018.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended June 30, ~~2017~~2018 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — ~~OTHER~~OTHER INFORMATION

ITEM 1.LEGAL PROCEEDINGS

Other Claims: See Note 8 9for additional discussion ofon-going claims and disputes in 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.

ITEM 1A.RISK FACTORS

Our business has many risks. Any of the risks discussed in this Quarterly Report on Form10-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 have been no material changes to the risks described in the Company’s Annual Report on Form10-K ~~or Quarterly Report on Form10-Q~~ for the ~~periods~~year ended December 31, ~~2016 or March 31, 2017, respectively.~~2017. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

As of the Effective Date, the Company issued New Equity to the holders of claims against and interests in the Company, and the Company’s shares of common stock outstanding prior to the Effective Date was cancelled, in each case as provided in the Plan. Under the Plan, the Company’s new organizational documents became effective on the Effective Date. The Company’s new organizational documents authorized the Company to issue shares of New Equity pursuant to the Plan.None.

~~On the Effective Date, pursuant to the Plan:~~

~~70,579,367 shares of New Equity were issued pro rata to holders of the HoldCo Notes with claims allowed under the Plan;~~

~~80,022,410 shares of New Equity were issued pro rata to holders of Existing Common Shares;~~

~~2,512,623 shares of New Equity were issued to commitment parties under the Backstop Commitment Agreement in respect of the commitment premium due thereunder;~~

~~18,844,363 shares of New Equity were issued to commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder (the “Backstop Shares”); and~~

~~23,032,893 shares of New Equity were issued to participants in the Rights Offering.~~

With the exception of the Backstop Shares, New Equity was issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act, under Section 1145 of the Bankruptcy Code. The Backstop Shares were issued under the exemption from registration requirements of the Securities Act provided by Section 4(a)(2) thereof.

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.MINE SAFETY DISCLOSURES

None.

ITEM 5.OTHER INFORMATION

~~None.~~None.

ITEM 6.EXHIBITS

(a) Exhibits

2.1

~~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 Form8-K filed by Ultra Petroleum Corp. on March 16, ~~2017)~~2017).

3.1		Articles of Reorganization of Ultra Petroleum ~~Corp~~Corp. (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form8-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 ~~3.2~~3.1 to ~~Registration Statement~~the Current Report on Form~~8-A~~ 8-K filed by Ultra Petroleum Corp. on ~~April~~March 12, ~~2017)~~2018).

4.1		Specimen Common Share Certificate - (incorporated by reference to Exhibit 4.1 to the Current Report on Form8-K filed by Ultra Petroleum Corp. on April 18, 2017).

4.2		Indenture dated April 12, 2017 among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as ~~trustee.~~trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form8-K filed by Ultra Petroleum Corp. on April 18, 2017).

10.1		~~Senior Secured Term Loan~~ Second Amendment to Credit Agreement dated ~~as of~~ April ~~12, 2017,~~19, 2018, by and among ~~Ultra Petroleum Corp. and UP Energy Corporation, as parent guarantor,~~ Ultra Resources, Inc., as ~~borrower, Barclays~~a Borrower, Bank ~~PLC,~~of Montreal as ~~administrative agent~~Administrative Agent for the Lenders, and each of the ~~lenders and other parties~~Lenders party thereto. (incorporated by reference to Exhibit 10.1 to the Current Report on Form8-K filed by Ultra Petroleum Corp. on April ~~18, 2017)~~20, 2018).

10.2		~~Credit~~ Employment Agreement of Jerald J. “Jay” Stratton dated as of April 12, 2017, among Ultra Petroleum Corp. and UP Energy Corporation, as parent guarantor, Ultra Resources, Inc., as borrower, Bank of Montreal, as administrative agent, and the lenders and other parties party thereto. (incorporated by reference to Exhibit 10.2 to the Current Report on Form~~8-K~~ ~~filed by Ultra Petroleum Corp. on April 18, 2017)~~

~~10.3~~		Guaranty and Collateral Agreement dated as of April 12, 2017, among Ultra Petroleum Corp. and the other parties signatory there to, as grantors, and Bank of Montreal, as collateral agent. (incorporated by reference to Exhibit 10.3 to the Current Report on Form~~8-K~~ ~~filed by Ultra Petroleum Corp. on April 18, 2017)~~

~~10.4~~		~~Registration Rights Agreement dated as of April 12, 2017 by and among Ultra Petroleum Corp. and the other parties signatory thereto~~May 31, 2018 (incorporated by reference to Exhibit 10.1 to the ~~Registration Statement~~Current Report on Form~~8-A~~ 8-K filed by Ultra Petroleum Corp. on ~~April 12, 2017)~~June 1, 2018).
10.3
~~10.5~~		Ultra Petroleum Corp. 2017 Stock Incentive Plan, as amended and restated June 8, 2018 (incorporated by reference to Exhibit 10.1 to the ~~Registration Statement~~Current Report on Form~~S-8~~ 8-K filed by Ultra Petroleum Corp. on ~~April 12, 2017)~~June 14, 2018).
10.4
~~10.6~~		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to the ~~Registration Statement~~Current Report onForm ~~S-8~~8-K filed by Ultra Petroleum Corp. on ~~April 12, 2017)~~June 14, 2018).

~~10.7~~ *31.1		First Amendment to Plan Support Agreement effective as of February 10, 2017, by and among Ultra Petroleum Corp. and the other Debtors, on the one hand, and certain holders of common stock in Ultra Petroleum Corp. and debt securities issued by Ultra Petroleum Corp., on the other hand (incorporated by reference to Exhibit 10.1 to the Current Report on~~Form 8-K~~ ~~filed by Ultra Petroleum Corp. on February 15, 2017).~~

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.

~~99.1~~ 101.INS*		~~Order Confirming Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit 99.1 to the Current Report on Form8-K~~ ~~filed by Ultra Petroleum Corp. on March 16, 2017).~~

101.INS* XBRL Instance Document.
101.SCH*
XBRL Taxonomy Extension Schema Document.
101.CAL*
XBRL Taxonomy Calculation Linkbase Document.
101.LAB*
XBRL Label Linkbase Document.
101.PRE*
XBRL Presentation Linkbase Document.
101.DEF*
XBRL Taxonomy Extension Definition.

*	Filed herewith.

~~SIGNATURES~~SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


ULTRA PETROLEUM CORP.

~~By:~~	By:	/s/ ~~Michael D. Watford~~Brad Johnson
~~Name:~~		~~Michael D. Watford~~ Name:	Brad Johnson
~~Title:~~		~~Chairman, President and~~
Title:		Interim Chief Executive Officer

~~Date: August 9, 2017~~


~~By:~~
Date: August 9, 2018

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

Date: August 9, 2018

~~Date: August 9, 2017~~


	Shares Issued and Outstanding (000’s)			Common Stock		Retained Loss			Treasury Stock			Total Shareholders’ (Deficit) Equity
Balances at December 31, 2015		79,933		$	502,050	$	(3,493,811	)	$	(176	)	$	(2,991,937	)
Employee stock plan grants		145			—		—			—			—
Sharesre-issued from treasury		—			—		(127	)		127			—
Net share settlements		(61	)		—		(379	)		—			(379	)
Fair value of employee stock plan grants		—			8,014		—			—			8,014
Net income		—			—		56,151			—			56,151

Balances at December 31, 2016		80,017		$	510,064	$	(3,438,166	)	$	(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		2,160			26,417		—			—			26,417
Net share settlements		(841	)		—		(9,581	)		—			(9,581	)
Fair value of employee stock plan grants		—			9,870		—			—			9,870
Net income		—			—		409,338			—			409,338

Balances at June 30, 2017		196,315		$	2,098,355	$	(3,038,409	)	$	(49	)	$	(940,103	)


	Six Months Ended
	June 30,
	2017			2016
	(Unaudited)
	(Amounts in thousands of U.S. dollars)
Operating activities - cash provided by (used in):
Net income (loss) for the period	$	409,338		$	(7,832	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion, depreciation and amortization		70,427			62,083
Deferred income tax benefit		—			1
Unrealized gain on commodity derivatives		(8,367	)		—
Deferred gain on sale of liquids gathering system		(5,276	)		(5,276	)
Stock compensation		26,264			2,704
Non-cash reorganization items, net		(431,579	)		22,324
Other		1,160			5,907
Net changes in operating assets and liabilities:
Restricted cash		(18,194	)		(3,219	)
Accounts receivable		283			5,382
Other current assets		7,972			(13,277	)
Othernon-current assets		144			(818	)
Accounts payable		30,245			(70,552	)
Accrued liabilities		(8,654	)		(11,596	)
Production taxes payable		869			(7,467	)
Interest payable		32,438			57,118
Other long-term obligations		3,808			(3,465	)
Income taxes payable/receivable		2,099			(279	)

Net cash provided by operating activities		112,977			31,738

Investing Activities - cash provided by (used in):
Oil and gas property expenditures		(225,057	)		(121,542	)
Change in capital cost accrual		7,740			(13,500	)
Inventory		(2,276	)		(196	)
Purchase of capital assets		(756	)		122

Net cash used in investing activities		(220,349	)		(135,116	)

Financing activities - cash provided by (used in):
Borrowings under Credit Agreement		144,000			369,000
Borrowings under Term Loan		800,000			—
Extinguishment of long-term debt - (chapter 11)		(2,459,000	)		—
Payments under Credit Agreement		(67,000	)		—
Proceeds from issuance of Senior Notes		1,200,000			—
Deferred financing costs		(70,071	)		—
Shares issued, net of transaction costs		573,774			(307	)
Repurchased shares/net share settlements		(9,581	)		—
Reserve Fund		(400,236	)		—

Net cash (used in) provided by financing activities		(288,114	)		368,693

(Decrease) increase in cash and cash equivalents during the period		(395,486	)		265,315
Cash and cash equivalents, beginning of period		401,478			4,143

Cash and cash equivalents, end of period	$	5,992		$	269,458


	June 30, 2017
Liabilities subject to compromise at December 31, 2016	$	4,038,041
Debt extinguishment - cash		(2,521,493	)
Debt extinguishment -non-cash		(1,339,740	)
Contract settlement		(17,350	)
Reclassified to accrued liabilities		(159,458	)

Liabilities subject to compromise at June 30, 2017	$	—


	For the Three Months Ended						For the Six Months Ended
	June 30, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Professional fees(1)	$	(4,313	)	$	(3,582	)	$	(62,004	)	$	(3,582	)
Gains (losses)(2)		431,107			—			431,107			—
Deferred financing costs		—			(18,742	)		—			(18,742	)
Other(3)		22			141			167			141

Total Reorganization items, net	$	426,816		$	(22,183	)	$	369,270		$	(22,183	)


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2017		2016		2017		2016
	(Share amounts in 000’s)
Net income (loss)	$	499,037	$	14,002	$	409,338	$	(7,832	)

Weighted average common shares outstanding - basic		180,964		80,002		130,770		79,984
Effect of dilutive instruments		69		331		308		—

Weighted average common shares outstanding - diluted		181,033		80,333		131,078		79,984

Net income (loss) per common share - basic	$	2.76	$	0.18	$	3.13	$	(0.10	)

Net income (loss) per common share - diluted	$	2.76	$	0.17	$	3.12	$	(0.10	)

Number of shares not included in dilutive earnings per share that would have been anti-dilutive because the exercise price was greater than the average market price of the common shares (1)		—		749		—		—


				Weighted
	Number of			Average
	Options			Exercise Price
	(000’s)			(US Dollars)
Balance, December 31, 2015		271		$	94.04	to	$	189.57

Cancelled or Extinguished		(90	)	$	96.15	to	$	144.14

Balance, December 31, 2016		181		$	94.04	to	$	189.57

Cancelled or Extinguished		(181	)	$	94.04	to	$	144.14

Balance, June 30, 2017		—		$	0.00	to	$	0.00


	June 30, 2017				December 31, 2016(1)
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
Term loan, secured, due April 2024	$	800,000	$	794,000	$	—	$	—
6.875% Notes, unsecured, due April 2022, issued 2017		700,000		709,301		—		—
7.125% Notes, unsecured, due April 2025, issued 2017		500,000		501,599		—		—
Credit Facility due January 2022		77,000		77,000		—		—
7.31% Notes due March 2016, issued 2009		—		—		62,000		64,266
4.98% Notes due January 2017, issued 2010		—		—		116,000		123,967
5.92% Notes due March 2018, issued 2008		—		—		200,000		224,025
5.75% Notes due December 2018, issued 2013		—		—		450,000		465,630
7.77% Notes due March 2019, issued 2009		—		—		173,000		204,854
5.50% Notes due January 2020, issued 2010		—		—		207,000		233,932
4.51% Notes due October 2020, issued 2010		—		—		315,000		337,528
5.60% Notes due January 2022, issued 2010		—		—		87,000		99,983
4.66% Notes due October 2022, issued 2010		—		—		35,000		38,225
6.125% Notes due October 2024, issued 2014		—		—		850,000		893,325
5.85% Notes due January 2025, issued 2010		—		—		90,000		106,299
4.91% Notes due October 2025, issued 2010		—		—		175,000		193,665
Credit Facility due October 2016		—		—		999,000		999,000

	$	2,077,000	$	2,081,900	$	3,759,000	$	3,984,699



101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Calculation Linkbase Document.

101.LAB*		XBRL Label Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition.