Ultra Petroleum 8-K Other Events

	Exhibit 99.1
		Page
INDEX TO FINANCIAL STATEMENTS
	Report of Independent Registered Public Accounting Firm		2
	Consolidated Balance Sheet as of December 31, 2016 and 2015		3
	Consolidated Statement of Operations for the years ended December 31, 2016, 2015, and 2014		4
	Consolidated Statement of Changes in Stockholders’ Equity for the years ended December 31, 2016, 2015, and 2014		5
	Consolidated Statement of Cash Flows for the years ended December 31, 2016, 2015, and 2014		6
	Notes to Consolidated Financial Statements		7

1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Ultra Petroleum Corp. and subsidiaries

We have audited the accompanying consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Ultra Petroleum Corp. and subsidiaries at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

Since the date of the completion of our audit of the accompanying consolidated financial statements and initial issuance of our report thereon dated February 22, 2017, which report contained an explanatory paragraph regarding the Company’s ability to continue as a going concern, as discussed under the caption “DESCRIPTION OF THE BUSINESS - Chapter 11 Proceedings, Ability to Continue as a Going Concern – Ability to Continue as a Going Concern” in the Notes to the Consolidated Financial Statements, the Company’s plan of reorganization became effective and the Company emerged from bankruptcy on April 12, 2017.  Therefore, the conditions that raised substantial doubt about whether the Company will continue as a going concern no longer exist.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Ultra Petroleum Corp. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2017, expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP

Houston, Texas

February 22, 2017

Except for the portion of:  DESCRIPTION OF THE BUSINESS - Chapter 11 Proceedings, Ability to Continue as a Going Concern – Ability to Continue as a Going Concern, as to which the date is November 15, 2017

2

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016			2015			2014
	(Amounts in thousands of U.S. dollars, except per share data)
Revenues:
Natural gas sales	$	609,756		$	696,730		$	969,850
Oil sales		111,335			142,381			260,170
Total operating revenues		721,091			839,111			1,230,020
Expenses:
Lease operating expenses		89,134			106,906			96,496
Liquids gathering system operating lease expense		20,686			20,647			20,306
Production taxes		69,737			72,774			103,898
Gathering fees		86,809			87,904			59,931
Transportation charges		20,049			83,803			77,780
Depletion, depreciation and amortization		125,121			401,200			292,951
Ceiling test and other impairments		—			3,144,899			—
General and administrative		9,179			7,387			19,069
Total operating expenses		420,715			3,925,520			670,431
Operating income (loss)		300,376			(3,086,409	)		559,589
Other income (expense), net:
Interest expense (excludes contractual interest expense of $141.5 million    for the year ended December 31, 2016)		(66,565	)		(171,918	)		(126,157	)
Gain on commodity derivatives		—			42,611			82,402
Deferred gain on sale of liquids gathering system		10,553			10,553			10,553
Litigation expense		—			(4,401	)		—
Restructuring expenses		(7,176	)		—			—
Contract settlement		(131,106	)		—			—
Gain on sale of property		—			—			8,022
Other (expense) income, net		(3,082	)		(2,060	)		2,618
Total other (expense) income, net		(197,376	)		(125,215	)		(22,562	)
Reorganization items, net		(47,503	)		—			—
Income (loss) before income tax benefit		55,497			(3,211,624	)		537,027
Income tax benefit		(654	)		(4,404	)		(5,824	)
Net income (loss)	$	56,151		$	(3,207,220	)	$	542,851
Basic Earnings (Loss) per Share:
Net income (loss) per common share — basic	$	0.37		$	(20.94	)	$	3.54
Fully Diluted Earnings (Loss) per Share:
Net income (loss) per common share — fully diluted	$	0.36		$	(20.94	)	$	3.51
Weighted average common shares outstanding — basic		153,378			153,192			153,136
Weighted average common shares outstanding — fully diluted		154,081			153,192			154,694

Approved on behalf of the Board:
/s/ Michael D. Watford	/s/ Michael J. Keeffe
Chairman of the Board, Chief Executive Officer and President	Director

See accompanying notes to consolidated financial statements.

3

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

(Debtor-in-Possession)

CONSOLIDATED BALANCE SHEETS

	December 31, 2016			December 31, 2015
	(Amounts in thousands of U. S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	401,478		$	4,143
Restricted cash		3,571			115
Oil and gas revenue receivable		79,179			61,881
Joint interest billing and other receivables		10,781			11,356
Income tax receivable		2,099			5,150
Inventory		4,906			4,269
Deposits and retainers		13,359			—
Other current assets		6,020			4,300
Total current assets		521,393			91,214
Oil and gas properties, net, using the full cost method of accounting:
Proven		1,010,466			851,145
Property, plant and equipment		7,695			8,844
Deferred income taxes		—			1
Other		1,374			835
Total assets	$	1,540,928		$	952,039
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	28,171		$	93,415
Accrued liabilities		53,348			72,428
Production taxes payable		44,329			52,273
Current portion of long-term debt		—			3,370,553
Interest payable		—			42,657
Capital cost accrual		12,360			20,571
Total current liabilities		138,208			3,651,897
Deferred gain on sale of liquids gathering system		115,742			126,295
Other long-term obligations		177,088			165,784
Total liabilities not subject to compromise		431,038			3,943,976
Liabilities subject to compromise		4,038,041			—
Commitments and contingencies (Note 11)
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding    shares — 153,418,041 and 153,255,989, at December 31, 2016 and 2015,    respectively		510,063			502,050
Treasury stock		(49	)		(176	)
Retained loss		(3,438,165	)		(3,493,811	)
Total shareholders’ deficit		(2,928,151	)		(2,991,937	)
Total liabilities and shareholders’ equity	$	1,540,928		$	952,039

See accompanying notes to consolidated financial statements.

4

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

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

	Shares Issued and Outstanding			Common Stock			Retained Loss			Treasury Stock			Total Shareholders’ (Deficit) Equity
Balances at December 31, 2013		152,991		$	487,273		$	(816,802	)	$	(1,961	)	$	(331,490	)
Stock options exercised		43			770			—			—			770
Employee stock plan grants		298			700			—			—			700
Shares re-issued from treasury		—			(770	)		(1,450	)		2,220			—
Shares repurchased		(332	)		—			—			(6,472	)		(6,472	)
Net share settlements		(104	)		—			(2,639	)		—			(2,639	)
Fair value of employee stock plan grants		—			7,940			—			—			7,940
Net income		—			—			542,851			—			542,851
Balances at December 31, 2014		152,896		$	495,913		$	(278,040	)	$	(6,213	)	$	211,660
Employee stock plan grants		526			700			—			—			700
Shares re-issued from treasury		—			—			(6,037	)		6,037			—
Net share settlements		(166	)		—			(2,514	)		—			(2,514	)
Fair value of employee stock plan grants		—			5,437			—			—			5,437
Net (loss)		—			—			(3,207,220	)		—			(3,207,220	)
Balances at December 31, 2015		153,256		$	502,050		$	(3,493,811	)	$	(176	)	$	(2,991,937	)
Employee stock plan grants		279			—			—			—			—
Shares re-issued from treasury		—			—			(127	)		127			—
Net share settlements		(117	)		—			(379	)		—			(379	)
Fair value of employee stock plan grants		—			8,014			—			—			8,014
Net income		—			—			56,151			—			56,151
Balances at December 31, 2016		153,418		$	510,064		$	(3,438,166	)	$	(49	)	$	(2,928,151	)

See accompanying notes to consolidated financial statements.

5

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

(Debtor-in-Possession)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015			2014
	(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net income (loss) for the period	$	56,151		$	(3,207,220	)	$	542,851
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depletion, depreciation and amortization		125,121			401,200			292,951
Ceiling test and other impairments		—			3,144,899			—
Deferred and current non-cash income taxes		1			(990	)		995
Unrealized (gain) loss on commodity derivatives		—			104,190			(130,066	)
Deferred gain on sale of liquids gathering system		(10,553	)		(10,553	)		(10,553	)
Gain on sale of property		—			—			(8,022	)
Stock compensation		5,562			4,128			5,467
Non-cash reorganization items, net		42,523			—			—
Other		6,870			9,217			4,569
Net changes in operating assets and liabilities:
Restricted cash		(3,456	)		2			2
Accounts receivable		(19,635	)		65,132			(43,116	)
Other current assets		(15,647	)		(20,106	)		(1,920	)
Other non-current assets		(539	)		21,112			284
Accounts payable		(63,924	)		13,815			28,696
Accrued liabilities		133,144			1,655			(5,938	)
Production taxes payable		(7,944	)		(3,312	)		15,115
Interest payable		57,117			(3,441	)		14,233
Other long-term obligations		276			(5,770	)		6,427
Current taxes payable/receivable		2,547			1,580			609
Net cash provided by operating activities		307,614			515,538			712,584
Investing Activities:
Acquisition of oil and gas properties		—			3,964			(891,075	)
Oil and gas property expenditures		(269,314	)		(494,025	)		(599,913	)
Gathering system expenditures		—			—			(6,842	)
Proceeds from sale of property		—			—			27,944
Change in capital cost accrual		(8,134	)		(25,380	)		(125,577	)
Inventory		(1,123	)		3,235			175
Purchase of property, plant and equipment		(329	)		(551	)		(5,455	)
Net cash used in investing activities		(278,900	)		(512,757	)		(1,600,743	)
Financing activities:
Borrowings on long-term debt		369,000			1,165,000			1,095,000
Payments on long-term debt		—			(1,153,000	)		(1,037,000	)
Proceeds from issuance of Senior Notes		—			—			850,000
Deferred financing costs		—			6			(13,245	)
Repurchased shares/net share settlements		(379	)		(2,514	)		(9,111	)
Payment of contingent consideration		—			(17,049	)		—
Proceeds from exercise of options		—			—		770
Net cash provided by (used in) financing activities		368,621			(7,557	)		886,414
Increase/(Decrease) in cash during the period		397,335			(4,776	)		(1,745	)
Cash and cash equivalents, beginning of period		4,143			8,919			10,664
Cash and cash equivalents, end of period	$	401,478		$	4,143		$	8,919
SUPPLEMENTAL INFORMATION:
Cash paid for:
Interest	$	4,793		$	169,867		$	108,889
Income taxes	$	94		$	—		$	1,752
Non-cash investing activities — oil and gas properties	$	—		$	—		$	20,000

See accompanying notes to consolidated financial statements.

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ULTRA PETROLEUM CORP. AND SUBSIDIARIES

(Debtor-in-Possession)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(All amounts in this Report on Form 10-K 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, Ability to Continue as a Going Concern

Chapter 11 Proceedings

On April 29, 2016 (the “Petition Date”), to restructure their respective obligations and capital structures, the Company and each of its direct and indirect wholly owned subsidiaries (collectively, the “Ultra Entities” or “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”). The Debtors’ chapter 11 cases are being jointly administered for procedural purposes under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.). Information about our chapter 11 cases is available at our website (www.ultrapetroleum.com) and also at a website maintained by our claims agent, Epiq Systems (http://dm.epiq11.com/UPT/Docket).

We are currently operating our business as a debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. After we filed our chapter 11 petitions, the Bankruptcy Court granted certain relief we requested enabling us to conduct our business activities in the ordinary course, including, among other things and subject to the terms and conditions of such orders, authorizing us to pay employee wages and benefits, pay taxes and certain governmental fees and charges, continue to operate our cash management system in the ordinary course, remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and pay the prepetition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms.

Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the date on which our chapter 11 cases were filed were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our prepetition liabilities and obligations should be settled or compromised under the Bankruptcy Code as part of our chapter 11 proceedings.

Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors”. In addition, our assets, liabilities, including our capital structure, shareholders, officers and/or directors could change materially because of our chapter 11 cases. In addition, the description of our operations, properties and capital plans included in this Annual Report on Form 10-K may not accurately reflect our operations, properties and capital plans after we emerge from chapter 11.

Creditors’ Committees – Appointment & Formation

On May 5, 2016, the United States Trustee for the Southern District of Texas appointed an official committee for unsecured creditors of all of the Debtors (the “UCC”). On September 26, 2016, the United States Trustee for the Southern District of Texas filed a Notice of Reconstitution of the UCC. In addition, certain other stakeholders have organized for purposes of participating in the Debtors’ chapter 11 cases: (i) on June 8, 2016, an informal ad hoc committee of unsecured creditors of our subsidiary, Ultra Resources, Inc. (“Ultra Resources”), notified the Bankruptcy Court it had formed and identified its members, most of which are distressed debt investors and/or hedge funds; (ii) on June 13, 2016, an informal ad hoc committee of the holders of senior notes issued by the Company notified the Bankruptcy Court it had formed and identified its members; (iii) on July 20, 2016, an informal ad hoc committee of shareholders of the Company notified the Bankruptcy Court it had formed and identified its members; and (iv) on January 6, 2017, an informal ad hoc committee of unsecured creditors of our subsidiary, Ultra Resources, notified the Bankruptcy Court it had formed and identified its members, most of which are insurance companies. We expect each of the committees to be involved in our chapter 11 cases, and any disagreements with any of the committees may extend our chapter 11 cases, increase the cost of our chapter 11 cases, and/or delay our emergence from chapter 11.

Exclusivity

The Bankruptcy Code provides chapter 11 debtors-in-possession with the exclusive right to file a plan of reorganization under chapter 11 through a period of time specified in the Bankruptcy Code, which period may be extended by the Bankruptcy Court. On July 27, 2016, we filed a motion seeking an extension of the exclusive chapter 11 plan filing period. At a hearing conducted on August 25, 2016, the Bankruptcy Court extended our exclusive right to file a plan of reorganization under chapter 11 through and including March 1, 2017, and to solicit acceptances

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of such plan through and including May 1, 2017, subject to our producing and delivering a long-term business plan prior to December 1, 2016. The long-term business plan was provided prior to December 1, 2016, and, pursuant to a Stipulation Regarding Order Extending Exclusivity signed by the Bankruptcy Court, we satisfied the condition (with the effect that our exclusive right to file a reorganization plan now continues until and including March 1, 2017, and our exclusive right to solicit acceptances of such a plan continues until and including May 1, 2017). On February 1, 2017, we filed a motion seeking an extension of the exclusive chapter 11 plan filing period through June 29, 2017 and the exclusive right to solicit acceptances of a chapter 11 plan through August 29, 2017. On February 17, 2017, we filed a revised proposed form of order to the motion seeking an extension of the exclusive chapter 11 plan filing period through April 15, 2017 and the exclusive right to solicit acceptances of a chapter 11 plan through June 15, 2017.

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

On November 21, 2016, each of the Ultra Entities entered into a Plan Support Agreement (“PSA”) with (i) holders of at least 66.67% of the principal amount of the Company’s outstanding 5.750% Senior Notes due 2018 and 6.125% Senior Notes due 2024 and (ii) shareholders who own at least a majority of the Company’s outstanding common stock or the economic interests therein (collectively, the “Plan Support Parties”) and a Backstop Commitment Agreement (“BCA”) with a subset thereof (collectively, the “Commitment Parties”).

Plan Support Agreement:    The PSA sets forth the terms and conditions pursuant to which the Ultra Entities and the Commitment Parties have agreed to seek and support a joint plan of reorganization at an aggregate plan value of $6.25 billion, $6.0 billion, or $5.5 billion, depending on commodity prices, for the Ultra Entities which will successfully complete the Reorganization Proceedings (collectively, the “Plan”). Under the Plan, the total enterprise value of the Ultra Entities will be $6.0 billion (the “Plan Value”); provided, that if the average closing price of the 12-month forward Henry Hub natural gas strip price during the seven (7) trading days preceding the commencement of the Rights Offering solicitation is: (i) greater than $3.65/MMBtu, the Plan Value will be $6.25 billion; or (ii) less than $3.25/MMBtu, the Plan Value will be $5.5 billion.

Among other matters, the Plan provides for a comprehensive restructuring of all allowable claims against and interests in the Ultra Entities, including the conversion of the outstanding unsecured senior notes issued by the Company (“HoldCo Notes” and, the holders thereof, “HoldCo Noteholders”) to newly-issued shares of common stock in the Company, the exchange of the outstanding unsecured senior notes issued by UPL’s subsidiary Ultra Resources for a combination of new unsecured notes issued by Ultra Resources and cash, the payment in full of all other allowed claims against the Ultra Debtors in cash, and the distribution to each owner of common stock in the Company as of the Plan’s record date (“HoldCo Equityholders”) of such owner’s pro rata share of the new UPL common stock and the right to participate in the Rights Offering (as described below).

The PSA provides certain milestones for the restructuring, which the Company is required to use commercially reasonable efforts to satisfy. Failure of the Company to satisfy certain milestones, including (i) entry of an order approving the Debtors’ entry into the BCA by January 20, 2017 and (ii) consummation of the Plan by April 15, 2017 would provide the Plan Support Parties a termination right under the PSA.

On February 9, 2017, the Company entered into the First Amendment to the Plan Support Agreement (the “PSA Amendment”) with the Plan Support Parties party thereto. Pursuant to the PSA Amendment, the Required Consenting Parties agreed that the Plan Term Sheet, as modified to accord with the treatment of OpCo Funded Debt Claims and General Unsecured Claims under the Second Amended Plan, is reasonably satisfactory to such parties (as such terms are defined in the Plan Support Agreement).

On February 13, 2017, the Court signed an order approving our Disclosure Statement. On February 21, 2017, the Court signed an amended order approving our Disclosure Statement. The amended order: (1) approves the adequacy of our Disclosure Statement, (2) approves the solicitation and notice procedures related to confirmation of our plan of reorganization, (3) approves the forms of ballots and notices related thereto, (4) approves the rights offering procedures and matters related thereto, (5) schedules certain dates related to our plan confirmation process and Rights Offering, and (6) grants related relief. With respect to the Rights Offering, the amended order defines the “Subscription Commencement Date” as February 21, 2017. Accordingly, as will be reflected in the materials to be distributed in connection with the Rights Offering, the Plan Value under the PSA is $6.0 billion.

Rights Offering:    In accordance with the Plan, the BCA and the Rights Offering procedures submitted by the Company in connection with the Plan, the Company will offer eligible debt and equity holders, including the Commitment Parties, the right to purchase shares of new common stock in the Company upon effectiveness of the Plan for an aggregate purchase price of $580.0 million. The Rights Offering will consist of the following offerings:

• HoldCo Noteholders shall be granted rights (the “HoldCo Noteholder Rights Offering”) entitling each such holder to subscribe for the Rights Offering in an amount up to its pro rata share of new common stock (the “HoldCo Noteholder Rights Offering Shares”), which HoldCo Noteholder Rights Offering Shares, collectively, will reflect an aggregate purchase price of $435.0 million.

• HoldCo Equityholders shall be granted rights (the “HoldCo Equityholder Rights Offering”) entitling each such holder to subscribe for the Rights Offering in an amount up to its pro rata share of new common stock (the “HoldCo Equityholder Rights Offering Shares” and, together with the HoldCo Noteholder Rights Offering Shares, the “Rights Offering Shares”), which HoldCo Equityholder Rights Offering Shares, collectively, will reflect an aggregate purchase price of $145.0 million.

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Backstop Commitment Agreement:    Under the BCA, the Commitment Parties have agreed to purchase the HoldCo Noteholder Rights Offering Shares and the HoldCo Equityholder Rights Offering Shares, as applicable, that are not duly subscribed for pursuant to the HoldCo Noteholder Rights Offering or the HoldCo Equityholder Rights Offering, as applicable, by parties other than Commitment Parties (the “Backstop Commitment”) at an implied 20% discount to the Plan Value, which is the price for the rights offering set forth in the PSA (the “Rights Offering Price”).

The Company will pay the Commitment Parties upon the closing of the Rights Offering a Commitment Premium equal to 6.0% of the $580.0 million committed amount (the “Commitment Premium”). The Commitment Premium was fully earned as of January 19, 2017, the date the Backstop Approval Order was entered by the Bankruptcy Court. The Commitment Premium will be paid either in the form of new common stock at the Rights Offering Price, if the Plan is consummated as contemplated in the Plan Support Agreement, or in cash in the amount of 4.0% of the $580.0 million committed amount, if the Backstop Agreement is terminated other than as a result of a material breach by the Commitment Parties.

Exit Financing Commitment Letter:    On February 8, 2017, the Debtors obtained a commitment letter (the “Commitment Letter”) from Barclays Bank PLC (including any affiliates that may perform its responsibilities thereunder, “Barclays”), pursuant to which, in connection with the consummation of the Plan, Barclays has agreed to provide secured and unsecured financing in an aggregate amount of up to $2.4 billion, consisting of:

• A seven-year senior secured first lien term loan credit facility (the “Term Loan Facility”) in an aggregate amount of $600.0 million;

• A five-year senior secured first lien revolving credit facility (the “Revolving Facility”) in an aggregate amount of $400.0 million with an initial borrowing base (the “Borrowing Base”) (which limits the aggregate amount of first lien debt under the Revolving Facility and the Term Loan Facility) of $1.0 billion with scheduled semi-annual redeterminations starting on October 1, 2017; and

• Senior unsecured bridge loans under senior unsecured bridge facilities (together with the Revolving Facility and the Term Loan Facility, the “Credit Facilities”) in an aggregate amount of $1.4 billion, consisting of (i) a five-year bridge facility in an aggregate principal amount of $700.0 million, less the aggregate principal amount of privately placed five-year senior unsecured notes of the Company, if any, issued on or prior to the closing date of the Credit Facilities (the “Closing Date”) and (ii) an eight-year bridge facility in an aggregate principal amount of $700.0 million, less the aggregate principal amount of privately placed eight-year senior unsecured notes of the Company, if any, issued on or prior to the Closing Date.

The Revolving Facility is anticipated to, among other things:

• have capacity for the Debtors to increase the commitments subject to certain conditions;

• have $100.0 million of the commitments available for the issuance of letters of credit; and

• require the Company to maintain (A) a maximum total net debt to EBITDAX ratio of (i) 4.25 to 1.0 as of the end of the first full fiscal quarter after the closing date and each subsequent fiscal quarter of 2017 and (ii) 4.0 to 1.0 as of the end of each fiscal quarter thereafter, (B) a minimum current ratio of 1.0 to 1.0 and (C) a minimum interest coverage ratio of 2.5 to 1.0.

The Term Loan Facility is anticipated to, among other things, have capacity for the Debtors to increase the commitments, with such increase in commitments subject to certain conditions.

The Revolving Facility and Term Loan Facility will include customary affirmative and negative covenants, including, among other things, as to compliance with laws, delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of properties (including oil and gas properties), maintenance of a lien on, and delivery of title information with respect to, 85% of the Debtors’ proved oil and gas reserves, restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.

The Revolving Facility and Term Loan Facility will include events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to material indebtedness; bankruptcy; material judgments; and certain ERISA events. Many events of default are subject to customary notice and cure periods.

The commitments of Barclays to provide the Credit Facilities are subject to certain conditions set forth in the Commitment Letter, including but not limited to the Plan Support Parties’ reasonable satisfaction with the approval by the Bankruptcy Court of all actions to be taken, undertakings to be made and obligations to be incurred by the Debtors in connection with the Credit Facilities.

The Commitment Letter will terminate upon the occurrence of certain events described therein and the outside termination date for the Commitment Letter is May 9, 2017.

Based on the indicative pricing levels provided to the Company, the blended interest rate of the Credit Facilities on the effective date of the Plan (the “Blended Rate”) is expected to be approximately 5.10% per annum. The actual Blended Rate on the effective date of the Plan will depend on factors including, without limitation, the size of each tranche of the Credit Facilities and the results of the syndication process of such Credit Facilities, and may therefore be higher or lower than 5.10% per annum.

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As previously disclosed on a Current Report on Form 8-K filed with the SEC on February 9, 2017, on February 8, 2017, the Debtors filed a motion with the Bankruptcy Court seeking authorization to enter into and perform under the Commitment Letter and the other commitment papers. The motion was heard and approved during the Company’s disclosure statement hearing on February 13, 2017.

Plan of Reorganization (Disclosure Statement)

We plan to emerge from our chapter 11 cases after we obtain approval from the Bankruptcy Court for a chapter 11 plan of reorganization. Among other things, a chapter 11 plan of reorganization will determine the rights and satisfy the claims of our prepetition creditors and security holders. The terms and conditions of a chapter 11 plan of reorganization will be determined through negotiations with our stakeholders and, possibly, decisions by the Bankruptcy Court.

On December 6, 2016, we filed an initial plan of reorganization and disclosure statement therefore. On January 17, 2017, we filed a revised plan of reorganization and disclosure statement therefore. On February 8, 2017, we filed a further revised plan of reorganization and disclosure statement therefore. On February 13, 2017, we filed amendments and further revisions to the plan of reorganization we filed on February 8, 2017 (the “Plan”) and to the disclosure statement therefore (the “Disclosure Statement”). The Court approved our Disclosure Statement on February 13, 2017 and scheduled a hearing to consider confirmation of the Plan for March 14, 2017.

Under the absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of our existing common stock can receive any distribution or retain any property under a chapter 11 plan of reorganization. The ultimate recovery to creditors and/or shareholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors or shareholders. Our plan of reorganization could result in any of the holders of our liabilities and/or securities, including our common stock, receiving no distribution on account of their interests and cancellation of their holdings. Moreover, a plan of reorganization can be confirmed, under the Bankruptcy Code, even if the holders of our common stock vote against the plan and even if the plan provides that the holders of our common stock receive no distribution on account of their equity interests.

Liabilities Subject to Compromise

We have applied Accounting Standards Codification (“ASC”) 852, Reorganizations, in preparing the Consolidated Financial Statements included in this Annual Report on Form 10-K. In addition, the consolidated financial statements presented here include amounts classified as “liabilities subject to compromise.” This amount represents estimates of known or potential prepetition claims expected to be resolved in connection with our chapter 11 proceedings. Additional amounts may be included in liabilities subject to compromise in future periods if we elect to reject executory contracts and unexpired leases as part of our chapter 11 cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Annual Report on Form 10-K and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the chapter 11 process, and we plan to make adjustments in future periods as necessary and appropriate. Such adjustments may be material.

Under the Bankruptcy Code, we may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. If we reject a contract or lease, such rejection generally (1) is treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieves the Debtors of performing their future obligations under such contract or lease, and (3) entitles the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. If we assume an executory contract or unexpired lease, we are generally required to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty. Accordingly, any description of an executory contract or unexpired lease in this Annual Report on Form 10-K, including any quantification of our obligations under any such contract or lease, is wholly qualified by the rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto.

The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of December 31, 2016:

	December 31, 2016
Accounts payable	$	1,322
Accrued liabilities		6,303
Accrued interest payable		99,774
Debt		3,759,000
Accrued contract settlements		171,642
Liabilities subject to compromise	$	4,038,041

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Schedules and Statements – Magnitude of Potential Claims & Claims Resolution Process

On June 8, 2016, each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. On October 14, 2016, Ultra Wyoming LGS, LLC (“UWLGS”), one of the Debtors and our indirect, wholly owned subsidiary, filed an amendment to its Schedules and Statements. The Schedules and Statements are subject to further amendment or modification. Certain holders of prepetition claims were required to file proofs of claim by the deadline for filing certain proofs of claims in the Debtors’ chapter 11 cases, which deadline was September 1, 2016, for prepetition general unsecured claims and October 26, 2016, for governmental claims. Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and will likely continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

To the best of our knowledge, we have notified all of our known current or potential creditors that the Debtors have filed chapter 11 cases. The Schedules and Statements set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors is a party, and are subject to the qualifications and assumptions included therein and amendment or modification as our chapter 11 cases proceed.

Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate.

Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. In addition, there are differences between the amounts for certain claims listed in the Schedules and Statements and the amounts claimed by our creditors. Such differences, as well as other disputes and contingencies will be investigated and resolved as part of our claims resolution process in our chapter 11 cases. Please refer to Note 11 for additional information about contingent matters and commitments related to certain claims filed in our chapter 11 cases.

Pursuant to the Federal Rules of Bankruptcy Procedure, some creditors who wished to assert prepetition claims against us and whose claims (i) were not listed in the Schedules and Statements or (ii) were listed in the Schedules and Statements as disputed, contingent, or unliquidated, were required to file a proof of claim with the Bankruptcy Court prior to the bar date set by the court. The bar date for non-governmental creditors was September 1, 2016, and the bar date for governmental creditors was October 26, 2016.

The claims filed against the Debtors to date are voluminous. Further, it is possible that claimants will file amended or modified claims in the future, including modifications or amendments to assign values to claims originally filed with no designated value. The amended or modified claims may be material.

We plan to investigate and evaluate all filed claims in connection with our plan of reorganization. As a part of the claims resolution process, we anticipate working to resolve differences in amounts we listed in our Schedules and Statements and amounts of claims filed by our creditors. We have already identified, for example, claims that we believe should be disallowed by the Bankruptcy Court because they are duplicative, have been later amended or superseded, are without merit, are overstated or for other reasons. We have previously filed, and we will continue to file and prosecute objections with the Bankruptcy Court as necessary for claims we believe should be disallowed.

Tax Attributes; Net Operating Loss Carryforwards

We have substantial tax net operating loss carryforwards and other tax attributes. Under the U.S. Internal Revenue Code, our ability to use these net operating losses and other tax attributes may be limited if we experience a change of control, as determined under U.S. Internal Revenue Code. Accordingly, we obtained an order from the Bankruptcy Court that is intended to protect our ability to use our tax attributes by imposing certain notice procedures and transfer restrictions on the trading of the Company’s common stock.

In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of the Company’s common stock. Such persons are required to notify us and the Bankruptcy Court before effecting a transaction that might result in us losing the ability to use our tax attributes, and we have the right to seek an injunction to prevent the transaction if it might adversely affect our ability to use our tax attributes.

Any purchase, sale or other transfer of our equity securities in violation of the restrictions of the order is null and would be treated as invalid from the outset as an act in violation of a Bankruptcy Court order and would therefore confer no rights on a proposed transferee.

Costs of Reorganization

We have incurred and will continue to incur significant costs associated with our reorganization and the chapter 11 proceedings. We expect these costs, which are being expensed as incurred, will significantly affect our results of operations. In addition, a non-cash charge to write-off the unamortized debt issuance costs related to our funded indebtedness is included in “Reorganization items, net” as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. For additional information about the costs of our reorganization and chapter 11 proceedings, see “Reorganization items, net” below.

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The following table summarizes the components included in Reorganization items, net in our Consolidated Statements of Operations for the three and year months ended December 31, 2016:

	For the Twelve Months Ended December 31,
	2016			2015		2014
Professional fees(1)	$	11,781		$	—	$	—
Deferred financing costs(2)		18,742			—		—
Contract settlements(3)		17,350			—		—
Other(4)		(370	)		—		—
Total Reorganization items, net	$	47,503		$	—	$	—

(1) The year ended December 31, 2016 includes $6.4 million directly related to accrued, unpaid professional fees associated with the chapter 11 filings.

(2) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases.

(3) Includes accrued, unpaid amounts subject to Bankruptcy Court approval related to a settlement reached with Big West Oil, LLC in the amount of $17.35 million.

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

Ability to Continue as a Going Concern

The Consolidated Financial Statements included in this Annual Report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. As a result of our financial condition at the time the financial statements were originally issued, including the defaults under our debt agreements, and the risks and uncertainties surrounding our chapter 11 proceedings, we concluded that substantial doubt existed that we would be able to continue as a going concern.

On March 14, 2017, the Bankruptcy Court confirmed the Company’s Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization and on April 12, 2017, the Company emerged from bankruptcy.  Upon emergence from bankruptcy, the Company entered into the secured and unsecured exit financing agreements of $2.4 billion in commitments, satisfied the obligations under the outstanding debt agreements as described in Note 5, and completed the Rights Offering of $580.0 million.  As a result of the execution of the Plan, improved financial conditions, and successful emergence from chapter 11, the Company believes it has sufficient liquidity to fund anticipated 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 of the financial statements issued.

1. SIGNIFICANT ACCOUNTING POLICIES:

Our accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements.

(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 U.S. Generally Accepted Accounting Principles (“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 primarily represents 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.

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

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

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

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess asa 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 have any write-downs related to the full cost ceiling limitation in 2016 or 2014. During 2015, the Company recorded a $3.1 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials.

(g) Inventories:     At December 31, 2016 and 2015, inventory of $4.9 million and $4.3 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) Derivative Instruments and Hedging Activities:     The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 7).

(i) Deferred Financing Costs:     During the year ended December 31, 2016, a non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, unsecured Senior Notes (as defined below) issued by Ultra Resources, Inc., the unsecured 2018 Senior Notes (as defined below) issued by the Company and the unsecured 2024 Senior Notes (as defined below) issued by the Company is included in Reorganization items, net in the accompanying Consolidated Statements of Operations as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases. At December 31, 2015, other current assets includes costs associated with the issuance of our revolving credit facility while costs associated with the issuance of our Senior Notes, 2018 Notes and 2024 Notes are presented as a direct deduction from the carrying amount of the related debt liability.

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

(k) Earnings (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. The weighted average shares in the table below do not consider any potential dilutive effects of the proposed plan of reorganization discussed in Note 1.

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

	December 31,
		2016		2015			2014
Net income		$	56,151	$	(3,207,220	)	$	542,851
Weighted average common shares outstanding during the period			153,378		153,192			153,136
Effect of dilutive instruments			703		—			1,558
Weighted average common shares outstanding during the    period including the effects of dilutive instruments			154,081		153,192			154,694
Net income per common share — basic		$	0.37	$	(20.94	)	$	3.54
Net income per common share — fully diluted		$	0.36	$	(20.94	)	$	3.51
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			1,437		—			1,377

(1) Due to the net loss for the year ended December 31, 2015, 1.7 million shares for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.

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

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

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

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

(p) Revenue Recognition:     The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. 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

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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 December 31, 2016 and December 31, 2015 were immaterial.

(q) Capitalized Interest:    Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any.

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

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

(t) Deposits and Retainers:     Deposits and retainers primarily consists of payments related to surety bonds.

(u) 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. The ASU 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 does not expect the adoption of this ASU to have a material impact 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 this ASU to have a material impact on its consolidated financial statements.

In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU No. 2016-09”) to simplify some of the provisions in stock compensation accounting. The update simplifies the accounting for a stock payment’s tax consequences and amends how excess tax benefits and a business’s payments to cover the tax bills for the shares’ recipients should be classified. The amendments allow companies to estimate the number of stock awards expected to vest and revises the withholding requirements for classifying stock awards as equity. For public companies, the standard will take effect for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 with earlier application permitted. The Company is still evaluating the impact of ASU No. 2016-09 on its financial position and results of operations.

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 financial position and results of operations.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (“ASU No. 2015-11”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material impact on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, Interest — Imputation of Interest (Subtopic 835-30) —Simplifying the Presentation of Debt Issuance Costs. In August 2015, the FASB issued ASU 2015-15, Interest —Imputation of Interest (Subtopic 835-30) — Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . These ASUs require capitalized debt issuance costs, except for those related to revolving credit facilities, to be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, rather than as an asset. The Company adopted these ASUs on January 1, 2016, using a retrospective approach. The

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adoption resulted in a reclassification that reduced current assets and current maturities of long-term debt by $19.4 million on the Company’s Consolidated Balance Sheet at December 31, 2015. A non-cash charge to write-off all of the unamortized debt issuance costs is included in Reorganization items, net at December 31, 2016 as the related debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases.

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 Subtopic932-605, 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 dedicated resources to the implementation, completed training of the new ASU’s revenue recognition model, and begun contract review and documentation. The primary impacts to the Company of adopting ASU 2014-09 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 cumulative catch-up transition method). The Company is currently evaluating the available adoption methods.

In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that requires management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods ending after December 15, 2016 and for interim reporting periods thereafter. The adoption of this ASU did not have a material impact on the Company’s Consolidated Financial Statements.

2. ASSET RETIREMENT OBLIGATIONS:

The Company is required to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended:

	December 31,
	2016			2015
Asset retirement obligations at beginning of period	$	146,210		$	127,240
Accretion expense		10,252			9,122
Liabilities incurred		1,317			7,352
Liabilities settled		(170	)		(1,861	)
Revisions of estimated liabilities		(436	)		4,357
Asset retirement obligations at end of period		157,173			146,210
Less: current asset retirement obligations		(239	)		(305	)
Long-term asset retirement obligations	$	156,934		$	145,905

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3.OIL AND GAS PROPERTIES:

	December 31, 2016			December 31, 2015
Proven Properties:
Acquisition, equipment, exploration, drilling and    environmental costs	$	10,752,642		$	10,480,165
Less: Accumulated depletion, depreciation and    amortization(1)		(9,742,176	)		(9,629,020	)
		1,010,466			851,145

On a unit basis, DD&A was $0.44, $1.38 and $1.18 per Mcfe for the years ended December 31, 2016, 2015 and 2014, respectively.

(1) During 2015, the Company recorded a $3.1 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations, which is reflected within ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the preceding twelve month period at December 31, 2015 for Henry Hub natural gas and West Texas Intermediate oil, adjusted for market differentials.

4. PROPERTY, PLANT AND EQUIPMENT:

	December 31,
	2016							2015
	Cost		Accumulated Depreciation			Net Book Value		Net Book Value
Computer equipment		2,840		(2,237	)		603		794
Office equipment		309		(171	)		138		196
Leasehold improvements		486		(301	)		185		267
Land		4,637		—			4,637		4,637
Other		12,460		(10,328	)		2,132		2,950
Property, plant and equipment, net	$	20,732	$	(13,037	)	$	7,695	$	8,844

5. DEBT AND OTHER LONG-TERM LIABILITIES:

	December 31, 2016			December 31, 2015
Total Debt:
6.125% Senior Notes due 2024	$	850,000		$	850,000
5.75% Senior Notes due 2018		450,000			450,000
Senior Notes issued by Ultra Resources, Inc.		1,460,000			1,460,000
Credit Agreement		999,000			630,000
Total current portion of long-term debt		3,759,000			3,390,000
Less: Deferred financing costs(1)		—			(19,447	)
Less: Liabilities subject to compromise(2) (See Note 1)		(3,759,000	)		—
Total current portion of long-term debt not subject to    compromise		—		$	3,370,553

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	December 31, 2016		December 31, 2015
Other long-term obligations:
Other long-term obligations	$	177,088	$	165,784

Aggregate maturities of debt at December 31, 2016:(2)
2017		2018		2019		2020		2021		Beyond 5 years		Total
$	3,759,000	$	—	$	—	$	—	$	—	$	—	$	3,759,000

(1) A non-cash charge to write-off all of the unamortized debt issuance costs related to the unsecured Credit Agreement, the unsecured Senior Notes issued by Ultra Resources, the unsecured 2018 Senior Notes issued by the Company and the unsecured 2024 Senior Notes issued by the Company is included in Reorganization items, net in the Consolidated Statements of Operations as these debt instruments are expected to be impacted by the pendency of the Company’s chapter 11 cases.

(2) We have significant indebtedness, all of which is included with liabilities subject to compromise at December 31, 2016 in the Consolidated Balance Sheets. Our level of indebtedness has adversely impacted and is continuing to adversely impact our financial condition. As a result of our financial condition, the defaults under our debt agreements and the risks and uncertainties surrounding our chapter 11 proceedings, substantial doubt exists that we will be able to continue as a going concern. As a result, we have classified all of our total outstanding debt as short-term.

Ultra Resources, Inc.

Bank indebtedness.    Ultra Resources, Inc. (“Ultra Resources”), a wholly owned subsidiary of the Company, is a party to the Credit Agreement. Ultra Resources’ obligations under the Credit Agreement are guaranteed by the Company and UP Energy Corporation, a wholly owned subsidiary of the Company.

Ultra Resources’ filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated its obligations under the Credit Agreement. Other events of default are also present with respect to the Credit Agreement, including a failure to make interest payments and, as described below, a failure to deliver annual audited consolidated financial statements without a going concern qualification, a failure to meet the minimum PV-9 ratio covenant and a failure to comply with the consolidated leverage covenant in the Credit Agreement at the end of the first quarter of 2016. The Credit Agreement provides that upon the acceleration of Ultra Resources’ obligations under the Credit Agreement, the outstanding balance of loans extended under the Credit Agreement comes due, unpaid interest accrued as of the time of the acceleration comes due, and any fees or other obligations of the borrower come due. Under the Bankruptcy Code, the creditors under the Credit Agreement are stayed from taking any action against Ultra Resources or any of the other Debtors as a result of the default.

Prior to April 29, 2016, loans under the Credit Agreement bore interest, at the borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus a margin based on a grid of the borrower’s consolidated leverage ratio, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the borrower’s consolidated leverage ratio.

The Credit Agreement requires us to deliver annual audited, consolidated financial statements for the Company without a “going concern” or like qualification or explanation. On March 15, 2016, we delivered an audit report with respect to the financial statements in our 2015 Annual Report on Form 10-K that included an explanatory paragraph expressing uncertainty as to our ability to continue as a “going concern.”

The Credit Agreement contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31, 2016 (the ratio was 4.6 times at March 31, 2016).

The Credit Agreement contains a PV-9 covenant, pursuant to which Ultra Resources is required to maintain a minimum ratio of the discounted net present value of its oil and gas properties to its total funded consolidated debt of 1.5 times. We were required to report whether we were in compliance with this covenant on April 1, 2016. Based on the PV-9 of its oil and gas properties at December 31, 2015, Ultra Resources failed to comply with the PV-9 ratio covenant under the Credit Agreement (the ratio was 0.9 times at December 31, 2015).

Senior Notes.    Ultra Resources has outstanding $1.46 billion of senior notes (“Senior Notes”) which were issued pursuant to a certain Master Note Purchase Agreement dated as of March 6, 2008 (as amended, supplemented or otherwise modified, the “MNPA”). The Senior Notes rank pari passu with the Credit Agreement. Payment of the Senior Notes is guaranteed by the Company and by UP Energy Corporation. The Senior Notes are subject to representations, warranties, covenants and events of default similar to those in the Credit Agreement.

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Ultra Resources’ filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated its obligations under the MNPA and the Senior Notes. Other events of default are also present with respect to the MNPA, including a failure to comply with the consolidated leverage covenant at the end of the first quarter of 2016 and a failure to make principal and interest payments due under the Ultra Resources’ Senior Notes. The MNPA provides that upon the acceleration of Ultra Resources’ obligations under the MNPA and the Senior Notes, among other matters, the Senior Notes are deemed to have matured, the unpaid principal balance of the Senior Notes comes due, unpaid interest accrued as of the time of the acceleration comes due, and any applicable make-whole amount (as determined pursuant to the MNPA) comes due. Under the Bankruptcy Code, the creditors under the Senior Notes are stayed from taking any action against Ultra Resources or any of the other the Debtors as a result of the default.

The MNPA contains a consolidated leverage covenant, pursuant to which Ultra Resources is required to maintain a maximum ratio of its total funded consolidated debt to its trailing four fiscal quarters’ EBITDAX of 3.5 to 1.0. Based on Ultra Resources’ EBITDAX for the trailing four fiscal quarters ended March 31, 2016, we were not in compliance with this consolidated leverage covenant at March 31, 2016 (the ratio was 4.6 times at March 31, 2016).

On March 1, 2016, we failed to make an interest payment of approximately $40.0 million and a principal payment of $62.0 million, each of which was due March 1, 2016 under the terms of the Senior Notes. We entered into a forbearance agreement related to the failure to make these payments with the holders of the Senior Notes, and we filed the chapter 11 petitions without making the payments before the forbearance period expired.

Interest Expense.    No interest expense has been recognized with respect to the Credit Agreement or the Senior Notes subsequent to the Petition Date.

Ultra Petroleum Corp. Senior Notes

The Company’s filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated the Company’s obligations under the 2024 Notes and the 2018 Notes. Additionally, other events of default, including cross-defaults, are present due to the failure to make interest payments and other matters. Under the indentures pursuant to which the 2024 Notes and the 2018 Notes, respectively, were issued, upon the acceleration of the Company’s obligations under the 2024 Notes and the 2018 Notes, among other matters, the 2024 Notes and the 2018 Notes, respectively, are deemed to have matured, the unpaid principal balance of the 2024 Notes and the 2018 Notes, respectively, comes due, unpaid interest accrued as of the time of the acceleration comes due, and any applicable premiums (as determined pursuant to the indentures) comes due. Under the Bankruptcy Code, the creditors under the 2024 Notes and the 2018 Notes are stayed from taking any action against the Debtors as a result of the default.

Senior Notes due 2024:    On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and, as a result, are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions.

Interest due under the 2024 Notes is payable each April 1 and October 1. On April 1, 2016, we elected to defer making an interest payment on the 2024 Notes of approximately $26.0 million due April 1, 2016. The indenture governing the 2024 Notes provides a 30-day grace period for us to make this interest payment. We did not make this interest payment before the end of the grace period, which resulted in an event of default under the indenture governing the 2024 Notes.

Senior Notes due 2018:    On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and, as a result, are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. Interest due under the 2018 Notes is payable each June 15 and December 15.

The Company’s filing of the chapter 11 petitions described in Note 1 constituted an event of default that accelerated the Company’s obligations under the 2024 Notes and the 2018 Notes. Additionally, other events of default, including cross-defaults resulting from the acceleration of indebtedness outstanding under the Credit Agreement and the Ultra Resources’ Senior Notes, are present due to the failure to make interest payments and other matters. Under the Bankruptcy Code, the creditors under the 2024 Notes and the 2018 Notes are stayed from taking any action against the Debtors as a result of the Company’s bankruptcy filings.

Interest Expense.    No interest expense has been recognized with respect to the 2024 Notes or the 2018 Notes subsequent to the Petition Date.

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

6. SHARE BASED COMPENSATION:

The Company sponsors a share based compensation plan: the 2015 Stock Incentive Plan (“2015 Plan”). The Plan is administered by the Compensation Committee of the Board of Directors (the “Committee”). The share based compensation plan is an important component of the total compensation package offered to the Company’s key service providers, and reflects the importance that the Company places on motivating and rewarding superior results.

The purpose of the 2015 Plan is to foster and promote the long-term financial success of the Company and to increase shareholder value by attracting, motivating and retaining key employees, consultants, and outside directors, and providing such participants with a program for obtaining an ownership interest in the Company that links and aligns their personal interests with those of the Company’s shareholders, and thus, enabling such participants to share in the long-term growth and success of the Company. To accomplish these goals, the Plan permits the granting of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock, and other stock-based awards, some of which may require the satisfaction of performance-based criteria in order to be payable to participants. The Committee determines the terms and conditions of the awards, including, any vesting requirements and vesting restrictions and estimates forfeitures that may occur. The Committee may grant awards under the 2015 Plan until December 31, 2024.

Valuation and Expense Information

	Year Ended December 31,
	2016		2015		2014
Total cost of share-based payment plans	$	8,013	$	6,137	$	8,640
Amounts capitalized in oil and gas properties and equipment	$	2,451	$	2,009	$	3,173
Amounts charged against income, before income tax benefit	$	5,562	$	4,128	$	5,467
Amount of related income tax benefit recognized in income    before valuation allowances	$	2,216	$	1,645	$	2,285

Securities Authorized for Issuance Under Equity Compensation Plans

As of December 31, 2016, the Company had the following securities issuable pursuant to outstanding award agreements or reserved for issuance under the Company’s previously approved stock incentive plans. Upon exercise, shares issued will be newly issued shares or shares issued from treasury.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options		Weighted Average Exercise Price of Outstanding Options		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in the First Column)
	(000’s)				(000’s)
Equity compensation plans approved by security holders		346	$	60.64		4,339
Equity compensation plans not approved by security    holders	n/a		n/a		n/a
Total		346	$	60.64		4,339

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Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the three year period ended December 31, 2016:

	Number of Options			Weighted Average Exercise Price (US$)
	(000’s)
Balance, December 31, 2013		1,246		$	16.97	to	$	98.87
Forfeited		(513	)	$	33.57	to	$	75.18
Exercised		(43	)	$	16.97	to	$	25.68
Balance, December 31, 2014		690		$	25.68	to	$	98.87
Forfeited		(171	)	$	25.68	to	$	75.18
Balance, December 31, 2015		519		$	49.05	to	$	98.87
Forfeited		(173	)	$	50.15	to	$	75.18
Balance, December 31, 2016		346		$	49.05	to	$	98.87

The following table summarizes information about the stock options outstanding and exercisable at December 31, 2016:

	Options Outstanding and Exercisable
Range of Exercise Price	Number Outstanding		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
	(000’s)		(Years)
$49.05 — $62.23		210		0.31	$	54.12	$	—
$51.60 — $98.87		136		1.45	$	70.64	$	—

The aggregate intrinsic value in the preceding tables represents the total pre-tax intrinsic value, based on the Company’s closing stock price of $7.23 per share on December 31, 2016, which would have been received by the option holders had all option holders exercised their options as of that date. There were no in-the-money options exercisable as of December 31, 2016.

The following table summarizes information about the weighted-average grant-date fair value of share options:

	2016		2015		2014
Options forfeited during the year	$	25.17	$	28.00	$	24.40

As of December 31, 2011, all options were fully vested; therefore, no options vested during the years ended December 31, 2016, 2015 or 2014. There were no stock options exercised during the years ended December 31, 2016, 2015 and 2014.

At December 31, 2016, there was no unrecognized compensation cost related to non-vested, employee stock options as all options fully vested as of December 31, 2011.

PERFORMANCE SHARE PLANS:

Long Term Incentive Plans.    During 2015 and 2014, the Company offered a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years.

Under each LTIP, the Committee establishes a percentage of base salary for each participant that is multiplied by the participant’s base salary at the beginning of the performance period and individual performance level to derive a Long Term Incentive Value as a “target” value. This “target” value corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the participant is employed by the Company through the date the award vests and if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event the Company’s actual performance is below or above target levels.

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Time-Based Measure and Performance-Based Measures:

For each LTIP, the Compensation Committee established time-based and performance-based measures at the beginning of each three-year performance period. For the LTIP awards in 2015 and 2014, the Compensation Committee established the following performance-based measures: return on capital employed, debt level, and reserve replacement ratio. At the time the LTIP awards are awarded, the fair value of the time-based and performance-based component of the LTIP award is based on the average high and low market price of the Company’s common stock on the date of the award.

Market-Based Measure (Total Shareholder Return):

LTIP awards granted to officers during 2016 and 2015, included an additional performance metric, Total Shareholder Return. The grant-date fair value related to the market-based condition was calculated using a Monte Carlo simulation.

Valuation Assumptions

The Company estimates the fair value of the market condition related to the LTIP awards on the date of grant using a Monte Carlo simulation with the following assumptions:

	2015 LTIP			2014 LTIP
Volatility of common stock		40.1	%		39.0	%
Average volatility of peer companies		46.5	%	n/a
Average correlation coefficient of peer companies		0.454		n/a
Risk-free interest rate		1.02	%		0.66	%

Stock-Based Compensation Cost:

For the year ended December 31, 2016, the Company recognized $4.7 million in pre-tax compensation expense related to the 2015 and 2014 LTIP awards. For the year ended December 31, 2015, the Company recognized $2.9 million in pre-tax compensation expense related to the 2015, 2014 and 2013 LTIP awards. For the year ended December 31, 2014, the Company recognized $6.3 million in pre-tax compensation expense related to the 2014, 2013 and 2012 LTIP awards. The amounts recognized during the year ended December 31,

2016 assumes that performance objectives between less than threshold and up to maximum are attained for the 2015 LTIP and 2014 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at December 31, 2016, for each of the three-year performance periods is expected to be approximately $10.3 million and $9.5 million related to the 2015 and 2014 LTIP awards of restricted stock units, respectively.

Based on the Company’s achievement relative to the 2013 LTIP’s performance-based measures, and based on the continued employment with the Company by those participants who received a payment in connection with the 2013 LTIP relative to the 2013 LTIP’s time-based measures, during the first quarter of 2016, the Compensation Committee approved payment of the 2013 LTIP. This was the first payment of an LTIP since our LTIPs were modified in 2013 to include time-based and performance-based measures. As such, the Compensation Committee elected to pay the time-based portion of the LTIP awards in cash at the award value and the performance-based portion of the LTIP awards in shares of our common stock. The payout of the 2013 LTIP was during the first quarter of 2016 and totaled $3.8 million (resulting in delivery of 132,843 net shares of our common stock to eligible participants in the 2013 LTIP).

7. DERIVATIVE FINANCIAL INSTRUMENTS:

Objectives and Strategy:    The Company’s major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is currently driven primarily by the prevailing price for the Company’s Wyoming 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 balance sheet 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

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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 Consolidated Statements of Cash Flows.

Commodity Derivative Contracts:     At December 31, 2016, the Company had no open commodity derivative contracts to manage price risk on a portion of its production.

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014:

	For the Year Ended December 31,
Commodity Derivatives:	2016		2015			2014
Realized gain (loss) on commodity derivatives-natural gas(1)	$	—	$	146,801		$	(48,170	)
Realized gain on commodity derivatives-crude oil(1)		—		—			506
Unrealized (loss) gain on commodity derivatives(1)		—		(104,190	)		130,066
Total gain on commodity derivatives	$	—	$	42,611		$	82,402

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

8. FAIR VALUE MEASUREMENTS:

As required by FASB ASC Topic 820, Fair Value Measurements and Disclosures (“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 we have 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.

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

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Assets and Liabilities Measured on a Non-recurring Basis

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

Fair Value of Financial Instruments

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

	December 31, 2016(1)				December 31, 2015
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
7.31% Notes due March 2016, issued 2009		62,000		64,266		62,000		63,604
4.98% Notes due January 2017, issued 2010		116,000		123,967		116,000		113,420
5.92% Notes due March 2018, issued 2008		200,000		224,025		200,000		191,985
5.75% Notes due December 2018, issued 2013		450,000		465,630		450,000		111,451
7.77% Notes due March 2019, issued 2009		173,000		204,854		173,000		174,488
5.50% Notes due January 2020, issued 2010		207,000		233,932		207,000		185,052
4.51% Notes due October 2020, issued 2010		315,000		337,528		315,000		258,520
5.60% Notes due January 2022, issued 2010		87,000		99,983		87,000		73,034
4.66% Notes due October 2022, issued 2010		35,000		38,225		35,000		25,558
6.125% Notes due October 2024, issued 2014		850,000		893,325		850,000		206,321
5.85% Notes due January 2025, issued 2010		90,000		106,299		90,000		70,756
4.91% Notes due October 2025, issued 2010		175,000		193,665		175,000		115,911
Credit Facility due October 2016		999,000		999,000		630,000		630,000
	$	3,759,000	$	3,984,699	$	3,390,000	$	2,220,100

(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.

9. INCOME TAXES:

Income (loss) before income tax benefit is as follows:

	Year Ended December 31,
	2016			2015			2014
United States	$	134,959		$	(3,249,590	)	$	505,689
Foreign		(79,462	)		37,966			31,338
Total	$	55,497		$	(3,211,624	)	$	537,027

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The consolidated income tax (benefit) provision is comprised of the following:

	Year Ended December 31,
	2016			2015			2014
Current tax:
U.S. federal, state and local	$	(72	)	$	—		$	(110	)
Foreign		(583	)		(3,414	)		(6,709	)
Total current tax (benefit)		(655	)		(3,414	)		(6,819	)
Deferred tax:
Foreign		1			(990	)		995
Total deferred tax (benefit) expense		1			(990	)		995
Total income tax (benefit)	$	(654	)	$	(4,404	)	$	(5,824	)

The income tax provision (benefit) from continuing operations differs from the amount that would be computed by applying the U.S. federal income tax rate of 35% to pretax income as a result of the following:

	Year Ended December 31,
	2016			2015			2014
Income tax provision (benefit) computed at the U.S. statutory rate	$	19,424		$	(1,124,069	)	$	187,959
State income tax (benefit) provision net of federal effect		(2,335	)		(12,998	)		8,023
Valuation allowance		(31,083	)		1,147,619			(199,038	)
Tax effect of rate change		—			12,898			15,457
Foreign rate differential		17,388			(26,740	)		(16,314	)
Other, net		(4,048	)		(1,114	)		(1,911	)
Total income tax (benefit)	$	(654	)	$	(4,404	)	$	(5,824	)

The tax effects of temporary differences that give rise to significant components of the Company’s deferred tax assets and liabilities are as follows:

	December 31,
	2016			2015
Deferred tax assets :
Property and equipment		603,045			776,504
Deferred gain		40,867			44,593
U.S. federal tax credit carryforwards		15,967			16,144
U.S. net operating loss carryforwards		428,212			319,673
U.S. state net operating loss carryforwards		71,323			61,919
Non-U.S. net operating loss carryforwards		30,211			9,142
Asset retirement obligations		55,700			51,815
Liabilities subject to compromise-contract settlement		59,166			—
Incentive compensation/other, net		16,088			28,711
		1,320,579			1,308,501
Valuation allowance		(1,270,935	)		(1,307,076	)
Net deferred tax assets	$	49,644		$	1,425
Deferred tax liabilities :
Liabilities subject to compromise-interest		35,498			—
Liabilities subject to compromise-interest (non-U.S.)		14,146			—
Other — non-US		—			1,424
Net tax liabilities	$	49,644		$	1,424
Net tax asset	$	—		$	1

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible or before the attributes expire unused. Among other items,

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management considers the scheduled reversal of deferred tax liabilities, historical taxable income, projected future taxable income, and available tax planning strategies.

At December 31, 2016 and 2015, the Company recorded a valuation allowance against certain deferred tax assets of $1.3 billion and $1.3 billion, respectively. Some or all of this valuation allowance may be reversed in future periods if future taxable income of the appropriate character is available to recognize certain deferred tax assets. The Company’s valuation allowance decreased by $36.1 million from December 31, 2015 to December 31, 2016. Of this amount, $31.1 million reduced the Company’s current year deferred tax benefit, and $5.1 million was reflected through shareholders’ equity.

As of December 31, 2016, the Company had approximately $13.7 million of U.S. federal alternative minimum tax (AMT) credits available to offset regular U.S. Federal income taxes. These AMT credits do not expire and can be carried forward indefinitely. The Company has $0.5 million of general business credits available to offset U.S. federal income taxes. These general business credits expire in 2032. In addition, the Company has $1.6 million of foreign tax credit carryforwards, which will expire in 2017.

The Company has a U.S. federal tax net operating loss carryforward of $1.2 billion which will be carried forward to offset taxable income generated in future years, and if unutilized, will expire between 2033 and 2036. The Company has Pennsylvania state tax net operating loss carry forwards of $1.1 billion which will expire between 2031 and 2036. The Company has Utah state tax net operating loss carry forwards of $80.8 million which will expire between 2033 and 2036. The Company has immaterial state tax net operating loss carry forwards in other jurisdictions, none of which expire prior to 2020. Without regard to the recorded valuation allowance, if the Company experiences an ownership change as determined under Section 382 of the Internal Revenue Code, our ability to utilize our substantial net operating loss carryforwards and other tax attributes may be limited, if we can use them at all.

The Company has a Canada Federal and Provincial tax loss carryforward remaining after carryback of $111.9 million that will be carried forward to offset taxable income generated in future years and will expire in 2036.

The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations related to accounting for uncertain tax positions. The amount of unrecognized tax benefits did not change as of December 31, 2016.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statements of Operations. The Company has not incurred any interest or penalties associated with unrecognized tax benefits.

The Company files a consolidated federal income tax return in the United States federal jurisdiction and various combined, consolidated, unitary, and separate filings in several states, and international jurisdictions. With certain exceptions, the income tax years 2013 through 2016 remain open to examination by the major taxing jurisdictions in which the Company has business activity.

The undistributed earnings of the Company’s U.S. subsidiaries are considered to be indefinitely invested outside of Canada. Accordingly, no provision for Canadian income taxes and/or withholding taxes has been provided thereon.

10.    EMPLOYEE BENEFITS:

The Company sponsors a qualified, tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its employees. Employees may defer 100% of their compensation, subject to limitations. The Company matches all of the employee’s contribution up to 5% of compensation, as defined by the plan, along with an employer discretionary contribution of 8%. The expense associated with the Company’s contribution was $2.3 million, $2.3 million and $2.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

11.    COMMITMENTS AND CONTINGENCIES:

The commencement of the chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates, and the Company has obtained from the Bankruptcy Court authority to pay certain prepetition claims in the ordinary course of business notwithstanding the commencement of the chapter 11 proceedings. A future plan of reorganization in the chapter 11 proceedings, when confirmed, will provide for the treatment of claims against the Company’s bankruptcy estates, including prepetition liabilities that have not otherwise been satisfied or addressed during the chapter 11 proceedings.

Indebtedness Claims

The chapter 11 filings by the Company and its various subsidiaries, including Ultra Resources, constituted events of default under the Company’s debt agreements. See Note 5 of this Annual Report on Form 10-K for more information about the debt agreements. On or around September 1, 2016, many of the holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid interest that had accrued by the petition dates, interest that has accrued since the petition dates (including interest at the default rates under the debt agreements), make-whole amounts, and other fees and obligations under the debt agreements. On December 29, 2016, holders of certain Senior Notes (as defined below) filed a complaint initiating an adversary proceeding

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against us in our chapter 11 cases. In the complaint, among other matters, the noteholders allege that there is a make-whole amount due under the Senior Notes as a result of our filing the chapter 11 cases, which they assert is “no less than $200,725,869, exclusive of any interest thereon.” On January 13, 2017, holders of certain other Senior Notes intervened to join the adversary proceeding as plaintiffs. On January 30, 2017, we filed a motion to dismiss the complaint. On February 10, 2017, both noteholder groups objected to our motion to dismiss. On February 13, 2017, the Court set a briefing schedule and a hearing date for April 20, 2017 for resolution of the make-whole and interest claims. 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. We anticipate these claims will be resolved during our chapter 11 proceedings, although it is possible resolution of some of these matters could occur after we emerge from chapter 11.

Rockies Express Pipeline

On February 26, 2016, we received a letter from Sempra Rockies Marketing, LLC (“Sempra”) alleging that we were in breach of our Capacity Release Agreement, dated March 5, 2009 (the “Capacity Agreement”), resulting from nonpayment of fees for transportation service and notifying us that Sempra was authorized to recall the capacity released to us under the Capacity Agreement and to pursue any claims for damages or other remedies to which Sempra was entitled. On March 8, 2016, we received a letter from Sempra notifying us that Sempra was exercising its alleged right to permanently recall the 50,000 MMBtu/day of capacity on the Rockies Express Pipeline pursuant to the Capacity Agreement and that the recall would be effective as of March 9, 2016. On August 25, 2016, Sempra filed a proof of claim with the Bankruptcy Court for approximately $63.8 million. On October 28, 2016, we filed an objection to Sempra’s proof of claim. On December 20, 2016, Sempra filed a response to the Company’s objection. On November 28, 2016, the Bankruptcy Court entered a scheduling order establishing March 2, 2017 as the trial date for the claim objection. On January 23, 2017, the Bankruptcy Court entered an updated scheduling order establishing April 18, 2017 as the trial date for the claim objection. Our estimate of the potential exposure in connection with the Capacity Agreement and Sempra’s claim filed in our chapter 11 proceedings ranges from $4.2 million, which represents amounts Sempra paid to Rockies Express attributable to the capacity released to us under the Capacity Agreement prior to Sempra’s recalling such capacity, to $63.8 million. We anticipate Sempra’s claims will be resolved through our chapter 11 proceedings.

On April 4, 2016, we received a demand for payment and notice of enforcement from Rockies Express Pipeline LLC (“REX”) in connection with the transportation agreement related to the Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016. On April 14, 2016, REX filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages related to the alleged breach. On August 26, 2016, REX filed a proof of claim with the Bankruptcy Court for $303.3 million. The Company objected to REX’s proof of claim. On January 12, 2017, REX and the Company entered into a settlement agreement resolving REX’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to REX of $150.0 million six months after the Company emerges from chapter 11, but no later than October 30, 2017, and to provide REX an allowed general unsecured claim under our Plan in that amount. Additionally, in connection with the settlement, we agreed to enter into, with REX, a new seven-year agreement, commencing December 1, 2019, for firm transportation service on the Rockies Express Pipeline, west-to-east, of 200,000 dekatherms per day at a rate of approximately $0.37 per dekatherm, or approximately $26.8 million annually. The settlement with REX has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization.

Royalties

On April 19, 2016, the Company received a preliminary determination notice from the Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under Federal oil and gas leases. During the second quarter of 2016, the Company responded to the preliminary determination asserting the reasonableness of its allocation methodology of such costs, noting several matters we believed should have been considered in the preliminary determination notice. The ONRR unbundling review could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods. On October 27, 2016, ONRR filed a proof of claim with the Bankruptcy Court asserting approximately $35.1 million in claims attributable to the Company’s royalty calculations. The Company is not able to determine the likelihood or range of any additional royalties or, if and when assessed, whether such amounts would be material.

Oil Sales Contract

On April 29, 2016, the Company received a letter from counsel to Sunoco Partners Marketing & Terminals L.P. (“SPMT”) asserting that (1) the Company 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. We dispute SPMT’s positions in the letter and its proof of claim. 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. On January 18, 2017, SPMT filed a reply to our objection SPMT’s proof of claim and an answer to our complaint in the adversary proceeding. 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. SPMT is a member of our official committee of unsecured creditors. We anticipate SPMT’s claims will be resolved through our chapter 11 proceedings.

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The Company is a party, with Big West Oil, LLC (“Big West”), to several prepetition contracts (the “Crude Contracts”) for the purchase and sale of crude oil. On April 26, 2016, Big West Oil LLC (“Big West”) and the Company entered into a Temporary Suspension of Contracts and Interim Crude Oil Purchase and Sale Agreement (“Suspension Agreement”), pursuant to which the parties suspended performance under the prepetition contracts. On August 30, 2016, Big West filed a proof of claim with the Bankruptcy Court for $32.6 million. The Company objected to Big West’s proof of claim. On January 20, 2017, Big West and the Company reached an agreement settling and resolving Big West’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to Big West, within six months of our emergence from chapter 11, of $17.35 million to provide Big West with an allowed general unsecured claim against all of the Ultra Entities in that amount and that all of our prepetition contracts with Big West, including the Suspension Agreement, would be rejected (with no additional damages other than the $17.35 million payment) in connection with our plan of reorganization. Additionally, in connection with the settlement, we and Big West agreed to enter into two new,two-year, contracts for the purchase and sale of crude oil we produce in Wyoming and Utah. The settlement with Big West has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization.

Operating Lease

During December 2012, the Company sold its system of pipelines and central gathering facilities (the “Pinedale LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming and entered into a long-term, triple net lease agreement (the “Pinedale Lease Agreement”) relating to the use of the Pinedale LGS. The Pinedale Lease Agreement provides for an initial term of 15 years and potential successive renewal terms of 5 years or 75% of the then remaining useful life of the Pinedale LGS at the sole discretion of the Company. Annual rent for the initial term under the Pinedale Lease Agreement is $20.0 million (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. The Company currently projects that lease payments related to the Pinedale Lease Agreement will total approximately $229.9 million.

All of the Company’s lease obligations are related to leases that are classified as operating leases. These leases contain certain provisions that could result in accelerated lease payments. The Company has considered the effect of these provisions on minimum lease payments in its lease classification analysis and has determined that the default provisions do not impact classification of any the Company’s operating leases.

Office space lease

The Company maintains office space in Colorado, Texas, Wyoming and Utah with total remaining commitments for office leases of $6.6 million at December 31, 2016; ($1.3 million in 2017; $1.2 million in 2018; $1.2 million in 2019; $1.2 million in 2020; and $1.1 million in 2021 with the remainder due beyond five years).

During the years ended December 31, 2016, 2015 and 2014, the Company recognized expense associated with its office leases in the amount of $1.5 million, $1.3 million, and $1.0 million, respectively.

Delivery Commitments

With respect to the Company’s natural gas production, from time to time the Company enters into transactions to deliver specified quantities of gas to its customers. As of February 9, 2017, the Company has long-term natural gas delivery commitments of 2.8 MMMBtu in 2018 under existing agreements. As of February 9, 2017, the Company has long-term crude oil delivery commitments of 1.6 MMBbls in 2017, 1.7 MMBbls in 2018 and 0.3 MMBbls in 2019 under existing agreements. None of these commitments require the Company to deliver gas or oil produced specifically from any of the Company’s properties, and all of these commitments are priced on a floating basis with reference to an index price. In addition, none of the Company’s reserves are subject to any priorities or curtailments that may affect quantities delivered to its customers, any priority allocations or price limitations imposed by federal or state regulatory agencies or any other factors beyond the Company’s control that may affect its ability to meet its contractual obligations other than those discussed in Item 1A. “Risk Factors”. If for some reason our production is not sufficient to satisfy these commitments, subject to the availability of capital, we could purchase volumes in the market or make other arrangements to satisfy the commitments.

Other Claims

The Company is party to a lawsuit related to disputes with respect to overriding royalty interests in certain of our operated leases in Pinedale, Wyoming. At this time, no determination of the outcome of these claims can be made, and as no damage claim amount has been asserted by the claimants, we cannot reasonably estimate the potential impact of these claims. We intend to defend this case vigorously, and expect these claims to be resolved in our chapter 11 proceedings. The Company is 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.

12.    CONCENTRATION OF CREDIT RISK:

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables. The Company’s revenues related to natural gas and oil sales are derived principally from a diverse group of companies, including major energy

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companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries.

Concentrations of credit risk with respect to receivables is limited due to the large number of customers and their dispersion across geographic areas. Commodity-based contracts may expose the Company to the credit risk of nonperformance by the counterparty to these contracts. This credit exposure to the Company is diversified primarily among as many as ten major investment grade institutions and will only be present if the reference price of natural gas established in those contracts is less than the prevailing market price of natural gas, from time to time.

The Company maintains credit policies intended to monitor and mitigate the risk of uncollectible accounts receivable related to the sale of natural gas, condensate as well as its commodity derivative positions. The Company performs a credit analysis of each of its customers and counterparties prior to making any sales to new customers or extending additional credit to existing customers. Based upon this credit analysis, the Company may require a standby letter of credit or a financial guarantee. The Company did not have any outstanding, uncollectible accounts for its natural gas or oil sales, nor derivative settlements at December 31, 2016.

A significant counterparty is defined as one that individually accounts for 10% or more of the Company’s total revenues during the year. In 2016, the Company had one single customer that represented approximately 10% of its total revenues.

13. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to December 31, 2016 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:

• On January 17, 2017, we filed a revised plan of reorganization and disclosure statement therefore. On February 8, 2017, we filed a further revised plan of reorganization and disclosure statement therefore. On February 13, 2017, we filed amendments and further revisions to the plan of reorganization we filed on February 8, 2017 and to the disclosure statement therefore. The Court approved our Disclosure Statement on February 13, 2017 and scheduled a hearing to consider confirmation of the Plan for March 14, 2017. On February 21, 2017, the Court signed an amended order approving our Disclosure Statement. The amended order: (1) approves the adequacy of our Disclosure Statement, (2) approves the solicitation and notice procedures related to confirmation of our plan of reorganization, (3) approves the forms of ballots and notices related thereto, (4) approves the rights offering procedures and matters related thereto, (5) schedules certain dates related to our plan confirmation process and Rights Offering, and (6) grants related relief. With respect to the Rights Offering, the amended order defines the “Subscription Commencement Date” as February 21, 2017. Accordingly, as will be reflected in the materials to be distributed in connection with the Rights Offering, the Plan Value under the PSA is $6.0 billion.

• On February 8, 2017, the Debtors obtained a commitment letter from Barclays, pursuant to which, in connection with the consummation of the Plan, Barclays has agreed to provide secured and unsecured financing in an aggregate amount of up to $2.4 billion, consisting of (i) a seven-year senior secured first lien term loan credit facility in an aggregate amount of $600.0 million, (ii) a five-year senior secured first lien revolving credit facility in an aggregate amount of $400.0 million and (iii) senior unsecured bridge loans under senior unsecured bridge facilities in an aggregate amount of up to $1.4 billion.

• As of January 19, 2017, the Backstop Approval Order was entered by the Bankruptcy Court and the Commitment Premium was fully earned by the Commitment Parties; the order being entered on January 19, 2017 satisfied one of the milestones in the Backstop Agreement. The Commitment Premium will be paid either in the form of new common stock at the Rights Offering Price, if the Plan is consummated as contemplated in the Plan Support Agreement, or in cash if the Backstop Agreement is terminated other than as a result of a material breach by the Commitment Parties. See Note 1 for further details.

• On April 4, 2016, we received a demand for payment and notice of enforcement from REX in connection with the transportation agreement related to the Rockies Express Pipeline, pursuant to which Rockies Express demanded payment from us of $303.2 million by April 20, 2016. On April 14, 2016, REX filed a lawsuit against us in Harris County, Texas alleging breach of contract and seeking damages related to the alleged breach. On August 26, 2016, REX filed a proof of claim with the Bankruptcy Court for $303.3 million. The Company objected to REX’s proof of claim. On January 12, 2017, REX and the Company entered into a settlement agreement resolving REX’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to REX of $150.0 million six months after the Company emerges from chapter 11, but no later than October 30, 2017, and to provide REX an allowed general unsecured claim under our Plan in that amount. Additionally, in connection with the settlement, we agreed to enter into, with REX, a new seven-year agreement, commencing December 1, 2019, for firm transportation service on the Rockies Express Pipeline, west-to-east, of 200,000 dekatherms per day at a rate of approximately $0.37 per dekatherm, or approximately $26.8 million annually. The settlement with REX has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization.

• The Company is a party, with Big West Oil, LLC (“Big West”), to several prepetition contracts (the “Crude Contracts”) for the purchase and sale of crude oil. On April 26, 2016, Big West Oil LLC (“Big West”) and the Company entered into a Temporary Suspension of Contracts and Interim Crude Oil Purchase and Sale Agreement (“Suspension Agreement”), pursuant to which the parties suspended performance under the prepetition contracts. On August 30, 2016, Big West filed a proof of claim with the

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Bankruptcy Court for $32.6 million. The Company objected to Big West’s proof of claim. On January 20, 2017, Big West and the Company reached an agreement settling and resolving Big West’s proof of claim. Pursuant to the settlement, we agreed to make a cash payment to Big West, within six months of our emergence from chapter 11, of $17.35 million, to provide Big West with an allowed general unsecured claim against all of the Ultra Entities in that amount and that all of our prepetition contracts with Big West, including the Suspension Agreement, would be rejected (with no additional damages other than the $17.35 million payment) in connection with our plan of reorganization. Additionally, in connection with the settlement, we and Big West agreed to enter into two new, two-year, contracts for the purchase and sale of crude oil we produce in Wyoming and Utah. The settlement with Big West has been submitted to the Bankruptcy Court for approval and will be implemented in connection with the plan of reorganization.

14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

	2016
	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter			Total
Operating revenues	$	159,386		$	146,591		$	199,253		$	215,861		$	721,091
Operating expenses		126,868			94,746			99,788			99,313			420,715
Other income (expense), net:
Interest expense (excludes contractual interest    expense of $141.5 million for the year ended    December 31, 2016)		(49,903	)		(16,662	)		—			—			(66,565	)
Restructuring expenses		(5,579	)		(1,569	)		(28	)		—			(7,176	)
Contract settlement		—			—			—			(131,106	)		(131,106	)
Other income (expense), net		943			2,411			2,124			1,993			7,471
Total other (expense) income, net		(54,539	)		(15,820	)		2,096			(129,113	)		(197,376	)
Reorganization items, net		—			(22,183	)		(3,109	)		(22,211	)		(47,503	)
Income before income tax (benefit) provision		(22,021	)		13,842			98,452			(34,776	)		55,497
Income tax (benefit) provision		(190	)		(160	)		45			(349	)		(654	)
Net (loss) income	$	(21,831	)	$	14,002		$	98,407		$	(34,427	)	$	56,151
Net income (loss) per common share — basic	$	(0.14	)	$	0.09		$	0.64		$	(0.22	)	$	0.37
Net income (loss) per common share — fully diluted	$	(0.14	)	$	0.09		$	0.64		$	(0.22	)	$	0.36

	2015
	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter			Total
Operating revenues	$	219,309		$	207,998		$	222,503		$	189,301		$	839,111
Gain (loss) on commodity derivatives		36,865			(3,646	)		9,390			2			42,611
Operating expenses		189,347			188,483			195,339			207,452			780,621
Ceiling test and other impairments		—			—			—			3,144,899			3,144,899
Interest expense		(42,668	)		(42,619	)		(43,137	)		(43,494	)		(171,918	)
Other income (expense), net		(992	)		1,827			2,354			903			4,092
Income before income tax provision		23,167			(24,923	)		(4,229	)		(3,205,639	)		(3,211,624	)
Income tax provision		(2,022	)		(250	)		(1,133	)		(999	)		(4,404	)
Net income	$	25,189		$	(24,673	)	$	(3,096	)	$	(3,204,640	)	$	(3,207,220	)
Net income per common share — basic	$	0.16		$	(0.16	)	$	(0.02	)	$	(20.91	)	$	(20.94	)
Net income per common share — fully diluted	$	0.16		$	(0.16	)	$	(0.02	)	$	(20.91	)	$	(20.94	)

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15. DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):

The following information about the Company’s oil and natural gas producing activities is presented in accordance with FASB ASC Topic 932, Oil and Gas Reserve Estimation and Disclosures:

A.     OIL AND GAS RESERVES:

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and GAAP. The Vice President — Development is primarily responsible for overseeing the preparation of the Company’s reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, a Masters of Business Administration and is a licensed Professional Engineer with over 15 years of experience. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

The estimates of proved reserves and future net revenue as of December 31, 2016, are based upon the use of technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The reserves were estimated using deterministic methods; these estimates were prepared in accordance with generally accepted petroleum engineering and evaluation principles. Standard engineering and geoscience methods, such as reservoir modeling, performance analysis, volumetric analysis and analogy, that were considered to be appropriate and necessary to establish reserve quantities and reserve categorization that conform to SEC definitions and rules and regulations, were also used. As in all aspects of oil and natural gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, these estimates necessarily represent only informed professional judgment.

The determination of oil and natural gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. From time to time, the Company may adjust the inventory and schedule of its proved undeveloped locations in response to changes in capital budget, economics, new opportunities in the portfolio or resource availability. The Company has not scheduled any proved undeveloped reserves beyond five years nor does it have any proved undeveloped locations that have been part of its inventory of proved undeveloped locations for over five years.

The Company engaged Netherland, Sewell & Associates, Inc. (“NSAI”), a third-party, independent engineering firm, to prepare the reserve estimates for all of the Company’s assets for the year ended December 31, 2016, 2015 and 2014 in this annual report. For the year ended December 31, 2013, the Company engaged NSAI to prepare the reserve estimates for all of the Company’s assets in Wyoming and Pennsylvania in this annual report. Due to the timing of the closing of the acquisition in Utah in December 2013 relative to the timing of preparing annual corporate reserves, the Company’s Reservoir Engineering Department prepared the proved reserve estimates for its Utah assets for the year ended December 31, 2013, which were prepared in accordance with the Company’s internal controls and SEC regulations and represented less than 2% of estimated proved reserves as of December 31, 2013.

Our internal professional staff works closely with our independent engineers, NSAI, to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves. The report of NSAI is included as an Exhibit to this annual report.

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Sean A. Martin and Mr. Philip R. Hodgson. Mr. Martin, a Licensed Professional Engineer in the State of Texas (No. 125354), has been practicing consulting petroleum engineering at NSAI since 2014 and has over 7 years of prior industry experience. He graduated from graduated from University of Florida in 2007 with a Bachelor of Science Degree in Chemical Engineering. Mr. Hodgson, a Licensed Professional Geoscientist in the State of Texas (No. 1314), has been practicing consulting petroleum geoscience at NSAI since 1998 and has over 14 years of prior industry experience. He graduated from University of Illinois in 1982 with a Bachelor of Science Degree in Geology and from Purdue University in 1984 with a Master of Science Degree in Geophysics. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Since January 1, 2016, no crude oil, natural gas or NGL reserve information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

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The following unaudited tables as of December 31, 2016, 2015 and 2014 reflect estimated quantities of proved oil and natural gas reserves for the Company and the changes in total proved reserves as of December 31, 2016, 2015 and 2014. All such reserves are located in the Green River Basin in Wyoming, the Uinta Basin in Utah and the Appalachian Basin of Pennsylvania.

B.    ANALYSES OF CHANGES IN PROVEN RESERVES:

	United States
	Oil (MBbls)			Natural Gas (MMcf)			NGLs (MBbls)
Reserves, December 31, 2013		34,119			3,409,742			—
Extensions, discoveries and additions		34,275			866,513			210
Sales		—			(239,290	)		—
Acquisitions		9,381			1,345,964			21,740
Production		(3,409	)		(228,517	)		—
Revisions		(6,600	)		(323,218	)		43
Reserves, December 31, 2014		67,766			4,831,194			21,993
Extensions, discoveries and additions		166			17,415			3
Sales		—			—			—
Acquisitions		—			—			—
Production		(3,533	)		(268,954	)		—
Revisions		(42,224	)		(2,243,375	)		(12,156	)
Reserves, December 31, 2015		22,175			2,336,280			9,840
Extensions, discoveries and additions		3,519			251,634			530
Sales		—			—			—
Acquisitions		—			—			—
Production		(2,912	)		(264,278	)		—
Revisions		(1,307	)		(2,023	)		(467	)
Reserves, December 31, 2016		21,475			2,321,613			9,903

	United States
	Oil (MBbls)		Natural Gas (MMcf)		NGLs (MBbls)
Proved:
Developed		20,566		1,777,267		—
Undeveloped		13,553		1,632,475		—
Total Proved — 2013		34,119		3,409,742		—
Developed		28,481		2,245,004		9,118
Undeveloped		39,285		2,586,190		12,875
Total Proved — 2014		67,766		4,831,194		21,993
Developed		22,175		2,336,280		9,840
Undeveloped		—		—		—
Total Proved — 2015		22,175		2,336,280		9,840
Developed		21,475		2,321,613		9,903
Undeveloped		—		—		—
Total Proved — 2016		21,475		2,321,613		9,903

Changes in proved developed reserves :    During 2016, substantially all of our extensions and discoveries in the proved developed category were attributable to wells drilled in 2016.

Changes in proved undeveloped reserves :    As of December 31, 2016 and 2015, the Company did not include PUD reserves in its total proved reserve estimates due to uncertainty regarding its ability to continue as a going concern and the availability of capital that would be required to develop the PUD reserves.

NGLs :    During 2014, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017. These contracts provide for an annual election to process NGLs, and the Company elected not to process NGLs in 2017.

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Development plan :    The development plan underlying the Company’s proved undeveloped reserves, if any, adopted each year by senior management, is based on the best information available at the time of adoption. As factors such as commodity price, service costs, performance data, and asset mix are subject to change, the Company occasionally revises its development plan. Development plan revisions include deferrals, removals, and substitutions of previously scheduled PUD reserve locations. These occasional changes achieve the purpose of maximizing profitability and are in the best interest of the Company’s shareholders.

In addition, as a part of our internal controls for determining a plan to develop our proved reserves each year, we consider whether we have the financial capability to develop proved undeveloped reserves. This year, because substantial doubt exists about our ability to continue as a going concern, we lack the required degree of certainty that we have the ability to fund a development plan. Therefore, as of December 31, 2016, we did not book any PUD reserves. As of February 22, 2017, the Company has 5 rigs running in the Pinedale field (4 operated, 1 non-operated) and, subject to available capital, intends to continue drilling and completing wells. We expect to report PUD reserves in future filings if we determine that we have the financial capability to execute a development plan.

C.    STANDARDIZED MEASURE:

The following table sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved reserves. Natural gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company’s proved reserves and future net revenues at December 31, 2016, 2015 and 2014 was $2.07, $2.21 and $4.32 per Mcf, respectively, for natural gas, and $37.90, $42.36 and $80.62 per barrel, respectively, for oil and condensate. During 2014, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces beginning in 2017. These contracts provide for an annual election to process NGLs, and the Company elected not to process NGLs in 2017. For 2016 and 2015, the average sales price utilized for purposes of estimating the Company’s proved reserves and future net revenues associated with NGLs was $19.17 and $20.61 per barrel, respectively. The prices utilized in the reserve report are based upon the average of prices in effect on the first day of the month for the preceding twelve month period.

The future production and development costs represent the estimated future expenditures to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expense was computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties and available operating loss carryovers.

	As of December 31,
	2016			2015			2014
Future cash inflows	$	5,812,234		$	6,312,095		$	27,331,391
Future production costs		(2,665,082	)		(3,006,265	)		(8,627,657	)
Future development costs		(355,923	)		(358,848	)		(3,859,385	)
Future income taxes		—			—			(3,898,355	)
Future net cash flows		2,791,229			2,946,982			10,945,994
Discount at 10%		(1,100,283	)		(1,081,333	)		(5,712,511	)
Standardized measure of discounted future net cash flows	$	1,690,946		$	1,865,649		$	5,233,483

The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses.

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D.    SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:

	December 31,
	2016			2015			2014
Standardized measure, beginning	$	1,865,649		$	5,233,483		$	3,187,969
Net revisions of previous quantity estimates		(9,623	)		(2,126,998	)		(603,795	)
Extensions, discoveries and other changes		209,603			15,254			1,787,643
Sales of reserves in place		—			—			(398,506	)
Acquisition of reserves		—			—			2,552,491
Changes in future development costs		11,556			1,618,068			(1,013,652	)
Sales of oil and gas, net of production costs		(454,725	)		(550,879	)		(949,389	)
Net change in prices and production costs		(72,939	)		(6,996,416	)		1,010,052
Development costs incurred during the period that reduce    future development costs		22,523			548,112			342,987
Accretion of discount		186,565			709,736			413,177
Net changes in production rates and other		(67,663	)		1,551,413			(175,419	)
Net change in income taxes		—			1,863,876			(920,075	)
Aggregate changes		(174,703	)		(3,367,834	)		2,045,514
Standardized measure, ending	$	1,690,946		$	1,865,649		$	5,233,483

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and natural gas prices have fluctuated widely.

E.    COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES:

	Years Ended December 31,
	2016		2015		2014
United States
Property Acquisitions:
Unproved	$	983	$	13,845	$	26,106
Proved		—		—		895,179
Exploration*		224,277		18,164		197,664
Development		44,300		461,458		382,984
Total	$	269,560	$	493,467	$	1,501,933

* Exploration costs (as defined in Regulation S-X) includes costs spent on development of unproved reserves in the Pinedale Field.

F.    RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES:

	Years Ended December 31,
	2016			2015			2014
United States
Oil and gas revenue	$	721,091		$	839,111		$	1,230,020
Production expenses		(266,366	)		(288,231	)		(280,631	)
Depletion and depreciation		(125,121	)		(401,200	)		(292,951	)
Ceiling test and other impairments		—			(3,144,899	)		—
Income tax benefit (expense)		83,112			(9,841	)		3,736
Total	$	412,716		$	(3,005,060	)	$	660,174

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G.    CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES:

	December 31,
	2016			2015
Proven Properties:
Acquisition, equipment, exploration, drilling and    environmental costs	$	10,752,642		$	10,480,165
Less: accumulated depletion, depreciation and amortization		(9,742,176	)		(9,629,020	)
		1,010,466			851,145
Unproven Properties:
	$	1,010,466		$	851,145

16. SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the financial statements of Ultra Petroleum Corp. (the “Parent Company”), which are included to provide additional information with respect to the Parent Company’s results of operations, financial position and cash flows on a stand-alone basis:

CONDENSED STATEMENT OF OPERATIONS

	Year Ended December 31,
	2016			2015			2014
General and administrative expense	$	650		$	308		$	261
Other income (expense):
Interest expense (excludes contractual interest expense of    $52.4 million for the year ended December 31, 2016)		(26,590	)		(81,069	)		(42,996	)
Income (loss) from unconsolidated affiliates		157,450			(3,152,078	)		558,634
Guarantee fee income		6,073			23,029			23,045
Other expense		(64,888	)		(1,684	)		(1,324	)
Reorganization items, net		(15,827	)		—			—
Income (loss) before income taxes		55,568			(3,212,110	)		537,098
Income tax benefit		(583	)		(4,890	)		(5,753	)
Net income (loss)	$	56,151		$	(3,207,220	)	$	542,851

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CONDENSED BALANCE SHEET

	December 31, 2016			December 31, 2015
ASSETS
Current Assets:
Cash and cash equivalents	$	3,009		$	523
Accounts receivable from related companies		29,939			64,542
Other current assets		2,100			5,150
Total current assets		35,048			70,215
Other non-current assets		—			24,197
Total assets	$	35,048		$	94,412
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	—		$	1,283,232
Interest payable		—			14,166
Accrued and other current liabilities		47			—
Total current liabilities		47			1,297,398
Advances from unconsolidated affiliates		1,623,414			1,788,951
Total liabilities not subject to compromise		1,623,461			3,086,349
Liabilities subject to compromise		1,339,739			—
Total shareholders’ deficit		(2,928,152	)		(2,991,937	)
Total liabilities and shareholders’ equity	$	35,048		$	94,412

CONDENSED STATEMENT OF CASH FLOWS

	Year Ended December 31,
	2016			2015			2014
Net cash (used in) operating activities	$	(21,309	)	$	(101,277	)	$	(35,818	)
Investing Activities:
Investment in subsidiaries		—			—			(850,000	)
Dividends received		24,089			96,297			52,741
Net cash provided by (used in) investing activities		24,089			96,297			(797,259	)
Financing activities:
Proceeds from issuance of Senior Notes		—			—			850,000
Deferred financing costs		—			6			(13,245	)
Repurchased shares/net share settlements		43			—			(6,471	)
Shares re-issued from treasury		(337	)		4,725			2,936
Net cash (used in) provided by financing activities		(294	)		4,731			833,220
Increase (decrease) in cash during the period		2,486			(249	)		143
Cash and cash equivalents, beginning of period		523			772			629
Cash and cash equivalents, end of period	$	3,009		$	523		$	772

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