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

or

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

For the transition period from                      to                     

Commission file number 001-33614

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 of Regulation 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, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

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 in Rule 12b-2 of the Act).    YES  ☐    NO  ☒

The number of shares outstanding, without par value, of Ultra Petroleum Corp., outstanding as of August 2, 2017 was 196,315,182.

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
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37
ITEM 4.	Controls and Procedures	38
PART II — OTHER INFORMATION
ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3.	Defaults upon Senior Securities	39
ITEM 4.	Mine Safety Disclosures	39
ITEM 5.	Other Information	39
ITEM 6.	Exhibits	40
	Signatures	42

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2017			2016			2017			2016
	(Unaudited)
	(Amounts in thousands of U.S. dollars, except per share data)
Revenues:
Natural gas sales	$	179,997		$	116,780		$	368,848		$	254,882
Oil sales		30,732			29,811			62,081			51,095
Other revenues		1,928			—			2,687			—
Total operating revenues		212,657			146,591			433,616			305,977
Expenses:
Lease operating expenses		23,089			21,836			46,225			47,230
Liquids gathering system operating lease expense		5,226			5,171			10,452			10,343
Production taxes		21,754			13,474			43,887			28,706
Gathering fees		20,642			21,504			41,571			43,954
Transportation charges		—			146			—			23,701
Depletion, depreciation and amortization		38,673			31,234			70,427			62,083
General and administrative		25,009			1,381			26,061			5,600
Total operating expenses		134,393			94,746			238,623			221,617
Operating income		78,264			51,845			194,993			84,360
Other income (expense), net:
Interest expense		(29,425	)		(16,662	)		(114,872	)		(66,565	)
Gain on commodity derivatives		20,717			—			7,499			—
Deferred gain on sale of liquids gathering system		2,638			2,638			5,276			5,276
Restructuring expenses		—			(1,569	)		—			(7,148	)
Contract settlement expense		—			—			(52,707	)		—
Other income (expense) , net		27			(227	)		(119	)		(1,922	)
Total other (expense) income, net		(6,043	)		(15,820	)		(154,923	)		(70,359	)
Reorganization items, net		426,816			(22,183	)		369,270			(22,183	)
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	)
Weighted average common shares outstanding - basic		180,964			80,002			130,770			79,984
Weighted average common shares outstanding - fully diluted		181,033			80,333			131,078			79,984

See accompanying notes to consolidated financial statements.

3

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2017			2016
	(Unaudited)
	(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	5,992		$	401,478
Restricted cash		435,501			3,571
Oil and gas revenue receivable		76,094			79,179
Joint interest billing and other receivables		14,590			10,781
Deposits and retainers		—			13,359
Derivative assets		8,367			—
Income tax receivable		—			2,099
Inventory		7,533			4,906
Other current assets		11,220			6,020
Total current assets		559,297			521,393
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,186,073			1,010,466
Property, plant and equipment, net		7,737			7,695
Other		8,896			1,374
Total assets	$	1,762,003		$	1,540,928
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	59,736		$	28,171
Accrued liabilities		237,466			53,348
Production taxes payable		45,198			44,329
Interest payable		20,625			—
Capital cost accrual		20,178			12,360
Total current liabilities		383,203			138,208
Long-term debt		2,016,914			—
Deferred gain on sale of liquids gathering system		110,465			115,742
Other long-term obligations		191,524			177,088
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
Treasury stock		(49	)		(49	)
Retained loss		(3,038,409	)		(3,438,165	)
Total shareholders’ deficit		(940,103	)		(2,928,151	)
Total liabilities and shareholders’ equity	$	1,762,003		$	1,540,928

See accompanying notes to consolidated financial statements.

4

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			—		—			—			—
Shares re-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 existing pre-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;

• 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.

5

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	)
Other non-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.

6

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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 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, Case No. 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”).

7

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.

8

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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:

	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, 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 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 and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by GAAP and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

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

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

(c) Restricted Cash: Restricted cash represents 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.

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

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

(f) Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities – Oil and Gas (“FASB ASC 932”). Under this method of

9

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 the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs are included in the base costs for calculating depletion.

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

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down for the six months ended June 30, 2017 or 2016.

(g) Inventories: At June 30, 2017 and 2016, inventory of $7.5 million and $4.1 million, respectively, primarily includes the cost of pipe and production equipment that will be utilized during the 2017 drilling program and crude oil inventory. Materials and supplies inventories are carried at lower of cost or market and include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. The Company uses the weighted average method of recording its materials and supplies inventory. Crude oil inventory is valued at lower of cost or market.

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

(i) Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 6 for more information).

10

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(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 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, 2017, the Company had 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 Note 4). There were no contingently issuable shares outstanding for the quarter and six months ended June 30, 2016.

	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.

11

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(m) 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) 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) 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 7 for additional information.

(p) 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) 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. 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.

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

(t) 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) Recent Accounting Pronouncements

12

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 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 ASU 2016-15, Statement of Cash Flows (Topic 230) (“ASU No. 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 (“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. 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 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.

We are currently evaluating the provisions of ASU 2014-09 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.

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 of initial application (the modified retrospective method). The Company currently anticipates adopting the standard using the modified retrospective method.

13

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 in a Current Report on Form 8-K filed with the SEC on April 18, 2017, on the Effective Date, all principal, prepetition interest, and other undisputed amounts were paid in full for the amounts owed under the prepetition Credit Agreement and the prepetition Senior Notes shown in the table above and the Company’s obligations under the prepetition Credit Agreement and the prepetition Senior Notes were cancelled and extinguished. The claims related to the 2018 and 2024 Notes, shown in the table above were allowed in full, each claim holder received a distribution of our common stock in the amount of the applicable claim, and the Company’s obligations under the 2018 and 2024 Notes were cancelled and extinguished.

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.

14

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 interest rate at June 30, 2017 was 3.93%. The Revolving Credit Facility loans mature on January 12, 2022.

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.

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 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.

15

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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. 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 distribution 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

16

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

17

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, 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, 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 in pre-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.

18

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. INCOME TAXES:

The Company’s overall effective tax rate on pre-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 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.

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 the pre-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.

19

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.

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 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	$	—	$	8,367	$	—	$	8,367

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.

20

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 is on-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.

21

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 Form 8-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.

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

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

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 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 and gas sales from wells located in the Appalachian Basin in Pennsylvania.

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

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, Case No. 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.

23

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”).

• 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	$	—

24

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.

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:

	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.

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.

25

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”) 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

26

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).

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.

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.

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.

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.

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 ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU No. 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.

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In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) (“ASU No. 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 (“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. 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 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.

We are currently evaluating the provisions of ASU 2014-09 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.

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 of initial application (the modified retrospective method). The Company currently anticipates adopting the standard using the modified retrospective method.

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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.

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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 the quarter 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

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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 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 $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.

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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.

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Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the six 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.

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 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).

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

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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 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 interest rate at June 30, 2017 was 3.93%. The Revolving Credit Facility loans mature on January 12, 2022.

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.

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 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.

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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.

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. 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,

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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 distribution 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, 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.

Cash flows provided by (used in):

Operating Activities. During the six months ended June 30, 2017, net cash provided by operating activities was $113.0 million compared to net cash provided by operating activities of $31.7 million for the same period in 2016. The increase in net cash provided by operating activities is largely attributable to increased revenues as a result of increased average 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.

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

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

in 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 emergence from chapter 11.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of June 30, 2017.

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

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

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and increased financing costs due to a significant increase in interest rates. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 for additional risks related to the Company’s business.

ITEM 3 - QUANTITATIVE AND 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, 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 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 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.

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 expense or income 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. See Note 7 for the detail of the fair value of the following derivatives.

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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 the pre-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.

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.

ITEM 4 — 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 Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report. The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2017.

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 that have materially affected or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other Claims:    See Note 8 for additional discussion of on-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 Form 10-Q or in our other SEC filings, could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes to the risks described in the Company’s Annual Report on Form 10-K or Quarterly Report on Form 10-Q for the periods ended December 31, 2016 or March 31, 2017, respectively. 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.

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.

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ITEM 6. EXHIBITS

(a) Exhibits

2.1	Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit A of the Order Confirming Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization, filed as Exhibit 99.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on March 16, 2017).
3.1	Articles of Reorganization of Ultra Petroleum Corp (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form 8-A filed by Ultra Petroleum Corp. on April 12, 2017).
3.2	Amended and Restated Bylaw No. 1 of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 to Registration Statement on Form 8-A filed by Ultra Petroleum Corp. on April 12, 2017).
4.1	Specimen Common Share Certificate - (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017).
4.2	Indenture dated April 12, 2017 among Ultra Resources, Inc., Ultra Petroleum Corp., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017)
10.1	Senior Secured Term Loan Agreement dated as of April 12, 2017, among Ultra Petroleum Corp. and UP Energy Corporation, as parent guarantor, Ultra Resources, Inc., as borrower, Barclays Bank PLC, as administrative agent and the lenders and other parties party thereto. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on April 18, 2017)
10.2	Credit Agreement 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 (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form 8-A filed by Ultra Petroleum Corp. on April 12, 2017).
10.5	Ultra Petroleum Corp. 2017 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 filed by Ultra Petroleum Corp. on April 12, 2017).
10.6	Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8 filed by Ultra Petroleum Corp. on April 12, 2017).
10.7	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*	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	Order Confirming Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on March 16, 2017).

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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.

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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:	/s/ Michael D. Watford
Name:	Michael D. Watford
Title:	Chairman, President and
	Chief Executive Officer

Date: August 9, 2017

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

Date: August 9, 2017

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