Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2019

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

For the transition period from to

Commission file number 001-33614

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

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

116 Inverness Drive East, Suite 400 Englewood, Colorado	80112
(Address of principal executive offices)	(Zip code)

(303) 708-9740

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

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

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

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

Large accelerated filer

☐

Accelerated filer

☑

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ☐ NO ☑

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

The number of shares, without par value, of Ultra Petroleum Corp., outstanding as of October 31, 2019 was 197,840,056.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements	3

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	37

ITEM 4.	Controls and Procedures	39

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	40

ITEM 1A.	Risk Factors	40

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

ITEM 3.	Defaults upon Senior Securities	40

ITEM 4.	Mine Safety Disclosures	40

ITEM 5.	Other Information	40

ITEM 6.	Exhibits	41

	Signatures	43

PART I – FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)

	September 30,			December 31,
	2019			2018
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	3,365		$	17,014
Restricted cash		3,207			2,291
Oil and gas revenue receivable and other receivables, net of allowances $11,266 and $8,350, respectively		52,535			144,390
Derivative assets		41,806			23,374
Other current assets		10,380			27,661
Total current assets		111,293			214,730
Proven oil and gas properties, net, using the full cost method of accounting		1,587,780			1,497,727
Property, plant and equipment, net		10,107			11,635
Long-term right-of-use assets		122,331			—
Other assets		15,047			9,196
Total assets	$	1,846,558		$	1,733,288
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	19,323		$	36,923
Accrued liabilities		49,983			58,574
Capital cost accrual		9,745			15,014
Production taxes payable		73,278			58,365
Current portion of long-term debt		9,750			7,313
Interest payable		23,830			28,672
Lease liabilities		11,723			—
Derivative liabilities		11,507			62,350
Total current liabilities		209,139			267,211
Long-term debt
Credit facility, face value		64,000			104,000
Long-term debt, face value		1,917,843			1,932,722
Add: Premium on exchange transactions, net		214,500			228,096
Less: Unamortized deferred financing costs and discount		(49,056	)		(56,650	)
Total long-term debt, net		2,147,287			2,208,168
Deferred gain on sale of liquids gathering system		—			94,636
Long-term lease liabilities		110,633			—
Other long-term obligations		223,297			211,895
Total liabilities		2,690,356			2,781,910
Commitments and contingencies (Note 12)
Shareholders' equity:
Common stock - As of September 30, 2019, no par value; authorized - unlimited; issued and outstanding - 197,840,056; and as of December 31, 2018, no par value; authorized - 750,000,000; issued and outstanding - 197,383,295		2,140,228			2,137,443
Treasury stock		(49	)		(49	)
Retained loss		(2,983,977	)		(3,186,016	)
Total shareholders' deficit		(843,798	)		(1,048,622	)
Total liabilities and shareholders' equity	$	1,846,558		$	1,733,288

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

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2019			2018			2019			2018
	(In thousands, except per share data)
Revenues:
Natural gas sales	$	117,518		$	156,986		$	489,421		$	479,704
Oil sales		24,465			41,523			75,231			125,974
Other revenues		2,255			5,267			6,451			13,611
Total operating revenues		144,238			203,776			571,103			619,289
Expenses:
Lease operating expenses		17,914			25,817			51,026			71,226
Facility lease expense		6,640			6,875			19,828			19,557
Production taxes		14,726			20,470			61,344			62,623
Gathering fees		19,827			21,810			60,027			69,046
Depletion, depreciation and amortization		49,581			49,672			157,003			151,954
General and administrative		6,595			1,482			21,080			16,233
Other operating expenses, net		10,536			3,422			26,621			4,275
Total operating expenses		125,819			129,548			396,929			394,914
Operating income		18,419			74,228			174,174			224,375
Other income (expense), net:
Interest expense		(32,372	)		(38,382	)		(98,074	)		(111,934	)
Gain (loss) on commodity derivatives		11,938			(21,804	)		19,254			(75,607	)
Deferred gain on sale of liquids gathering system		—			2,638			—			7,915
Other income, net		13,528			1,883			13,771			1,195
Total other (expense) income, net		(6,906	)		(55,665	)		(65,049	)		(178,431	)
Income before income tax (benefit) provision		11,513			18,563			109,125			45,944
Income tax (benefit) provision		—			—			(169	)		442
Net income	$	11,513		$	18,563		$	109,294		$	45,502
Earnings per common share:
Basic	$	0.06		$	0.09		$	0.55		$	0.23
Fully diluted	$	0.06		$	0.09		$	0.55		$	0.23
Weighted average common shares outstanding:
Basic		197,840			197,054			197,581			196,888
Fully diluted		198,604			197,055			197,805			197,288

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

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

(In thousands)

	Common Stock
	Shares			Amount		Retained (Loss) Earnings			Treasury Stock			Total Shareholders' (Deficit) Equity
Balances at January 1, 2019		197,383		$	2,137,443	$	(3,186,016	)	$	(49	)	$	(1,048,622	)
Fair value of employee stock plan grants		—			1,127		—			—			1,127
Net income		—			—		40,674			—			40,674
Initial adoption of ASC 842		—			—		92,818			—			92,818
Balances at March 31, 2019		197,383		$	2,138,570	$	(3,052,524	)	$	(49	)	$	(914,003	)
Stock plan grants		648			—		—			—			—
Net share settlements		(191	)		—		(71	)		—			(71	)
Fair value of employee stock plan grants		—			744		—			—			744
Net income		—			—		57,105			—			57,105
Balances at June 30, 2019		197,840		$	2,139,314	$	(2,995,490	)	$	(49	)	$	(856,225	)
Fair value of employee stock plan grants		—			914		—			—			914
Net income		—			—		11,513			—			11,513
Balances at September 30, 2019		197,840		$	2,140,228	$	(2,983,977	)	$	(49	)	$	(843,798	)

	Common Stock
	Shares			Amount		Retained (Loss) Earnings			Treasury Stock			Total Shareholders' (Deficit) Equity
Balances at January 1, 2018		196,347		$	2,116,018	$	(3,270,605	)	$	(49	)	$	(1,154,636	)
Employee stock plan grants		1,226			—		—			—			—
Net share settlements		(519	)		—		(2,061	)		—			(2,061	)
Fair value of employee stock plan grants		—			10,709		—			—			10,709
Initial adoption of ASC 606		—			—		1,761			—			1,761
Net income		—			—		47,494			—			47,494
Balances at March 31, 2018		197,054		$	2,126,727	$	(3,223,411	)	$	(49	)	$	(1,096,733	)
Fair value of employee stock plan grants		—			2,464		—			—			2,464
Net income (loss)		—			—		(20,555	)		—			(20,555	)
Balances at June 30, 2018		197,054		$	2,129,191	$	(3,243,966	)	$	(49	)	$	(1,114,824	)
Fair value of employee stock plan grants		—			2,149		—			—			2,149
Net income		—			—		18,563			—			18,563
Balances at September 30, 2018		197,054		$	2,131,340	$	(3,225,403	)	$	(49	)	$	(1,094,112	)

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

ULTRA PETROLEUM CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

	For the nine months ended September 30,
	2019			2018
	(In thousands)
Operating activities - cash provided by (used in):
Net income for the period	$	109,294		$	45,502
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		157,003			151,954
Unrealized loss (gain) on commodity derivatives		(75,957	)		72,557
Deferred gain on sale of liquids gathering system		—			(7,915	)
Stock compensation		2,271			11,547
Payable-in-kind (“PIK”) interest payable		10,022			—
Amortization of premium on debt exchange		(31,158	)		—
Amortization of deferred financing costs		9,563			8,333
Inventory write-down		7,461			—
Other		2,550			(1,046	)
Net changes in operating assets and liabilities:
Accounts receivable		88,939			12,057
Other current assets		3,388			(2,743	)
Other non-current assets		89			368
Accounts payable		(13,341	)		(14,396	)
Accrued liabilities		(7,870	)		(6,439	)
Production taxes payable		14,913			21,192
Interest payable		(4,869	)		17,414
Other long-term obligations		(1,247	)		(8,118	)
Income taxes payable/receivable		6,431			6,844
Net cash provided by operating activities		277,482			307,111
Investing Activities - cash provided by (used in):
Oil and gas property expenditures		(233,103	)		(339,918	)
Change in capital cost accrual and accounts payable		(10,251	)		(31,703	)
Proceeds from sale of oil and gas properties		—			65,811
Proceeds from sale of capital assets		—			2,872
Purchase of capital assets		(475	)		(4,612	)
Net cash used in investing activities		(243,829	)		(307,550	)
Financing activities - cash provided by (used in):
Borrowings under Credit Agreement		561,000			632,000
Payments under Credit Agreement		(601,000	)		(632,000	)
Payments under Term Loan		(4,875	)		—
Deferred financing costs		(1,440	)		(638	)
Tax withholding on shares settled		(71	)		(2,061	)
Net cash used in financing activities		(46,386	)		(2,699	)
(Decrease) increase in cash during the period		(12,733	)		(3,138	)
Cash, cash equivalents, and restricted cash, beginning of period		19,305			18,269
Cash, cash equivalents and restricted cash, end of period	$	6,572		$	15,131

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

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

All dollar amounts in this Quarterly Report on Form 10-Q are expressed in U.S. dollars unless otherwise noted.

DESCRIPTION OF THE BUSINESS:

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively the “Company”, “Ultra”, “our”, “we”, or “us”) is an independent oil and gas company engaged in the operation and production, development and exploration, and acquisition of oil and natural gas properties. Ultra Petroleum Corp. is incorporated under the laws of Yukon, Canada. The Company’s principal business activities are operating and developing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of southwest Wyoming.

1. SIGNIFICANT ACCOUNTING POLICIES:

Basis of Presentation: The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

The condensed consolidated balance sheet at December 31, 2018, has been derived from the audited consolidated financial statements at that date, but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. For further information, refer to the consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

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

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

Recently Adopted Accounting Pronouncements:

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), and has subsequently issued several supplemental and/or clarifying ASUs (collectively known as “ASC 842”). The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of more than 12 months. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative information. The Company adopted ASC 842 and applicable amendments on January 1, 2019, using the modified retrospective approach. The Company elected certain practical expedients and established internal controls and key system functionality to enable the preparation of financial information on adoption.

The adoption of the standard had an effect on the Company’s condensed consolidated balance sheets and condensed consolidated statement of operations. The most significant impact was the recognition of ROU assets and lease liabilities for operating leases, while accounting for finance leases remained substantially unchanged. Please refer to Note 11 for additional discussion.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Cumulative Effect of Recently Adopted Accounting Pronouncements:

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

	December 31, 2018 as reported			Impact of ASC 842			January 1, 2019 as adjusted
	(In thousands)
Long-term right-of-use assets	$	—		$	130,649		$	130,649
Total assets		1,733,288			130,649			1,863,937

Lease liabilities (current)		—			11,141			11,141
Deferred gain on sale of liquids gathering system		94,636			(94,636	)		—
Long-term lease liabilities		—			121,326			121,326
Total liabilities		2,781,910			37,831			2,819,741
Retained earnings (loss)		(3,186,016	)		92,818			(3,093,198	)
Total shareholders' equity (deficit)		(1,048,622	)		92,818			(955,804	)
Total liabilities and shareholders' equity (deficit)		1,733,288			130,649			1,863,937

Recent Accounting Pronouncements Not Yet Adopted:

Fair Value Measurements. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurements (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. ASU 2018-13 is effective for public companies for fiscal years beginning after December 15, 2019, and interim periods therein. The Company is currently assessing the impact of this standard on its consolidated financial statements.

Financial Instruments. In June 2016, The FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). This ASU changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. ASU 2016-13 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2019. The Company is currently assessing the impact of ASU 2016-13 on its consolidated financial statements.

2. REVENUE RECOGNITION:

Revenue from Contracts with Customers

Sales of oil and natural gas are recognized at the point when title and custody (“control”) of the product is transferred to the customer, collectability is reasonably assured, and the performance obligations are satisfied. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering line or a transmission line, the quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price we receive for our produced oil and natural gas fluctuates to remain competitive with other available oil and natural gas supplies.

Natural gas sales

We sell natural gas production at the tailgate of the processing plant or at a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect either (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue at the net price received when control transfers to the purchaser at the tailgate of the processing plant or at the agreed-upon delivery point. For these contracts, we have concluded that the Company is the principal for our net revenue interest share of the volumes being sold. Gathering fees are incurred prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the Condensed Consolidated Statement of Operations.

Our working interest partners are considered the principal for their working interest shares. They have the option to take their gas volumes in kind. The Company may act as an agent and market the other partners’ share of the natural gas production from wells

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

we operate. If it does so, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production.

Oil sales

We sell oil production at either (a) a lease automatic custody transfer meter, (b) a tank battery, or (c) a delivery point downstream, as specified in the contracts with our customers. The production is sold at set volumes and we collect either (i) an agreed upon index price, (ii) a specific index price adjusted for pricing differentials, or (iii) a set price. We recognize revenue at the point when the customer takes control of the product. For these contracts, we have concluded that the Company is the principal for its net revenue interest share of the volumes being sold. Gathering fees are performed prior to the customer taking control of the product, are not considered to be promised services, and are not included in the transaction price; thus, they are presented as expenses in the condensed consolidated statement of operations.

Our working interest partners are considered the principal for their working interest shares. They have the option to take their oil volumes in kind. The Company acts as an agent and markets the other partners’ share of almost all oil production from wells we operate. In these situations, the Company is considered the agent and revenue is recorded at the Company’s net revenue interest in the production.

Other revenues

Our other revenue is comprised of fees paid to us by the operators of the gas processing plants where our gas is processed. Control is transferred upon completion of the processing service. The Company is considered the principal, and revenue is recognized at the point in time that the control is transferred.

Transaction price allocated to remaining performance obligations

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

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

Contract balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

We record revenue in the month when control is transferred to the purchaser and all contractual obligations are satisfied. However, settlement statements for certain natural gas sales may not be received for 30 to 90 days after the date production is delivered. Consequently, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have been insignificant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the three and nine months ended September 30, 2019.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

3. OTHER CURRENT ASSETS:

The following table summarizes the major components of Other current assets included on the condensed consolidated balance sheet:

	September 30,		December 31,
	2019		2018
Deposits and retainers	$	651	$	651
Prepaids and others		859		1,822
Income tax receivable		—		6,431
Crude oil		1,041		1,113
Pipe and production equipment		7,829		17,644
Total Other current assets	$	10,380	$	27,661

During the quarter ended September 30, 2019, the Company recorded a write-down of pipe and production inventory to the lower of cost or net realizable value. Our inventories are valued at the lower of cost or net realizable value, with cost determined using either the weighted-average cost, including the cost of transportation and storage, and with net realizable value defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of transportation. Accordingly, the Company recorded a write-down of pipe and production equipment for $7.5 million. The expense is reported as Other operating expenses on the condensed consolidated statement of operations. The pipe and production equipment and crude oil inventory has been reclassified to Other current assets as of September 30, 2019 and December 31, 2018.

4. OIL AND GAS PROPERTIES:

	September 30,			December 31,
	2019			2018
	(In thousands)
Proven properties, subject to depletion:
Acquisition, equipment, exploration, drilling and abandonment costs	$	11,812,369		$	11,577,281
Less: Accumulated depletion, depreciation and amortization		(10,224,589	)		(10,079,554	)
Total Oil and gas properties, net	$	1,587,780		$	1,497,727

5. EARNINGS PER SHARE:

Basic earnings per share is computed by dividing net earnings attributable to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of common stock equivalents. The Company uses the treasury stock method to determine the dilutive effect.

Certain share-based payments subject to performance or market conditions are considered contingently issuable shares for purposes of calculating diluted earnings per share. Thus, they are excluded from the diluted earnings per share denominator until the performance or market conditions are met. Additionally, warrants are excluded from the diluted earnings per share denominator until the date on which the volume-weighted average price of the Common Shares is at least $2.50 per Common Share for 30 consecutive trading days. For further information on the warrants, refer to the consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
	(In thousands, except per share data)
Net income	$	11,513	$	18,563	$	109,294	$	45,502
Weighted average common shares outstanding - basic		197,840		197,054		197,581		196,888
Effect of dilutive instruments		764		1		224		400
Weighted average common shares outstanding - fully diluted		198,604		197,055		197,805		197,288

Basic	$	0.06	$	0.09	$	0.55	$	0.23

Fully diluted	$	0.06	$	0.09	$	0.55	$	0.23
Number of contingently issuable shares that are excluded from the diluted earnings per share denominator as the performance or market criteria have not been met		20,547		4,895		20,302		2,547

6. LONG TERM DEBT:

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

	September 30, 2019
	Principal repayment obligation (1)			Unamortized DFC and discounts (2)			Unamortized premium		Carrying value
	(In thousands)
Credit Facility, secured, due January 2022	$	64,000		$	—		$	—	$	64,000
Term Loan, secured, due April 2024		971,194			(23,620	)		—		947,574
Second Lien Notes, secured, due July 2024		580,960			—			214,500		795,460
6.875% Notes, unsecured, due April 2022		150,439			(12,187	)		—		138,252
7.125% Notes, unsecured, due April 2025		225,000			(13,249	)		—		211,751
Total debt	$	1,991,593		$	(49,056	)	$	214,500	$	2,157,037
Less: Current maturities		(9,750	)		—			—		(9,750	)
Total long-term debt, net	$	1,981,843		$	(49,056	)	$	214,500	$	2,147,287

(1)	Includes PIK interest on the Term Loan and Second Lien Notes of $1.1 million and $8.9 million, respectively.

(2)	Deferred financing costs related to the Revolving Credit Facility are reported within Other assets on the condensed consolidated balance sheet, rather than as a reduction of the carrying amount of long-term debt.

	December 31, 2018
	Principal repayment obligation			Unamortized DFC and discounts (1)			Unamortized premium		Carrying value
	(In thousands)
Credit Facility, secured, due January 2022	$	104,000		$	—		$	—	$	104,000
Term Loan, secured, due April 2024		975,000			(26,874	)		—		948,126
Second Lien Notes, secured, due July 2024		545,000			—			228,096		773,096
6.875% Notes, unsecured, due April 2022		195,035			(15,168	)		—		179,867
7.125% Notes, unsecured, due April 2025		225,000			(14,608	)		—		210,392
Total debt	$	2,044,035		$	(56,650	)	$	228,096	$	2,215,481
Less: Current maturities		(7,313	)		—			—		(7,313	)
Total long-term debt, net	$	2,036,722		$	(56,650	)	$	228,096	$	2,208,168

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(1)	Deferred financing costs related to the Revolving Credit Facility are reported within Other assets on the condensed consolidated balance sheet, rather than as a reduction of the carrying amount of long-term debt.

Credit Agreement. Ultra Resources Inc., a Delaware corporation and wholly-owned subsidiary of the Company, (“Ultra Resources”) entered into a Credit Agreement (as amended, the “Credit Agreement”) as the borrower with the Company and UP Energy Corporation, as parent guarantors, with Bank of Montreal, as administrative agent (the “RBL Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “RBL Lenders”), providing for a revolving credit facility (the “Revolving Credit Facility”) subject to a borrowing base redetermination, which limits the aggregate amount of first lien debt under the Revolving Credit Facility and Term Loan Agreement (as defined below).

On September 16, 2019, Ultra Resources entered into a Fifth Amendment to the Credit Agreement (the “Fifth Amendment”) with the Agent and the Lenders party thereto. Pursuant to the Fifth Amendment and the fall borrowing base redetermination, the Borrowing Base (as defined in the Credit Agreement) was reduced to $1.175 billion, with $200 million attributed to the Credit Agreement. The $200 million commitment for the Credit Facility automatically reduces to $120 million on February 29, 2020. As of September 30, 2019, Ultra Resources had $64.0 million of outstanding borrowings under the Revolving Credit Facility, with total commitments of $200.0 million. Availability under the Revolving Credit Facility is the undrawn portion of the commitment of $136.0 million plus the unrestricted cash of Ultra Resources, which was $3.0 million, for a total availability of $139.0 million as of September 30, 2019.

The Fifth Amendment also provides for, among other items, the following changes to certain covenants and other provisions of the Credit Agreement:

•

elimination of all financial maintenance covenants;

•

reduction to the Company’s minimum hedging requirements on projected natural gas volumes to 50% through March 31, 2020, and removal of any minimum hedging requirements thereafter;

•

establishment of maximum capital expenditures of $65 million, $10 million and $5 million, for the quarters ended September 30, 2019, December 31, 2019, and quarterly thereafter, with the ability to carryforward unused amounts up to $5 million in aggregate;

•

revision of the anti-cash hoarding provision from $100 million to $25 million at all times borrowings are outstanding under the Revolving Credit Facility; and

•

ability to repurchase indebtedness, including borrowings under the Company’s Senior Secured Term Loan, Senior Secured Second Lien Notes, 6.875% Senior Notes due 2022 and 7.125% Senior Notes due 2025 under certain circumstances, including having no amounts drawn on the Revolving Credit Facility, the Company having established adequate cash reserves, satisfaction of a first lien incurrence test, each as set forth in the Fifth Amendment, and compliance with the Company’s other debt documents. Of note, the Term Loan and the Second Lien Notes have prohibitions against the use of cash to repurchase debt. Therefore, in order for the Company to utilize this provision provided by the Credit Agreement, the Company would have to receive additional approval from both the Term Loan Lenders (defined below) and the Second Lien noteholders.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The next scheduled semi-annual borrowing base redetermination is in the spring of 2020. To the extent the Borrowing Base is reduced to an amount that is less than the outstanding borrowings under the Term Loan Agreement (as defined below), then commitments under the Revolving Credit Facility would be reduced to zero and Ultra Resources would become subject to additional coverage tests under the Term Loan Agreement. Among these new requirements is an asset coverage test and, if not satisfied, the Company would be required to make mandatory prepayments to the Term Loan Lenders (as defined below) in order to cure any deficiency. Failure to make such required payments would result in an Event of Default under the Term Loan Agreement.

The Revolving Credit Facility has $35.0 million of the commitments available for the issuance of letters of credit. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. The applicable margin is increased by 25 basis points in the event the Company’s consolidated net leverage ratio, as defined, exceeds 4.00 to 1.00. Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees. The Revolving Credit Facility loans mature on January 12, 2022.

As noted above, the Fifth Amendment established a maximum capital expenditure, as defined, of $65 million, $10 million, and $5 million, for the quarters ended September 30, 2019, December 31, 2019, and quarterly thereafter, with the ability to carryforward unused amounts up to $5 million in aggregate. Per the definition of maximum capital expenditures in the Fifth Amendment, the Company expended $53.7 million in the quarter ended September 30, 2019.

The Revolving Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At September 30, 2019, Ultra Resources was in compliance with all of its debt covenants under the Revolving Credit Facility.

Under the Revolving Credit Facility, the Company is subject to minimum hedging requirements. During the quarterly period beginning on September 30, 2019 and ending on March 30, 2020, the Company is required to hedge a minimum of 50% of projected proved developed producing natural gas reserve volumes projected to be produced in the specified quarter. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.

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

Term Loan. Ultra Resources entered into a Term Loan Agreement (as amended, the “Term Loan Agreement”) as the borrower with the Company and UP Energy Corporation, as parent guarantors, with Barclays, as administrative agent (the “Term Loan Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “Term Loan Lenders”) providing for a term loan credit facility (the “Term Loan Credit Facility”). As of September 30, 2019, Ultra Resources had a balance of approximately $971.2 million in borrowings, including $1.1 million of PIK interest, and current maturities under the Term Loan Credit Facility.

In December 2018, Ultra Resources and the parent guarantors entered into the First Amendment to the Term Loan Agreement (the “Term Loan Amendment”) with the Term Loan Administrative Agent and the Term Loan Lenders party thereto. Pursuant to the Term Loan Amendment, the parties agreed, among other things, to amend the Term Loan Agreement to permit the issuance of the Second Lien Notes and the December Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payable in cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to:

•

introducing call protection of 102% until December 21, 2019 and 101% until December 21, 2020;

•

introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility as more thoroughly described in the Term Loan Amendment;

•

deleting the ability to increase commitments under the Term Loan;

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

•

increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement);

•

removing the ability to create, invest in and utilize unrestricted subsidiaries;

•

further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Term Loan Amendment; and

•

providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term Loan Amendment.

Borrowings under the Term Loan Agreement bear interest at a rate equal to either (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable-in-kind (“PIK”) solely upon election by Ultra Resources. During 2019, the Company has elected the PIK option for several of its selected interest payments. Recently, the Company has elected not to utilize this PIK option. Beginning in June 2019, the borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the initial aggregate principal amount. Remaining borrowings under the Term Loan Agreement mature on April 12, 2024.

Borrowings under the Term Loan Agreement are subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain conditions including a situation in which the Revolving Credit Facility no longer exists, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments equal to six monthly payments are required in order to attain compliance, with such amounts being applied to prepay the borrowings under the Term Loan Agreement.

The Term Loan Agreement also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), delivery of quarterly and annual financial statements and oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. At September 30, 2019, Ultra Resources was in compliance with all of its debt covenants under the Term Loan Agreement.

The Term Loan Agreement contains customary events of default and remedies for credit facilities of this nature. If Ultra Resources does not comply with the financial and other covenants in the Term Loan Agreement, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Term Loan Agreement.

Second Lien Notes. As of September 30, 2019, Ultra Resources had approximately $581.0 million, including $8.9 million of PIK interest, in outstanding borrowings of Senior Secured Second Lien Notes (the “Second Lien Notes”) pursuant to the Indenture, dated December 21, 2018 (the “Second Lien Notes Indenture”), with Ultra Resources, as issuer, the Company and its other subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral agent (the “Trustee”).

Interest on the Second Lien Notes accrues at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The cash interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing in July 2019. The Company has accounted for such PIK interest as an increase to the principal outstanding. The Second Lien Notes will mature on July 12, 2024.

The Second Lien Notes are senior secured obligations of Ultra Resources and rank senior in right of payment to all of its existing and future unsecured senior debt, to the extent of the value of the collateral pledged under the Second Lien Notes Indenture and related collateral arrangements, senior in right of payment to all of its future subordinated debt, and junior in right of payment to all of its existing and future secured debt of senior priority, to the extent of the value of the collateral pledged thereby. The Second Lien Notes are secured by second priority security interests in substantially all assets of the Company. Payment by Ultra Resources of all amounts due on or in respect of the Second Lien Notes and the performance of Ultra Resources under the Indenture are initially guaranteed by the Company.

If Ultra Resources experiences certain change of control triggering events set forth in the Second Lien Notes Indenture, each holder of the Second Lien Notes may require Ultra Resources to repurchase all or a portion of its Second Lien Notes for cash at a price

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

equal to 101% of the aggregate principal amount of such Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase.

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

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

The 2022 Notes will mature on April 15, 2022. Interest on the 2022 Notes accrues at an annual rate of 6.875% and interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. Interest on the 2025 Notes accrues at an annual rate of 7.125% and interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity. Refer to Note 6 Long Term Debt in the 2018 Form 10-K for additional details on the terms of the Unsecured Notes.

7. SHARE BASED COMPENSATION:

Valuation and Expense Information

	For the Three Months				For the Nine Months Ended
	Ended September 30,				Ended September 30,
	2019		2018		2019		2018
	(In thousands)
Total cost of share-based payment plans	$	914	$	2,148	$	2,785	$	15,321
Amounts capitalized in oil and gas properties and equipment	$	164	$	724	$	514	$	3,774
Amounts charged against income, before income tax benefit	$	750	$	1,424	$	2,271	$	11,547
Amount of related income tax benefit recognized in income before valuation allowance	$	158	$	299	$	477	$	2,425

Performance Share Plans:

2017 Stock Incentive Plan. In April 2017, the Ultra Petroleum Corp. 2017 Stock Incentive Plan (“2017 Stock Incentive Plan”) was established by our board of directors (the “Board”) pursuant to which 7.5% of the equity in the Company (on a fully-diluted/fully-distributed basis) is reserved for grants to be made from time to time to the directors, officers, employees, and consultants of the Company (the “Reserve”). During 2017, management incentive plan grants (the “Initial MIP Grants”) were made to members of the Board, officers, and other employees of the Company subject to the conditions and performance requirements provided in the grants, including the limitations that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds $6.0 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, that one-third of the Initial MIP Grants will vest, if at all, at such time when the total enterprise value of the Company equals or exceeds 110% or $6.6 billion based upon the volume weighted average price of the common stock during a consecutive 30-day period, and, that if any Initial MIP Grants do not vest before April 12, 2023, such Initial MIP Grants shall automatically expire. The balance of the Reserve is available to be granted by the Board from time to time.

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

•

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

•

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

•

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

•

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

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

•

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

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

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

Long Term Incentive Awards. In 2018 and March 2019, the Board approved long-term incentive awards under the A&R Stock Incentive Plan in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. The awards cover a performance period of three years and include time-based and performance-based measures established by the Board at the beginning of the three-year period.

Stock-Based Compensation Cost:

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

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

Expense. For the nine months ended September 30, 2019, the Company recognized $2.3 million in pre-tax compensation expense, which is included within General and administrative expenses on the condensed consolidated statement of operations. During the nine months ended September 30, 2018, the Company recognized $11.5 million in pre-tax compensation expense, of which $10.9 million related to the Initial MIP Grants.

8. INCOME TAXES:

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

The Company has a valuation allowance recorded against all deferred tax assets as of September 30, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted into law. Further guidance and clarifications continue to be issued regarding the regulations and provisions of the Tax Act. The Company will continue to monitor these new regulations and analyze their applicability and impact on the Company.

9. DERIVATIVE FINANCIAL INSTRUMENTS:

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

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

Under the Revolving Credit Facility, the Company is subject to minimum hedging requirements through March 31, 2020, as described in Note 6. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.

Fair Value of Commodity Derivatives: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC 815”). The Company does not apply hedge accounting to any of its derivative instruments. Instead, in accordance with ASC 815 the derivative contracts are recorded at fair value as derivative assets and liabilities on the condensed consolidated balance sheets and the associated unrealized gains and losses are recorded as current income or expense on the condensed consolidated statements of operations. The Company does not offset the value of its derivative arrangements with the same counterparty. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the Condensed Consolidated Statements of Cash Flows.

Commodity Derivative Contracts: At September 30, 2019, the Company had open commodity derivative contracts to manage commodity price risks as presented in the table below. Subsequent to September 30, 2019, the Company monetized certain derivative contracts and received proceeds for approximately $6.6 million. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty. For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period. For the collars, the Company pays the counterparty if the market price is above the ceiling price and the counterparty pays if the market price is below the floor price on a notional quantity. For deferred premium puts, the Company pays the deferred premium in the month of settlement. To the extent the market price is below the put price, the counterparty owes the Company the difference between the market price and put price in the period of settlement. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties. Refer to Note 10 for more information regarding the fair value of the Company’s derivative instruments.

Type/Year	Index	Total Volumes		Weighted Average Price per Unit			Fair Value Asset (Liability) - September 30, 2019
		(in millions)					(in thousands)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2019 (October through December)	NYMEX-Henry Hub		32.7	$	2.77		$	11,419
2020	NYMEX-Henry Hub		24.6		2.78			5,210

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2019 (October through December)	NW Rockies Basis Swap		29.1	$	(0.48	)	$	(6,469	)
2020	NW Rockies Basis Swap		17.1		(0.17	)		581

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2019 (October through December)	NYMEX-WTI		0.3	$	59.60		$	1,849
2020	NYMEX-WTI		0.5		60.31			3,718

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Type/Year	Index	Total Volumes		Weighted Average Floor Price ($/MMBTU)		Weighted Average Ceiling Price ($/MMBTU)		Fair Value Asset (Liability) - September 30, 2019
		(in millions)						(in thousands)
Natural gas collars		(Mmbtu)
2019 (October through December)	NYMEX		1.4	$	2.90	$	3.15	$	673
2020	NYMEX		76.1	$	2.45	$	2.92	$	12,734
2021	NYMEX		7.2	$	2.46	$	3.05	$	73

Natural gas deferred premium put options (2)		(Mmbtu)
2020	NYMEX		27.9	$	2.41	N/A		$	3,336

(1)

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

(2)

The Natural gas deferred premium put options include an average deferred premium cost of $0.13.

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the condensed consolidated statements of operations for the three and nine months ended September 30, 2019 and 2018:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
Commodity Derivatives:	2019			2018			2019			2018
	(In thousands)
Realized gain (loss) on commodity derivatives - natural gas (1)	$	17,721		$	(5,468	)	$	(59,546	)	$	6,958
Realized gain (loss) on commodity derivatives - oil (1)		787			(5,318	)		2,843			(10,008	)
Unrealized gain (loss) on commodity derivatives (1)		(6,570	)		(11,018	)		75,957			(72,557	)
Total gain (loss) on commodity derivatives	$	11,938		$	(21,804	)	$	19,254		$	(75,607	)

(1)

Included in Gain (Loss) on commodity derivatives in the condensed consolidated statements of operations.

10. FAIR VALUE MEASUREMENTS:

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

Level 1:

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

Level 2:

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

Level 3:

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

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).

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Current derivative asset	$	—	$	41,806	$	—	$	41,806
Long-term derivative asset (1)		—		7,671		—		7,671
Total derivative instruments	$	—	$	49,477	$	—	$	49,477
Liabilities:
Current derivative liability	$	—	$	11,507	$	—	$	11,507
Long-term derivative liability (2)		—		4,846		—		4,846
Total derivative instruments	$	—	$	16,353	$	—	$	16,353

⁽¹⁾

Included in Other assets in the condensed consolidated balance sheet.

⁽²⁾

Included in Other long-term obligations in the condensed consolidated balance sheet.

The Company entered into commodity derivative contracts and as a result, we expose ourselves to counterparty credit risk. Credit risk is the potential failure of the counterparty to perform under the terms of a derivative contract. In order to minimize our credit risk in derivative instruments, we (i) enter into derivative contracts with counterparties that our management has deemed credit worthy as competent and competitive market makers and (ii) routinely monitor and review the credit of our counterparties. In addition, each of our current counterparties are lenders under our Revolving Credit Facility. We believe that all of our counterparties are of substantial credit quality. Other than as provided in our Revolving Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2019, we did not have any past-due receivables from, or payables to, any of the counterparties of our derivative contracts. Refer to Note 9 for additional details on our derivative financial instruments.

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 estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheets for cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The Company uses available market data and valuation methodologies to estimate the fair value of its debt and the fair values presented in the tables below reflect original maturity dates for each of the debt instruments. The valuation assumptions utilized to measure the fair value of the Company’s debt are considered Level 2 inputs. This disclosure is presented in accordance with FASB ASC Topic 825, Financial Instruments, and does not impact the Company’s consolidated financial position, results of operations or cash flows.

	September 30, 2019				December 31, 2018
	Principal		Estimated		Principal		Estimated
	repayment obligation		Fair Value		repayment obligation		Fair Value
	(In thousands)
Credit Facility, secured, due January 2022	$	64,000	$	64,000	$	104,000	$	104,000
Term Loan, secured, due April 2024		971,194		665,268		975,000		858,000
Second Lien Notes, secured, due July 2024		580,960		109,685		545,000		395,125
6.875% Notes, unsecured, due April 2022		150,439		11,095		195,035		68,262
7.125% Notes, unsecured, due April 2025		225,000		18,000		225,000		69,750
Total debt	$	1,991,593	$	868,048	$	2,044,035	$	1,495,137

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

11. LEASES:

The Company adopted ASU 2016-02, Leases (Topic 842), and all applicable amendments as of January 1, 2019. The Company elected to apply the new standard to all leases existing at the date of initial application. Consequently, historical financial information will not be updated, and the disclosures required under the new standard will be provided only for periods beginning January 1, 2019.

The Company determines if an arrangement is a lease at inception. Operating leases are included in long-term right-of-use (“ROU”) assets, and long-term lease liabilities on our condensed consolidated balance sheets. ROU assets represent the Company’s right to use of an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives. The Company’s lease terms may include options to extend or terminate the lease when the Company is reasonably certain that it will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The ROU assets are tested for impairment in accordance with ASC 360.

The Company has lease agreements with lease and non-lease components, which are accounted for as a single lease component under the practical expedient provisions of the standard. Additionally, for certain leases, the Company applies a portfolio approach to effectively account for the operating lease ROU assets and liabilities. The portfolio approach was used to assess and determine the incremental borrowing rate with information available at adoption date.

The Company has lease agreements with terms less than one year. For the qualifying short-term leases, the Company elected the short-term lease recognition exemption in which the Company will not recognize ROU assets or lease liabilities, including the ROU assets or lease liabilities for existing short-term leases of those assets in upon adoption.

As of the adoption date, the Company had existing lease agreements with easements in which the Company elected the practical expedient. All new and modified lease agreements with easements completed after the adoption date will be evaluated under the ASC 842.

The Company has operating leases for corporate offices, the Company’s liquids gathering system, and certain equipment. The leases have remaining lease terms of one year to nine years. The Company does not include renewal options in the lease term for calculating the lease liability unless it is reasonably certain that it will exercise the option or the lessor has the sole ability to exercise the option.

The following table summarizes the components of lease cost:

	For the Three Months Ended		For the Nine Months Ended
	September 30, 2019		September 30, 2019
	(In thousands)
Operating lease cost	$	5,221	$	15,697
Variable lease cost (1)	$	1,834	$	4,875
Short-term lease cost (2)	$	133	$	15,200
Total lease cost (3)	$	7,188	$	35,772

(1)

Variable lease payments include additional payments made that were not included in the initial measurement of the ROU asset and corresponding lease liability for agreements with terms longer than 12 months. Variable lease payments relate to the actual volumes transported under certain agreements, and variable utility costs associated with the Company’s leased office space. Fluctuations in variable lease payments are driven by actual volumes under long-term agreements.

(2)

Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than one year. This amount includes drilling activities, most of which are contracted for 12 months or less. It is expected this amount will fluctuate primarily with the number of drilling rigs the Company is operating under short-term agreements. Additionally, this balance for the nine months ended September 30, 2019 includes approximately $2.0 million of rig demobilization costs and early termination costs. Drilling contracts that were on a month-to-month basis are excluded from this amount.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(3)

Lease costs are either expensed on the accompanying statements of operations or capitalized on the accompanying balance sheets depending on the nature and use of the underlying ROU asset.

The following table provides supplemental balance sheet information related to the Company’s operating leases:

	September 30, 2019
	(In thousands)
Operating Leases
Operating lease right-of-use assets	$	122,331

Operating lease liabilities	$	11,723
Long-term operating lease liabilities		110,633
Total operating lease liabilities	$	122,356

Weighted Average Remaining Lease Term
Operating leases	8.1 years
Weighted Average Discount Rate
Operating leases		7.91	%

The following table provides supplemental cash flow information related to the Company’s operating leases:

	Nine Months Ended
	September 30, 2019
	(In thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	15,671

The following table summarizes the fixed, future minimum rental payments, excluding variable costs, which are discounted by the Company’s incremental borrowing rates to calculate the lease liabilities for the Company’s operating leases:

	Operating Leases
	(In thousands)
For the year ending December 31,
2019 (remaining)	$	5,216
2020		20,853
2021		20,750
2022		20,327
2023		19,719
Thereafter		78,239
Total lease payments	$	165,104
Less: imputed interest		(42,748	)
Total	$	122,356

12. COMMITMENTS AND CONTINGENCIES:

Litigation Matters

Pending Claims – Ultra Resources Indebtedness

On April 29, 2016, the Company and its subsidiaries filed voluntary petitions under chapter 11 of title 11 of the U.S. Code in the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). Our chapter 11 cases were jointly administered under the caption In re Ultra Petroleum Corp., et al, Case No. 16-32202 (MI) (Bankr. S.D. Tex.). On March 14, 2017, the Bankruptcy Court confirmed our Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (the “Plan”) and on April 12, 2017, we emerged from bankruptcy.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

Our chapter 11 filings constituted events of default under Ultra Resources’ prepetition debt agreements. During our bankruptcy proceedings, many holders of this indebtedness filed proofs of claim with the Bankruptcy Court, asserting claims for the outstanding balance of the indebtedness, unpaid prepetition interest, unpaid postpetition interest (including interest at the default rates under the prepetition debt agreements), make-whole amounts, and other fees and obligations allegedly arising under the prepetition debt agreements. As previously disclosed, in connection with our emergence from bankruptcy and in accordance with the Plan, all of our obligations with respect to Ultra Resources prepetition indebtedness and the associated debt agreements were cancelled, except to the limited extent expressly set forth in the Plan, and the holders of claims related to the indebtedness received payment in full of allowed claims (including with respect to outstanding principal, unpaid prepetition interest, and certain other prepetition fees and obligations arising under the debt agreements). In connection with the confirmation and consummation of the Plan, we entered into a stipulation with the claimants pursuant to which we agreed to establish and fund a $400.0 million reserve account after the Company’s emergence from bankruptcy, pending resolution of make-whole and postpetition interest claims. On April 14, 2017, we funded the account. Following our emergence from bankruptcy, we continued to dispute the claims made by holders of the Ultra Resources’ indebtedness for certain make-whole amounts and postpetition interest at the default rates provided for in the debt agreements.

On September 22, 2017, the Bankruptcy Court denied the Company’s objection to the pending make-whole and postpetition interest claims. On October 6, 2017, the Bankruptcy Court entered an order requiring the Company to distribute amounts attributable to the disputed claims to the applicable parties. Pursuant to the order, on October 12, 2017, the Company distributed $399.0 million from the reserve fund to the parties asserting the make-whole and postpetition interest claims and $1.3 million (the balance remaining after distributions to the parties asserting claims) was returned to the Company. The disbursement of $399.0 million was comprised of $223.8 million representing the fees owed under the make-whole claims and $175.2 million representing postpetition interest at the default rate. The Company appealed the court order denying its objections to these claims to the U.S. Court of Appeals for the Fifth Circuit (the “Appellate Court”).

During the fourth quarter of 2018, the Company entered into settlement agreements (collectively, the “Settlement Agreements”) with holders of certain claims related to Ultra Resources’ prepetition indebtedness (the “Claimants”) pursuant to which the parties agreed to settle the pending disputes between the Claimants and the Company. Under the terms of the Settlement Agreements, the Claimants collectively agreed to pay approximately $16.4 million to the Company.

On January 17, 2019, the Appellate Court issued an opinion vacating the order of the Bankruptcy Court that had denied the Company’s objection to the asserted make-whole and post-petition interest claims and remanding the matter and those determinations to the Bankruptcy Court for further reconsideration. On January 31, 2019, the holders of these claims filed a petition for rehearing en banc.

During 2019, the Company entered into additional settlement agreements with holders of certain make-whole and post-petition interest claims. Pursuant to these settlements, the parties agreed to settle the pending disputes between such holders and the Company, and the holders collectively agreed to pay approximately $13.5 million to the Company. As of September 30, 2019, there is approximately $240 million of claims subject to the Appellate Court decision. It is not possible to determine the ultimate disposition of these matters at this time.

Royalties

On April 19, 2016, the Company received a preliminary determination notice from the U.S. Department of the Interior’s Office of Natural Resources Revenue (“ONRR”) asserting that the Company’s allocation of certain processing costs and plant fuel use at certain processing plants were impermissibly charged as deductions in the determination of royalties owed under federal oil and gas leases. ONRR also filed a proof of claim in our bankruptcy proceedings asserting approximately $35.1 million in claims related to these matters. We disputed the preliminary determination and the proof of claim. In September 2019, the Company and ONRR entered into a resolution agreement whereby the Company agreed to pay $12.4 million through installment payments over 60 months, with interest accruing at the applicable federal rate and payable with the final installment payment. This obligation has been recorded to Other operating expense on the condensed consolidated statement of operations for the nine months ended September 30, 2019, and the first installment payment was paid in September 2019. Both the Company and ONRR issued full releases in connection with the audit period. The releases were not an admission of liability as to any of the matters settled.

ULTRA PETROLEUM CORP.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Other Claims

During the nine months ended September 30, 2019, the Company settled and funded a dispute related to a net profits interest in certain of its operated leases in the Pinedale field. This settlement resulted in a payment of $3.5 million. The Company had accrued for this item in prior period. Additionally, the Company settled a separate overriding royalty interest dispute and has recognized an expense of $1.5 million as an estimate of the historical claims during nine months ended September 30, 2019.

We are also party to various disputes with respect to certain overriding royalty and net profits interests in certain of our operated leases in the Pinedale field. At this time, no determination of the outcome of these claims can be made, and we cannot reasonably estimate the potential impact of these claims. We are defending these cases vigorously, and we expect these claims to be resolved in our chapter 11 proceedings. In addition, we are currently involved in various routine disputes and allegations incidental to our business operations. While it is not possible to determine the ultimate disposition of these matters, we believe the Company has adequately reserved for such items where it has been determined that a liability is probable and is reasonably estimable. Additionally, we believe that resolution of all such additional pending or threatened litigation is not likely to have a material adverse effect on our financial position, results of operations, or cash flows.

13. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2019, for material events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

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

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

FORWARD-LOOKING STATEMENTS:

This report contains or incorporates by reference forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995. Except for statements of historical facts, all statements included in this document, including without limitation, statements in Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding the Company’s financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of the Company’s management for future operations, covenant compliance and those statements preceded by, followed by or that otherwise include the words “believe,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions are forward-looking statements. The Company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the Company assure adequate funding will be available to execute the Company’s planned future capital program.

Other risks and uncertainties include, but are not limited to, the Company’s ability to decrease its leverage or fixed costs, increased competition, the timing and extent of changes in prices for oil and gas, particularly in the areas where we own properties, conduct operations, and market our production, as well as the timing and extent of our success in discovering, developing, producing and estimating oil and gas reserves, our ability to successfully monetize the properties we are marketing, weather and government regulation, and the availability of oil field services, personnel and equipment. See the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 for additional risks related to the Company’s business.

OPERATIONS OVERVIEW:

Ultra Petroleum Corp. and its wholly-owned subsidiaries (collectively, the “Company,” “Ultra,” “our,” “we,” or “us”) is an independent exploration and production company focused on developing and producing its long-life natural gas reserves in the Pinedale and Jonah fields of the Green River Basin of southwest Wyoming. The Company operates in one industry segment, natural gas and oil exploration and development, with one geographical segment, the United States.

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

The Company currently generates its revenue, earnings and cash flow from the production and sales of natural gas and crude oil and condensate from its Pinedale field.

Total production for the quarter ended September 30, 2019 was 57.6 Bcf of natural gas and 419.4 MBbl of crude oil and condensate, for a total of 60.2 Bcfe of production. The production was 2.3 Bcfe lower as compared to the second quarter of 2019, driven by reduced drilling activities and decreased capital investment activity during the quarter as compared to previous quarters in 2019. The Company generated significant cash flow from its producing activities, whereby it has produced 184.9 Bcfe through the nine months ended September 30, 2019. For the nine months ended September 30, 2019, cash flow from operations was $277.5 million.

Early in the third quarter, the Company announced its decision to reduce its operated rig count to a single operated rig. Then late in the third quarter of 2019, the Company decided to release it remaining drilling rig and suspend its operated drilling program in the Pinedale field. This decision was based on natural gas pricing remaining near multi-year lows. This decision has reduced the level of total 2019 capital investment to a range of $240 million to $250 million, a reduction of approximately $90 million from the midpoint of the Company’s initial 2019 capital investment guidance. The Company will continue to evaluate the commodity price environment and the projected investment returns, as it manages its capital investment program.

The Company has agreed to reduce the amount of future capital investment expenditures as part of the Fifth Amendment to the Credit Agreement (“Fifth Amendment”) dated September 16, 2019. The Fifth Amendment establishes a maximum capital expenditure

amount of $65 million, $10 million, and $5 million, for the quarters ended September 30, 2019, December 31, 2019, and quarterly thereafter, with the ability to carryforward unused amounts up to $5 million in aggregate. Per the definition of maximum capital expenditures in the Fifth Amendment, the Company expended $53.7 million in the quarter ended September 30, 2019.

The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and this volatility could be detrimental to the Company’s financial performance. As a result, and from time to time, the Company tries to limit the impact of this volatility on its results by entering into derivative commodity contracts through the use of swap agreements, costless collars, and/or deferred premium puts. In addition to fixed price swap contracts, the Company utilizes costless collars and deferred put contracts, with low premium costs, to provide a degree of floor price protection and allow the Company to participate in more upward price exposure. The Company also enters into short-term fixed price forward physical delivery contracts for natural gas and oil from time-to-time. Under the Fifth Amendment, the Company is subject to minimum hedging requirements. From September 30, 2019 through March 31, 2020, the Company is required to hedge a minimum of 50% of the projected proved developed producing natural gas reserve volumes projected to be produced in the specific quarter. Beginning April 1, 2020, the Company will no longer be subject to a minimum hedging requirement.

On a per unit basis, the average realized prices for the Company in the quarters ended September 30, 2019 and 2018, excluding realized gains and losses on commodity derivatives, was $2.36 per Mcfe and $2.94 per Mcfe, respectively. The average price realization for the Company during the quarter ended September 30, 2019 was $2.67 per Mcfe, including realized gains and losses on commodity derivatives, compared to $2.78 per Mcfe during the quarter ended September 30, 2018.

The average price realization for the Company’s natural gas during the quarter ended September 30, 2019 was $2.35 per Mcf, including realized gains and losses on commodity derivatives, compared to $2.38 per Mcf during the quarter ended September 30, 2018. The average price realization for the Company’s natural gas during the each of the quarter ended September 30, 2019 and 2018, excluding realized gains and losses on commodity derivatives, was $2.04 per Mcf and $2.46 per Mcf, respectively.

The average price realization for the Company’s crude oil and condensate during the quarter ended September 30, 2019 was $60.20 per barrel, including realized gains and losses on commodity derivatives, compared to $58.02 per barrel during the quarter ended September 30, 2018. The average price realization for the Company’s crude oil and condensate during the quarter ended September 30, 2019, excluding realized gains and losses on commodity derivatives, was $58.33 per barrel, compared to $66.54 per barrel during the quarter ended September 30, 2018.

In September 2019, the Company suspended its operated drilling program in the Pinedale Field. The total capital investment in oil and gas properties was $233.1 million for the nine months ended September 30, 2019. During this period, there were 71 gross (70.3 net) vertical wells and 1 gross (0.9 net) horizontal wells, together with 22 gross (7.3 net) vertical wells operated by others that were brought online.

The vertical well costs for the quarter ended September 30, 2019 averaged $2.8 million per well. This is a decrease from $3.2 million per well in the first and second quarters. The decline of well costs in 2019 is a result of an increased success rate of the two-string drilling design over the year, as well as overall improvements in efficiencies and cost management throughout the year. Included in the well results was the successful completion of seven wells with the two-string design in third quarter at an average well cost of $2.6 million per well, highlighting improvement of the selection of the locations for this application in the Pinedale Field, as well as the knowledge gained over the course of the year as to the application of the techniques deployed.

As of September 30, 2019, the Company had $64.0 million outstanding under its Revolving Credit Facility. The borrowing base under our Revolving Credit Facility is currently $1.175 billion, and lender commitments under the Revolving Credit Facility are $200.0 million based on the borrowing base redetermination completed in September 2019. Availability under the Revolving Credit Facility is the unfunded portion of the commitment of $136.0 million, plus the unrestricted cash of Ultra Resources, which was $3.0 million, for a total availability of $139.0 million as of September 30, 2019.

The Company agreed with its lenders under the Revolving Credit Facility that commitments will be reduced to $120 million on February 29, 2020. This agreement to reduce the commitment amount in 2020 was negotiated as part of the Fifth Amendment, whereby the Company will be focusing on net free cash flow generation to facilitate the reduction of total indebtedness. The Fifth Amendment also provides for, among other items, the following changes to certain covenants and other provisions of the Credit Agreement:

•

elimination of all financial maintenance covenants;

•

reduction to the Company’s minimum hedging requirements on projected natural gas volumes to 50% through March 31, 2020, and removal of any minimum hedging requirements thereafter;

•

revision of the anti-cash hoarding provision from $100 million to $25 million at all times borrowings are outstanding under the Revolving Credit Facility; and

•

CONSOLIDATED RESULTS OF OPERATIONS:

Beginning as of January 1, 2019, the Company revised its estimated administrative costs associated with its operations and classified as Lease operating expenses on the Consolidated Statement of Operations. During 2018 and 2019, the Company has taken steps to drive efficiencies through its operations which resulted its overhead costs being less than the inflation adjusted overhead rates set by the Council of Petroleum Accountants Societies (“COPAS”). Accordingly, the Company reduced the amount of costs categorized as Lease operating expenses, with General and administrative expenses absorbing a larger portion of the Company’s total administrative costs.

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

	For the Quarter Ended									For the Nine Months
	Ended September 30,						%			Ended September 30,						%
	2019			2018			Variance			2019			2018			Variance
	(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)		57,645			63,790			(10	)%		177,023			198,917			(11	)%
Crude oil and condensate (Bbl)		419			624			(33	)%		1,305			1,969			(34	)%
Total production (Mcfe)		60,159			67,534			(11	)%		184,853			210,731			(12	)%

Commodity Prices:
Natural gas ($/Mcf, excluding hedges)	$	2.04		$	2.46			(17	)%	$	2.76		$	2.41			15	%
Natural gas ($/Mcf, including realized hedges)	$	2.35		$	2.38			(1	)%	$	2.43		$	2.45			(1	)%
Oil and condensate ($/Bbl, excluding hedges)	$	58.33		$	66.54			(12	)%	$	57.63		$	63.98			(10	)%
Oil and condensate ($/Bbl, including realized hedges)	$	60.20		$	58.02			4	%	$	59.81		$	58.89			2	%

Revenues:
Natural gas sales	$	117,518		$	156,986			(25	)%	$	489,421		$	479,704			2	%
Oil sales		24,465			41,523			(41	)%		75,231			125,974			(40	)%
Other revenues		2,255			5,267			(57	)%		6,451			13,611			(53	)%
Total operating revenues	$	144,238		$	203,776			(29	)%	$	571,103		$	619,289			(8	)%

Derivatives:
Realized gain (loss) on commodity derivatives	$	18,508		$	(10,786	)		(272	)%	$	(56,703	)	$	(3,050	)		1759	%
Unrealized gain (loss) on commodity derivatives		(6,570	)		(11,018	)		(40	)%		75,957			(72,557	)		(205	)%
Total Gain (loss) on commodity derivatives	$	11,938		$	(21,804	)		(155	)%	$	19,254		$	(75,607	)		(125	)%

Operating Costs and Expenses:
Lease operating expenses	$	17,913		$	25,817			(31	)%	$	51,027		$	71,226			(28	)%
Facility lease expense	$	6,640		$	6,875			(3	)%	$	19,828		$	19,557			1	%
Production taxes	$	14,726		$	20,470			(28	)%	$	61,344		$	62,623			(2	)%
Gathering fees	$	19,827		$	21,810			(9	)%	$	60,027		$	69,046			(13	)%
Depletion, depreciation and amortization	$	49,581		$	49,672			(0	)%	$	157,003		$	151,954			3	%
General and administrative expenses	$	6,595		$	1,482			345	%	$	21,080		$	16,233			30	%

Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.30		$	0.38			(21	)%	$	0.28		$	0.34			(18	)%
Facility lease expense	$	0.11		$	0.10			10	%	$	0.11		$	0.09			22	%
Production taxes	$	0.24		$	0.30			(20	)%	$	0.33		$	0.30			10	%
Gathering fees	$	0.33		$	0.32			3	%	$	0.32		$	0.33			(3	)%
Depletion, depreciation and amortization	$	0.82		$	0.74			11	%	$	0.85		$	0.72			18	%
General and administrative expenses	$	0.11		$	0.02			450	%	$	0.11		$	0.08			38	%

Quarter Ended September 30, 2019 vs. Quarter Ended September 30, 2018

Production, Commodity Prices and Revenues:

Production. During the quarter ended September 30, 2019, total production decreased on a gas equivalent basis to 60.2 Bcfe compared to 67.5 Bcfe for the same period in 2018. The decrease is primarily attributable to a decrease in capital investment which occurred in 2019 and resulted in lower production in the current period. Additionally, the divesture of the assets in Utah during late September 2018 resulted in a decrease in production by approximately 1.0 Bcfe on a comparative basis. Given the Company’s decision to suspend its operated drilling program, as announced in September 2019, it is expected that future periods production will decrease based on the natural decline of the proven producing developed wells that were online as of September 30, 2019.

Commodity Prices – Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 1% to $2.35 per Mcf during the quarter ended September 30, 2019, as compared to $2.38 per Mcf for the same period in 2018. The Company has entered into various natural gas price commodity derivative contracts with contract periods extending through the first quarter of 2021. The effect of the derivative contract settlements in the quarter ended September 30, 2019, was a benefit of $0.31 per Mcf. See Note 9 for additional details relating to these derivative contracts. During the quarter ended September 30, 2019 and 2018, the Company’s average price for natural gas, excluding realized gains and losses on commodity derivatives, was $2.04 per Mcf and $2.46 per Mcf, respectively.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased to $60.20 per barrel during the quarter ended September 30, 2019, as compared to $58.02 per barrel for the same period in 2018. The Company has entered into various oil price commodity derivative contracts with contract periods extending through the third quarter 2020. See Note 9 for additional details relating to these derivative contracts. The effect of the derivative contract settlements in the quarter ended September 30, 2019, was a benefit of $1.87 per Bbl. During the three months ended September 30, 2019, the Company’s average price for oil, excluding realized gains and losses on commodity derivatives, was $58.33 per barrel as compared to $66.54 per barrel for the same period in 2018.

Revenues. During the quarter ended September 30, 2019, revenues decreased to $144.2 million as compared to $203.8 million for the same period in 2018. This decrease is primarily attributable to the decrease in total production and the decrease in natural gas prices.

Operating Costs and Expenses:

The Company has been focused on continued cost management. On a unit basis, the Company expects modest pressure on Lease operating expense (“LOE”) and General and administrative expenses due to the expected decrease in future production as the Company has suspended its operated drilling program. Management expects it can mitigate some of this per unit pressure through further cost management and investment initiatives. However, with certain costs being fixed, it is not expected to fully mitigate this pressure.

Lease Operating Expense. LOE decreased to $17.9 million during the quarter ended September 30, 2019, as compared to $25.8 million during the same period in 2018. The decrease for the period was partially driven by the sale of the Utah assets in September 2018. The Utah production and related expenses approximated $3.0 million of expense for the quarter ended September 30, 2018. The sale of the Utah assets was completed in late September 2018. Additionally, beginning in 2019, the Company adjusted the estimate used to determine the overhead rate used for the Company administrative expenses as previously discussed. The decrease in the overhead charged to the LOE was approximately $3.2 million compared to the same period in 2018. On a unit of production basis, LOE costs decreased to $0.30 per Mcfe during the quarter ended September 30, 2019, as compared with $0.38 per Mcfe during the same period in 2018.

General and Administrative Expenses. During the quarter ended September 30, 2019, general and administrative expenses increased to $6.6 million as compared to $1.5 million for the same period in 2018. The increase is primarily attributable to the revision in estimate of costs attributed to General and administrative expenses and LOE, as previously described. The change was partially offset by a decrease in share-based compensation expense recognized during the quarter. On a per unit basis, general and administrative expenses increased to $0.11 per Mcfe for the quarter ended September 30, 2019 compared to $0.02 per Mcfe for the same period in 2018.

The Company analyzes the combined LOE and General and administrative expenses as controllable costs. The combined LOE and General and administrative expenses for the quarter ended September 30, 2019, was $0.41 per Mcfe compared to $0.40 per Mcfe for the same period in 2018. Management also analyzes the combined LOE and General and administrative expenses, excluding the non-cash element of stock compensation. The cash component of LOE and General and administrative expenses for the quarter ended September 30, 2019, was $0.40 per Mcfe compared to $0.38 per Mcfe for the same period in 2018.

Facility Lease Expense. In 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale field. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual base rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index), which base rent may increase if certain volume thresholds are exceeded. For the quarters ended September 30, 2019 and 2018, the Company recognized expense associated with the Lease Agreement of $6.6 million and $6.9 million, respectively.

Production Taxes. During the quarter ended September 30, 2019, production taxes decreased to $14.7 million compared to $20.5 million during the same period in 2018, or $0.24 per Mcfe compared to $0.30 per Mcfe, respectively. Production taxes in Wyoming are primarily calculated based on a percentage of revenue from the physical production and realized revenues, excluding derivative hedge settlements, after certain deductions and were 10.2% of revenues for the quarter ended September 30, 2019 and 10.0% of revenues for the same period in 2018.

Gathering Fees. During the quarter ended September 30, 2019, gathering fees decreased to $19.8 million compared to $21.8 million during the same period in 2018, related to decreased production volumes. On a per unit basis, gathering fees increased slightly to $0.33 per Mcfe for the quarter ended September 30, 2019 as compared to $0.32 per Mcfe in the same period in 2018. Because the gathering fees are charged on a per unit basis, management expects the gathering fees on a unit basis to be relatively consistent, except for contractual pricing adjustments for such services, into the future.

Depletion, Depreciation and Amortization. During the quarter ended September 30, 2019, depletion, depreciation and amortization (“DD&A”) expense was $49.6 million and remained relatively flat compared to the same period in 2018. On a unit of production basis, the DD&A rate increased to $0.82 per Mcfe for the quarter ended September 30, 2019 compared to $0.74 per Mcfe for the same period in 2018. The DD&A expense on a per unit basis has decreased from $0.86 per Mcfe for the first six months ended 2019 to $0.82 per Mcfe for the quarter ended September 30, 2019. The decrease on a per unit basis during the third quarter of 2019 is a result of the Company’s decision to suspend its operated drilling program. Upon the announcement to suspend its operated drilling program, the Company removed the future estimated capital costs and proven undeveloped reserves from the depletion calculation. Until the drilling program is resumed, such future development costs and reserves will continue to be excluded.

Other operating expenses. During the quarter ended September 30, 2019, the Company incurred $7.5 million of expense related to the inventory write-down, $1.8 million of expenses related to rig contract terminations, and $1.2 million of other recurring and nonrecurring expenses. During the quarter ended September 30, 2018, the Company incurred $2.7 million of expense related to the Sunoco Partners Marketing & Terminals L.P. (“SPMT”) settlement.

Other Income and Expenses:

Interest Expense. Interest expense decreased to $32.4 million during the quarter ended September 30, 2019 as compared to $38.4 million during the same period in 2018. Interest expense is comprised of four primary elements: (i) cash interest expense; (ii) PIK interest expense; (iii) amortization of deferred premium; and (iv) amortization of deferred financing costs. The table below reflects the comparative amounts in each period presented (in thousands). The cash interest expense and PIK interest increased for the quarter ended September 30, 2019, as compared to the same period in 2018. This increase is a result of the higher interest cost from the Second Lien Notes issued in December 2019. In conjunction with the issuance of the Second Lien Notes, the Company recognized a deferred premium which is amortized over the term of the Second Lien Notes.

	For the Three Months Ended September 30,
	2019			2018
	(In thousands)
Cash interest expense	$	36,403		$	35,558
PIK interest expense		3,300			—
Amortization of deferred premium		(10,586	)		—
Amortization of deferred financing costs and discount		3,255			2,824
Total interest expense	$	32,372		$	38,382

Deferred Gain on Sale of LGS. During the quarter ended September 30, 2018, the Company recognized $2.6 million in deferred gain on the 2012 sale of the LGS and certain associated real property rights. On January 1, 2019, the Company recognized the remaining deferred gain as an opening balance sheet adjustment to Retained loss upon adoption of ASC 842.

Other Income (Expense). As noted below, the Company entered into additional settlement agreements with holders of certain make-whole and post-petition interest claims. Pursuant to these settlements completed in 2019, the claimants collectively agreed to pay approximately $13.5 million to the Company and that amount is recorded to Other income (expense) on the condensed consolidated statement of operations for the nine months ended September 30, 2019.

Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the quarter ended September 30, 2019, the Company recognized a gain of $11.9 million, as compared to a loss of $21.8 million related to commodity derivatives for the same period in 2018. Of this total, the Company recognized $18.5 million related to a realized gain on commodity derivatives that were settled during the quarter ended September 30, 2019, as compared with $10.8 million related to a realized loss on commodity derivatives during the same period in 2018. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This amount also includes an unrealized loss of $6.6 million on commodity derivatives during the quarter ended September 30, 2019, as compared to an unrealized loss of $11.0 million during the same period in 2018. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract.

Income from Operations:

Pretax Income. During the quarter ended September 30, 2019, the Company recognized income before income taxes of $11.5 million compared to $18.6 million for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives and the decreased net interest expense were the primary elements for the decrease in net income during the quarter ended September 30, 2019, as compared to the same period in 2018.

Income Taxes. The Company has a recorded valuation allowance against all deferred tax assets as of September 30, 2019. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. During the quarter ended September 30, 2019, the Company recognized net income of $11.5 million, or $0.06 per diluted share, as compared to a net loss of $18.6 million, or $0.09 per diluted share, for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivatives and the decreased interest expense were the primary elements for the increase in net income during the quarter ended September 30, 2019, as compared to the same period in 2018.

Nine Months Ended September 30, 2019 vs. Nine Months Ended September 30, 2018

Production, Commodity Derivatives and Revenues:

Production. During the nine months ended September 30, 2019, total production decreased by 12% on a gas equivalent basis to 184.9 Bcfe compared to 210.7 Bcfe for the same period in 2018, primarily attributable to a decrease in capital investment which occurred over 2019 and resulted in lower production in the current period. Additionally, the sale of the assets in Utah in late September 2018 resulted in a decrease of 3.3 Bcfe in production on a comparative basis. As noted previously, the Company’s decision to suspend its operated drilling program will result in subsequent future quarterly decreases in production driven by the natural decline of the proven producing developed wells that were online as of September 30, 2019.

Commodity Prices – Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased to $2.43 per Mcf during the nine months ended September 30, 2019, as compared to $2.45 per Mcf for the same period in 2018. During the nine months ended September 30, 2019, the Company entered into additional natural gas price commodity derivative contracts with contract periods extending through March 2021. See Note 9 for additional details. During the nine months ended September 30, 2019, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.76 per Mcf as compared to $2.41 per Mcf for the same period in 2018. As of September 30, 2019, the derivative contract settlements resulted in a decrease of $0.33 per Mcf of value, most of which occurred in the first quarter of 2019.

Commodity Prices – Oil. Realized oil prices, including realized gains and losses on commodity derivatives, increased slightly to $59.81 per barrel during the nine months ended September 30, 2019 as compared to $58.89 per barrel for the same period in 2018. During the nine months ended September 30, 2019, the Company entered into additional oil price commodity derivative contracts with contract periods extending through June 2020. See Note 9 for additional details. During the nine months ended September 30, 2019, the Company’s average price for oil excluding realized gains and losses on commodity derivatives was $57.63 per barrel as compared

to $63.98 per barrel for the same period in 2018. The benefit from derivative contract settlements in 2019 has been $2.18 per Bbl of incremental value.

Revenues. Decreased production, partially offset by increased average natural gas prices, resulted in revenues decreasing to $571.1 million for the nine months ended September 30, 2019, as compared to $619.3 million for the same period in 2018.

Operating Costs and Expenses:

Lease Operating Expense. LOE decreased to $51.0 million during the nine months ended September 30, 2019 compared to $71.2 million during the same period in 2018. The decrease for the period was primarily related to the sale of the Utah assets in September 2018. The Utah production and related expenses approximated $8.9 million of LOE, or $0.04 per Mcfe, for the nine months ended September 30, 2018. Additionally, beginning in 2019, the Company adjusted the estimate used to determine the overhead rate used for the Company administrative expenses as previously discussed. The decrease in the overhead charged to the LOE was approximately $10.0 million for the nine months ended September 30, 2019. On a unit of production basis, LOE costs decreased to $0.28 per Mcfe during the nine months ended September 30, 2019 compared to $0.34 per Mcfe during the same period in 2018.

General and Administrative Expenses. General and administrative expenses increased to $21.1 million for the nine months ended September 30, 2019 compared to $16.2 million for the same period in 2018. The increase is primarily attributable to the change in estimate of costs attributed to General and administrative expenses and LOE, as previously described. Furthermore, during 2019 the Company incurred legal fees related to the Company’s unsuccessful offer to exchange Ultra Resources, Inc.’s outstanding 7.125% Senior Notes due 2025 for new third lien senior secured notes, which was ultimately terminated in July 2019. This was offset by the decrease in the stock incentive compensation expense for the year. On a per unit basis, general and administrative expenses increased to $0.11 per Mcfe for the nine months ended September 30, 2019 compared to $0.08 per Mcfe for the nine months ended September 30, 2018.

The Company analyzes the combined LOE and General and administrative expenses as controllable costs. The combined LOE and General and administrative expenses for the nine months ended September 30, 2019, was $0.39 per Mcfe compared to $0.42 per Mcfe for the same period in 2018. Management also analyzes the combined LOE and General and administrative expenses, excluding the non-cash element of stock compensation. The cash component of LOE and General and administrative expenses for the nine months ended September 30, 2019, was $0.38 per Mcfe compared to $0.36 per Mcfe for the same period in 2018. As previously noted, the decrease in LOE was due to the divesture of the Utah assets in September 2018. The Utah production and related expenses were approximately $0.04 per Mcfe of expense for the nine months ended September 30, 2018. The sale of the Utah assets was completed in September 2018. This was partially offset by the increase in General and administrative expenses associated with the unsuccessful offering of third lien senior secured notes by the Company in 2019. As previously noted, the suspension of the Company’s drilling program is expected to result in changes to per unit costs, driven by decreasing production volumes.

Facility Lease Expense. During December 2012, the Company sold the LGS and certain associated real property rights in the Pinedale field and the Company entered into the Lease Agreement. The Lease Agreement provides for an initial term of 15 years, and annual rent of $20.0 million during the initial term (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. For the nine months ended September 30, 2019, the Company recognized operating lease expense associated with the Lease Agreement of $19.8 million, or $0.11 per Mcfe, as compared to $19.6 million, or $0.09 per Mcfe, for the same period in 2018. The increase in the unit rate reflects decreased production volumes over which these costs relate.

Production Taxes. During the nine months ended September 30, 2019, production taxes were $61.3 million compared to $62.6 million during the same period in 2018, or $0.33 per Mcfe compared to $0.30 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 10.7% of revenues for the nine months ended September 30, 2019 and 10.1% of revenues for the same period in 2018. The increase in per unit taxes is primarily attributable to increased natural gas prices during the nine months ended September 30, 2019, as compared to the same period in 2018.

Gathering Fees. Gathering fees decreased to $60.0 million for the nine months ended September 30, 2019, compared to $69.0 million during the same period in 2018, largely related to decreased production. On a per unit basis, gathering fees decreased slightly to $0.32 per Mcfe for the nine months ended September 30, 2019, compared to $0.33 per Mcfe for the same period in 2018.

Depletion, Depreciation and Amortization. DD&A expenses increased to $157.0 million during the nine months ended September 30, 2019, from $152.0 million for the same period in 2018. The increase in 2019 is primarily attributable to the inclusion of projected future development costs associated with proved undeveloped properties being at a higher cost and, therefore, the depletion rate per unit is being greater than the current oil and gas property value per unit, offset slightly by decreased production volumes

during the nine months ended September 30, 2019. As noted previously, beginning in the third quarter of 2019, the Company has not included reserves or future development costs associated with proved undeveloped reserves in its depletion calculation given the decision to suspend its operated drilling program. On a unit of production basis, the DD&A rate increased to $0.85 per Mcfe for the nine months ended September 30, 2019 compared to $0.72 per Mcfe for the nine months ended September 30, 2018.

Other operating expenses. As described in Note 12, the Company reached a settlement with the ONRR audit from 2010 through 2012 for approximately $12.4 million during the nine months ended September 30, 2019. Such amounts had been in dispute prior to the Company’s bankruptcy filing in 2016. Furthermore, the Company settled a separate overriding royalty interest dispute and recognized an expense of $1.5 million during the period. The Company also incurred expenses related to the inventory write-down, rig contract terminations and other recurring and nonrecurring expenses during the nine months ended September 30, 2019 which approximated $12.8 million.

Other Income and Expenses:

Interest Expense. Interest expense decreased to $98.1 million during the nine months ended September 30, 2019 compared to $111.9 million during the same period in 2018. Interest expense is comprised of four primary elements: (i) cash interest expense; (ii) PIK interest expense; (iii) amortization of deferred premium; and (iv) amortization of deferred financing costs. The table below reflects the comparative amounts in each period presented. The cash interest expense for the nine months ended September 30, 2019 increased as compared to the same period in 2018 due to the higher interest rate Second Lien Notes that were issued in December 2018.

	For the Nine Months Ended September 30,
	2019			2018
	(In thousands)
Cash interest expense	$	109,647		$	103,601
PIK interest expense		10,022			—
Amortization of deferred premium		(31,158	)		—
Amortization of deferred financing costs and discount		9,563			8,333
Total interest expense	$	98,074		$	111,934

Deferred Gain on Sale of LGS. During the nine months ended September 30, 2018, the Company recorded $7.9 million in deferred gain on the sale of the LGS and certain associated real property rights in the Pinedale field during December 2012. On January 1, 2019, the Company recognized the remaining deferred gain as an opening balance sheet adjustment to Retained loss upon adoption of ASC 842.

Other Income (Expense). The Company entered into additional settlement agreements with holders of certain make-whole and post-petition interest claims. Pursuant to these settlements completed in 2019, the claimants collectively agreed to pay approximately $13.5 million to the Company and that amount is recorded to Other expense, net on the condensed consolidated statement of operations for the nine months ended September 30, 2019.

Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the nine months ended September 30, 2019, the Company recognized a gain of $19.3 million related to commodity derivatives as compared to a loss of $75.6 million related to commodity derivatives during the same period in 2018. Of this total, the Company recognized $56.7 million related to a realized loss on commodity derivatives during the nine months ended September 30, 2019, as compared with $3.1 million related to a realized loss on commodity derivatives during the same period in 2018. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts. This gain (loss) on commodity derivatives also includes an $76.0 million unrealized gain on commodity derivatives for the nine months ended September 30, 2019, as compared to a $72.6 million unrealized loss on commodity derivatives for the same period in 2018. The unrealized gain or loss on commodity derivatives represents the non-cash charge attributable to the change in the fair value of these derivative instruments over the remaining term of the contract. See Note 9 for additional details.

Income from Operations:

Pretax Income. The Company recognized income before income taxes of $109.1 million for the nine months ended September 30, 2019 compared to $45.9 million for the same period in 2018. The operating income and operating expense elements together with the gain on commodity derivative and the decreased net interest expense were the primary elements for the increase in net income during the nine months ended September 30, 2019, as compared to the same period in 2018.

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

Net Income. For the nine months ended September 30, 2019, the Company recognized net income of $109.3 million, or $0.55 per diluted share, as compared to $45.5 million, or $0.23 per diluted share, for the same period in 2018. The increase in earnings is driven by the operating income and operating expense elements together with the gain on commodity derivatives and the decreased interest expense were the primary elements for the increase in net income during the nine months ended September 30, 2019, as compared to the same period in 2018.

LIQUIDITY AND CAPITAL RESOURCES:

Overview. During the nine months ended September 30, 2019, we funded our operations primarily through cash flows from operating activities and periodic borrowings under the Revolving Credit Facility (defined below). At September 30, 2019, the Company had $64.0 million outstanding borrowings under the Revolving Credit Facility. The borrowing base attributed to the Revolving Credit Facility provides for a total of $200.0 million of availability, as determined in September 2019. Availability under the Revolving Credit Facility is the undrawn portion of the commitment of $136.0 million, plus the unrestricted cash of Ultra Resources, which was $3.0 million, for a total availability of $139.0 million as of September 30, 2019. In addition to the borrowings outstanding under the Revolving Credit Facility, the Company had $1.9 billion of other indebtedness outstanding in the form of term loans, secured notes and unsecured notes with maturities in 2022 through 2025.

In conjunction with the Fifth Amendment to the Credit Agreement, described in more detail below, the Company has agreed to limit its future capital expenditures. By reducing capital expenditures, the Company expects it will generate positive free cash flow that is intended to reduce outstanding indebtedness.

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

Capital Expenditures. For the nine months ended September 30, 2019, total capital expenditures were $233.1 million. During this period, the Company participated in 71 gross (70.3 net) vertical wells and 1 gross (0.9 net) horizontal wells, together with 22 gross (7.3 net) vertical wells operated by others that were brought online. As previously discussed, the Company suspended its operated drilling program in late September 2019. Certain completion operations will be concluded in the fourth quarter 2019, and future drilling expenditures will be reduced accordingly.

2019 Capital Investment Plan. As previously discussed , based on the decision in the third quarter to suspend its operated drilling program, the Company’s 2019 capital investment forecast has been adjusted to a range of $240 million to $250 million, a reduction of approximately $90 million from the midpoint of the initial capital investment guidance. We expect to fund any future capital expenditures through cash flows from operations, borrowings under the Revolving Credit Facility, and cash on hand. These future capital investments will be significantly reduced in accordance with the Fifth Amendment to the Credit Agreement, described below. We expect to allocate all of the capital, albeit limited, to development activities in our Pinedale field.

The Fifth Amendment also provides for, among other items, the following changes to certain covenants and other provisions of the Credit Agreement:

•

elimination of all financial maintenance covenants;

•

reduction to the Company’s minimum hedging requirements on projected natural gas volumes to 50% through March 31, 2020 and removal of any minimum hedging requirements thereafter;

•

revision of the anti-cash hoarding provision from $100 million to $25 million at all times borrowings are outstanding under the Revolving Credit Facility; and

•

ability to repurchase indebtedness, including borrowings under the Company’s Senior Secured Term Loan, Senior Secured Second Lien Notes, 6.875% Senior Notes due 2022 and 7.125% Senior Notes due 2025 under certain circumstances, including having no amounts drawn on the Revolving Credit Facility, the Company having established adequate cash reserves, satisfaction of a first lien incurrence test, each as set forth in the Fifth Amendment, and compliance with the Company’s other debt documents. The Term Loan and the Second Lien Notes have prohibitions against the use of cash to repurchase debt. Therefore, in order for the Company to utilize this provision provided by the Credit Agreement, the Company would have to receive additional approval from both the Term Loan Lenders (defined below) and the Second Lien noteholders.

The next scheduled semi-annual borrowing base redetermination is in the spring of 2020. To the extent the Borrowing Base is reduced to an amount that is less than the outstanding borrowings under the Term Loan Agreement, then commitments under the Revolving Credit Facility would be reduced to zero and Ultra Resources would become subject to additional coverage tests under the Term Loan Agreement. Among these new requirements is an asset coverage test and, if not satisfied, the Company would be required to make mandatory prepayments to the Term Loan Lenders in order to cure any deficiency. Failure to make such required payments would result in an Event of Default under the Term Loan Agreement.

The Revolving Credit Facility has $35.0 million of the commitments available for the issuance of letters of credit. No letters of credit are outstanding as of September 30, 2019. The Revolving Credit Facility bears interest either at a rate equal to (a) a customary London interbank offered rate plus an applicable margin that varies from 250 to 350 basis points or (b) the base rate plus an applicable margin that varies from 150 to 250 basis points. The applicable margin is increased by 25 basis points in the event the Company’s leverage ratio, as defined, exceeds 4.00 to 1.00. Ultra Resources is required to pay a commitment fee on the average daily unused portion of the Revolving Credit Facility, which varies based upon a borrowing base utilization grid. Ultra Resources is also required to pay customary letter of credit and fronting fees. The Revolving Credit Facility loans mature on January 12, 2022.

As noted above, the Fifth Amendment established a maximum capital expenditure amount, as defined, of $65 million, $10 million, and $5 million, for the quarters ended September 30, 2019, December 31, 2019, and quarterly thereafter, with the ability to carryforward unused amounts up to $5 million in aggregate. Per the definition of maximum capital expenditures in the Fifth Amendment, the Company expended $53.7 million in the quarter ended September 30, 2019.

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

Term Loan. Ultra Resources entered into a Term Loan Agreement (as amended, the “Term Loan Agreement”) as the borrower with the Company and UP Energy Corporation, as parent guarantors, with Barclays, as administrative agent (the “Term Loan Administrative Agent”), and with the other lenders party thereto from time to time (collectively, the “Term Loan Lenders”) providing for a term loan credit facility (the “Term Loan Credit Facility”). As of September 30, 2019, Ultra Resources had a balance of approximately $971.2 million in borrowings, including $1.1 million of payable-in-kind (“PIK”) interest and current maturities under the Term Loan Credit Facility.

Second Lien Notes and the December Exchange Transaction, to increase the interest rate payable by 100 basis points, such increase comprising 75 basis points payable in cash and 25 basis points payable in kind, and to revise certain covenants and other provisions of the Term Loan Agreement, including, but not limited to:

•

introducing call protection of 102% until December 21, 2019 and 101% until December 21, 2020;

•

introducing additional restrictions on the Revolving Credit Facility; including amendments and refinancing of the Revolving Credit Facility as more thoroughly described in the Term Loan Amendment;

•

deleting the ability to increase commitments under the Term Loan;

•

increasing collateral coverage from 85% to 95% of total PV-9 of Proven Reserves (as defined in the Term Loan Agreement);

•

removing the ability to create, invest in and utilize unrestricted subsidiaries;

•

further limiting the Company’s ability to incur unsecured debt, repay junior debt, and make restricted payments and investments as more thoroughly described in the Term Loan Amendment; and

•

providing the ability for the Company to exchange unsecured borrowings to third lien debt within a construct as described in the Term Loan Amendment.

Borrowings under the Term Loan Agreement bear interest at a rate equal to either (a) a customary London interbank offered rate plus 400 basis points or (b) the base rate plus 300 basis points, in each case, of which 25 basis points of the applicable margin is payable-in-kind solely upon election by Ultra Resources. During 2019, the Company has elected the PIK option for several of its selected interest payments. Recently the Company has elected not to utilize this PIK option. Beginning in June 2019, borrowings under the Term Loan Agreement amortize in equal quarterly installments in aggregate annual amounts equal to 0.25% of the initial aggregate principal amount. Borrowings under the Term Loan Agreement mature on April 12, 2024.

Borrowings under the Term Loan Agreement are subject to mandatory prepayments and customary reinvestment rights. The mandatory prepayments include, without limitation, a prepayment requirement with the total net proceeds from certain asset sales and net proceeds on insurance received on account of any loss of Ultra Resources’ property or assets, in each case subject to certain exceptions. In addition, subject to certain conditions including a situation in which a Revolving Credit Facility no longer exists, there is a prepayment requirement if the asset coverage ratio is less than 2.0 to 1.0. To the extent any mandatory prepayments are required, prepayments equal to six monthly payments are required in order to attain compliance with such amounts being applied to prepay the borrowings under the Term Loan Agreement.

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

Interest on the Second Lien Notes accrue at (i) an annual rate of 9.00% payable in cash and (ii) an annual rate of 2.00% PIK. The cash interest payment dates for the Second Lien Notes are January 15 and July 15 of each year, commencing in July 2019. The Company has accounted for such PIK interest as an increase to the principal outstanding. The Second Lien Notes will mature on July 12, 2024.

equal to 101% of the aggregate principal amount of such Second Lien Notes, plus any accrued but unpaid interest (including PIK interest) to the date of repurchase.

The 2022 Notes will mature on April 15, 2022. Interest on the 2022 Notes accrue at an annual rate of 6.875% and interest payment dates for the 2022 Notes are April 15 and October 15 of each year. The 2025 Notes will mature on April 15, 2025. Interest on the 2025 Notes accrue at an annual rate of 7.125% and interest payment dates for the 2025 Notes are April 15 and October 15 of each year. Interest will be paid on the Unsecured Notes from the issue date until maturity. Refer to Note 6 Long Term Debt in the 2018 Form 10-K for additional details on the terms of the Unsecured Notes.

Cash flows provided by (used in):

Operating Activities. During the nine months ended September 30, 2019, net cash provided by operating activities was $277.5 million compared to $307.1 million for the same period in 2018. The decrease in net cash provided by operating activities is attributable to decreased revenues as a result of decreased production. Net cash provided by operating activities is also affected by working capital changes and the timing of cash receipts and disbursements.

Investing Activities. During the nine months ended September 30, 2019, net cash used in investing activities was $243.8 million as compared to $307.6 million for the same period in 2018. The decrease in net cash used in investing activities is largely related to decreased capital investments in 2019 associated with the Company’s drilling activities as compared to 2018. In 2018, the Company was drilling vertical and horizontal wells which resulted in higher capital costs. During 2019, the Company was primarily focused on drilling vertical wells. In the third quarter of 2019, the Company announced its decision to suspend its operated drilling program in the Pinedale field while natural gas pricing remains near multi-year lows.

Financing Activities. During the nine months ended September 30, 2019, net cash used in financing activities was $46.4 million as compared to $2.7 million for the same period in 2018. The increase in net cash used in financing activities is attributable to the payments on the Revolving Credit Facility from operating cash flows in excess of the borrowings for the nine months ended September 30, 2019.

Critical Accounting Policies

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

New accounting pronouncements:

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

OFF BALANCE SHEET ARRANGEMENTS:

The Company did not have any off-balance sheet arrangements as of September 30, 2019.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Objectives and Strategy: The Company is exposed to commodity price risk. The following quantitative and qualitative information is provided about financial instruments to which we were a party at September 30, 2019, and from which we may incur future gains or losses from changes in commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

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

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

Commodity Derivative Contracts: At September 30, 2019, the Company had open commodity derivative contracts to manage commodity price risk as presented in the table below. Subsequent to September 30, 2019, the Company monetized certain derivative contracts and received proceeds for approximately $6.6 million. For the fixed price swaps, the Company receives the fixed price for the contract and pays the variable price to the counterparty. For the basis swaps, the Company receives a fixed price for the difference between two sales points for a specified commodity volume over a specified time period. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

Type/Year	Index	Total Volumes		Weighted Average Price per Unit			Fair Value Asset (Liability) - September 30, 2019
		(in millions)					(in thousands)
Natural gas fixed price swaps		(Mmbtu)		($/Mmbtu)
2019 (October through December)	NYMEX-Henry Hub		32.7	$	2.77		$	11,419
2020	NYMEX-Henry Hub		24.6		2.78			5,210

Natural gas basis swaps (1)		(Mmbtu)		($/Mmbtu)
2019 (October through December)	NW Rockies Basis Swap		29.1	$	(0.48	)	$	(6,469	)
2020	NW Rockies Basis Swap		17.1		(0.17	)		581

Crude oil fixed price swaps		(Bbl)		($/Bbl)
2019 (October through December)	NYMEX-WTI		0.3	$	59.60		$	1,849
2020	NYMEX-WTI		0.5		60.31			3,718

Type/Year	Index	Total Volumes		Weighted Average Floor Price ($/MMBTU)		Weighted Average Ceiling Price ($/MMBTU)		Fair Value Asset (Liability) - September 30, 2019
		(in millions)						(in thousands)
Natural gas collars		(Mmbtu)
2019 (October through December)	NYMEX		1.4	$	2.90	$	3.15	$	673
2020	NYMEX		76.1	$	2.45	$	2.92	$	12,734
2021	NYMEX		7.2	$	2.46	$	3.05	$	73

Natural gas deferred premium put options (2)		(Mmbtu)
2020	NYMEX		27.9	$	2.41	N/A		$	3,336

(1)

(2)

The Natural gas deferred premium put options include an average deferred premium of $0.13.

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

Type/Year	Index	Total Volumes	Weighted Average Price per Unit
Natural gas basis swaps		(Mmbtu)	($/Mmbtu)
2019 (October through December)	NW Rockies Basis Swap	2.44	$	(0.12	)
2020	NW Rockies Basis Swap	3.64	$	(0.12	)

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
Commodity Derivatives:	2019			2018			2019			2018
	(In thousands)
Realized gain (loss) on commodity derivatives - natural gas (1)	$	17,721		$	(5,468	)	$	(59,546	)	$	6,958
Realized gain (loss) on commodity derivatives - oil (1)		787			(5,318	)		2,843			(10,008	)
Unrealized gain (loss) on commodity derivatives (1)		(6,570	)		(11,018	)		75,957			(72,557	)
Total gain (loss) on commodity derivatives	$	11,938		$	(21,804	)	$	19,254		$	(75,607	)

(1)

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

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

Interest Rate Risk

We are also exposed to market risk related to adverse changes in interest rates, primarily related to fluctuations in short-term rates that are based on the London interbank offered rate. Such fluctuations may result in reductions of earnings or cash flows due to increases in the interest rates we pay on outstanding borrowings under the Revolving Credit Facility and Term Loan Agreement. At September 30, 2019, the weighted average interest rate on our variable rate debt was 6.0% per year. If the balance of our variable

interest rate at September 30, 2019 were to remain constant, a 10% change in the variable market interest rates would impact our cash flows by approximately $1.8 million per year.

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our natural gas and oil production, which we market to diverse group of companies, including major energy companies, natural gas utilities, oil refiners, pipeline companies, local distribution companies, financial institutions and end-users in various industries. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness.

To a lesser extent, we are also exposed to credit risk through our derivative counterparties. We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 9 for additional information regarding our derivative activities.

ITEM 4 — CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company has performed an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered by this Quarterly Report on Form 10-Q. The Company’s disclosure controls and procedures are the controls and other procedures that it has designed to ensure that it records, processes, accumulates and communicates information to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submissions within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2019.

Changes in Internal Control over Financial Reporting

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

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 12 for discussion of on-going claims and disputes that arose during our chapter 11 proceedings, certain of which may be material. The Company is also currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine or predict the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, results of operations, or cash flows.

ITEM 1A. RISK FACTORS

Our business has many risks. Any of the risks discussed in this Quarterly Report on Form 10-Q or in our other SEC filings, could have a material impact on our business, financial position, or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. Except as set forth below, there have been no material changes to the risks described in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 and the Quarterly Reports on the Form 10-Q for the periods ended March 31, 2019 and June 30, 2019. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

Any future borrowing base reductions under our Credit Agreement could subject us to additional coverage tests and mandatory prepayments.

If, at a future borrowing base redetermination, the Borrowing Base under our Credit Agreement is reduced to an amount less than the outstanding borrowings under the Term Loan Agreement, commitments under the Revolving Credit Facility would be reduced to zero and Ultra Resources would become subject to additional coverage tests under the Term Loan Agreement. Among these new requirements is an asset coverage test that, if not satisfied, would require the Company to make mandatory prepayments to the Term Loan Lenders in order to cure any deficiency. The failure to make such required payments would result in an Event of Default under the Term Loan Agreement.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

(a) Exhibits

Exhibit Number		Description

2.1		Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization (incorporated by reference to Exhibit A of the Order Confirming Debtors’ Second Amended Joint Chapter 11 Plan of Reorganization, filed as Exhibit 99.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on March 16, 2017).

3.1		Restated Articles of Reorganization of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed by Ultra Petroleum Corp. on August 9, 2019).

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

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

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

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

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

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

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

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

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

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

10.1		Fifth Amendment to Credit Agreement, dated as of September 16, 2019, by and among Ultra Resources, Inc. as borrower, Bank of Montreal, as administrative agent, and each of the lenders and other parties party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by Ultra Petroleum Corp. on September 16, 2019).

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


#10.6		Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.5 to the Form 10-Q filed by Ultra Petroleum Corp. on May 9, 2019).
*31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document.

**101.SCH		XBRL Taxonomy Extension Schema Document.

**101.CAL		XBRL Taxonomy Calculation Linkbase Document.

**101.LAB		XBRL Label Linkbase Document.

**101.PRE		XBRL Presentation Linkbase Document.

**101.DEF		XBRL Taxonomy Extension Definition.

*	Filed herewith

**	Furnished herewith

#	Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-Q pursuant to Item 15(b)

SIGNATURES

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

	ULTRA PETROLEUM CORP.

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

Date: November 7, 2019

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

Date: November 7, 2019

	By:	/s/ Mark T. Solomon
		Name:	Mark T. Solomon
		Title:	Vice President – Controller and Chief Accounting Officer
Date: November 7, 2019

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