Ultra Petroleum 8-K Ultra Petroleum Corp. Announces Fourth Quarter and Full-Year 2019 Results, Proved Reserves as Fourth Quarter 2019 Financial Results

Exhibit 99.1

  Ultra Petroleum Corp.

NEWS RELEASE

FOR IMMEDIATE RELEASE

Ultra Petroleum Corp. Announces Fourth Quarter and Full-Year 2019 Results, Proved Reserves as

ofYear-end December 31, 2019 and as of March 31, 2020, and the Issuance of a Qualified Opinion

by the Company’s Independent Registered Public Accounting Firm About the Company’s Ability

to Continue as a Going Concern

Englewood, ColoradoApril 14, 2020 – Ultra Petroleum Corp. (“Ultra” or the “Company”) (OTCQX: UPLC) announces financial and operating results for the quarter and year ended December 31, 2019. The Company is also reporting proved reserves as ofyear-end December 31, 2019 and as of March 31, 2020.

Highlights:

• Fourth quarter and full-year 2019 production were within guidance at 55.4 billion cubic feet equivalent (“Bcfe”) and 240.2 Bcfe, respectively,

• During 2019, Ultra turned online 71 gross (70.3 net) operated vertical wells prior to suspending its drilling program in September,

• The Company’s average unhedged price for natural gas was $2.78 per Mcf in the fourth quarter of 2019 and reflects thatfirst-of-month Rockies basis was positive to Henry Hub by $0.27 per MMBtu in the fourth quarter,

• During the fourth quarter of 2019, the Company had cash flow from operating activities of $19.8 million and generated positive free cash flow⁽⁸⁾ of $56.4 million.

“We continue to execute on our plan of focusing on free cash flow generation and reducing our debt levels. Ultra’slow-cost,low-decline and predictable operations resulted in free cash flow generation of approximately $56 million for the fourth quarter, allowing us to continue to reduce indebtedness on the trajectory we have forecast,” said Brad Johnson, President and Chief Executive Officer of Ultra.

Fourth Quarter 2019 Financial Results

Ultra’s reported net loss for the quarter ended December 31, 2019 was $1.3 million, or $0.01 per diluted share. The Company reported adjusted net income ⁽¹⁾ of $22.6 million, or $0.11 per diluted share, for the quarter ended December 31, 2019. Net income was $39.7 million or $0.20 per diluted share in the quarter ended 2018, with adjusted net income for the same period at $27.4 million or $0.14 per diluted share.

During the fourth quarter of 2019, total revenues excluding hedging settlements were $170.9 million as compared to $273.2 million during the fourth quarter of 2018. Derivative settlements during these periods were a loss of $2.2 million and of $82.4 million, respectively. The Company’s production of natural gas and oil was 55.4 Bcfe, a decrease from 64.3 Bcfe in the same period of 2018. The decrease in production was based on the Company’s decision to reduce and then suspend drilling in the third

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quarter of 2019 in response to weak commodity pricing. This decision allowed the Company to generate cash flow from operating activities of $19.8 million and free cash flow of $56.4 million in the fourth quarter of 2019. The Company reported Adjusted EBITDA⁽⁵⁾ of $100.6 million for the quarter ended December 31, 2019 compared to $110.8 million for the fourth quarter of 2018. Ultra’s fourth quarter production was comprised of 53.1 billion cubic feet (“Bcf”) of natural gas and approximately 378,000 barrels (“Bbls”) of oil.

During the fourth quarter of 2019, Ultra’s average realized natural gas price was $2.72 per thousand cubic feet (“Mcf”), which included derivative settlements, as compared to $2.58 per Mcf in the fourth quarter of 2018. Excluding the derivative settlements, the Company’s average price for natural gas was $2.78 per Mcf in the fourth quarter of 2019, compared to $3.95 per Mcf for the fourth quarter of 2018. Rockies natural gas basis, measured byfirst-of month Inside FERC Northwest Rockies (“NWROX”) compared to Henry Hub, was positive in the fourth quarter of 2019 by $0.27 per MMBtu. The Company’s average realized oil price was $60.53 per Bbl, including derivative settlements, for the quarter ended December 31, 2019, as compared to $61.74 per Bbl for the same period in 2018.

Full-Year 2019 Results

Ultra’s reported net income for the year ended December 31, 2019, was $108.0 million, or $0.55 per diluted share as compared with net income of $85.2 million or $0.43 per diluted share for the same period in 2018. Adjusted net income for the year ended December 31, 2019, was $69.1 million, or $0.35 per diluted share, as compared to $149.7 million and $0.76 per diluted share in 2018.

During the year ended December 31, 2019, revenues from natural gas and oil sales, including processing credits, was $742.0 million as compared to $892.5 million in the year ended December 31, 2018. During the year ended December 31, 2019, production of natural gas and oil was 240.2 Bcfe, which was comprised of 230.1 Bcf of natural gas and 1.7 million barrels of oil.

During the year ended December 31, 2019, Ultra’s average realized natural gas price was $2.50 per Mcf, including derivative settlements. Excluding the derivative settlements, the Company’s average price for natural gas was $2.77 per Mcf for both 2019 and 2018, with volatility through each period. The net basis differential between NWROX and Henry Hub, using first of month pricing was negative $0.04 per MMBtu for the full year 2019 as compared to negative $0.46 in 2018. The Company’s average realized oil price, including derivative settlements, was $59.97 per Bbl for the year ended December 31, 2019, as compared to $59.44 per Bbl for the same period in 2018.

For the full year 2019, total capital expenditures were $241.1 million. During this period, the Company participated in 94 gross (78.5 net) wells that were turned to sales, including operated andnon-operated wells in the Pinedale field in Wyoming.

Proved Reserves as of December 31, 2019

Year-end 2019 proved reserves were 1,990 Bcfe, consisting entirely of Proved Developed Producing (“PDP”) reserves. Given the decision to suspend the drilling program in the third quarter, citing a need for higher natural gas prices in order to justify capital development, the Company had revisions that transferred out all 570 Bcfe of its Proved Undeveloped (“PUD”) reserves as of December 31, 2019. For the 20th consecutive year, Netherland, Sewell & Associates, Inc. (“NSAI”), prepared a full reserve report for the Company. The highlights below summarize theyear-end 2019 reserve results:

• Year-end 2019 proved reserves were 1,990 Bcfe, all of which are in the PDP category, and by volume are comprised of 96 percent natural gas and 4 percent oil,

• Theyear-end 2019 PV10 valuation for proved reserves usingpre-tax estimated future net cash flows was $1.7 billion⁽⁹⁾, and

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• The PV10 valuation of Ultra’syear-end reserves was calculated based on reference prices for natural gas of $2.58 per MMBtu and oil of $55.85 per Bbl in accordance with the rules of the Securities and Exchange Commission (“SEC”). Applying regional market differentials along with appropriate adjustments for quality, our marketing contracts, energy content, transportation charges, and adjustments for basis over same historical12-month period, the average prices for the Company’s proved reserves were $2.44 per Mcf for natural gas and $55.36 per Bbl for oil, computed in accordance with the rules of the SEC.

Going Concern Qualification

The report of the Company’s independent registered public accounting firm that accompanies its audited, consolidated financial statements in our Annual Report on Form10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The failure to deliver audited, consolidated financial statements without a going concern or like qualification or explanation results in a default under each of the Credit Agreement and Term Loan Agreement as of April 14, 2020. We expect that we will be precluded from making additional draws on the Credit Agreement unless a waiver is obtained. If we do not obtain a waiver or other suitable relief from the lenders under the Credit Agreement and the Term Loan Agreement before the expiration of a30-day grace period, an event of default under each of the Credit Agreement and Term Loan Agreement would occur, which would allow the lenders to accelerate the loans outstanding under the Credit Agreement and Term Loan Agreement. At this time, we do not expect to obtain a waiver of this requirement and we do not currently have sufficient liquidity to repay such indebtedness were it to be accelerated.

Liability Management Update

In February and March 2020, the Company entered into confidentiality agreements and commenced discussions with certain holders of the Company’s long-term debt and their legal and financial advisors. The Company previously engaged with certain debtholders regarding a potential out-of-court restructuring, but as previously disclosed on March 5, 2020, such negotiations are no longer occurring. Negotiations and discussions with certain other debtholders and their advisors are now ongoing regarding a potential in-court restructuring, although as of the date of this filing no definitive agreements have been reached regarding any amendments, restructurings or other transactions relating to the Company’s indebtedness.

There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be. If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code or the Canadian Bankruptcy and Insolvency Act in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. We discuss these matters in further detail under, among other places, in Note 1 to our consolidated financial statements included in our Annual Report on Form10-K.

Proved Reserves as of March 31, 2020

In order to fulfill its obligation to evaluate the full cost ceiling and to calculate DD&A of its oil and gas properties, the Company is required to estimate its oil and gas reserves on a quarterly basis. The estimated proven oil and gas reserves considers the estimated future production based on the most current well information available including decline rate changes causing downward revisions, and updated pricing in accordance with SEC requirements. These SEC reference prices, together with basis differentials expanding modestly since year end, decreased by 15% for natural gas and <1% for oil, as compared to the pricing utilized as of December 31, 2019. NSAI prepared a full reserve report of estimated proved reserves as of March 31, 2020 for the Company. The highlights below summarize the March 31, 2020 reserve results:

• Consistent with year end, the SEC reference prices utilized in the preparation of the reserves as of March 31, 2020 were based on the12-month unweighted arithmetic average of thefirst-day-of-the-month price for each month in the period April 2019 through March 2020, which were $2.30 per MMBtu for Henry Hub spot and $55.96 per Bbl for WTI. Applying regional market differentials along with appropriate adjustments for quality, our marketing contracts, energy content, transportation charges, and updates to basis for the same period, the average prices for the Company’s proved reserves were $2.07 per Mcf for natural gas and $55.35 per Bbl for oil, computed in accordance with the rules of the SEC.

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• March 31, 2020 proved reserves were 1,766 Bcfe, all of which are in the PDP category, and by volume are comprised of 96 percent natural gas and 4 percent oil,

• The discounted future net cash flows before income tax estimated at March 31, 2020 was $1.217⁽¹⁰⁾billion, respectively.

2020 Capital Budget and Production Forecast

As previously announced, the Company’s capital investment program is expected to be approximately $10—$20 million for 2020, reflecting Ultra’s decision to suspend drilling and focus on free cash flow generation. Additionally, the Company is confirming its 2020 production guidance of 182 to 192 Bcfe. In the first quarter, the average daily production rate was 554 MMcfe/d.

Cost Guidance

The following table presents the Company’s expected per unit of production expenses for the first quarter and full year 2020. Production tax guidance assumes forward NYMEX prices for the remainder of the year and realized prices for the periods reported to date. The Company has previously disclosed that the unit costs are expected to increase as compared to 2019 based on a combination ofPDP-only production profile and the reduction of certain costs being capitalized toward itsnow-suspended development drilling program. The Company has incorporated cost savings into its 2020 guidance of approximately 16 percent for G&A items and approximately 3 percent for LOE items on a gross basis. The net effect, after the impact of reduced capitalization to the full cost pool in 2020 and the reduced production profile, is as reflected below. Additionally, the Company renegotiated certain midstream and marketing agreements in the fourth quarter of 2019. The effect of these renegotiated agreements removes a processing credit previously applied to net gathering expenses and provides for an incremental uplift in realized gas prices. The net effect is an increase to cash margin by $0.03 - $0.04 per MMBtu.

2020 Expenses (per Mcfe)	1Q20 Guidance	Full-Year 2020 Guidance
Lease Operating Expense	$0.34 – 0.39	$0.36 – 0.42
Facility Lease Expense	$0.10 – 0.13	$0.11 – 0.14
Production Taxes	$0.25 – 0.31	$0.19 – 0.25
Gathering Fees, gross	$0.32 – 0.36	$0.32 – 0.36
Gathering Fees, net	$0.31 – 0.35	$0.31 – 0.35
Transportation Charges	$0.06 – 0.10	$0.04 – 0.08
Cash G&A	$0.14 – 0.19	$0.15 – 0.20
DD&A	$0.82 – 0.88	$0.72 – 0.78
Cash Interest Expense	$0.65 – 0.70	$0.69 – 0.74

Hedging Activity

The Company will continue to evaluate hedging opportunities in order to provide a degree of certainty of cash flows along with being opportunistic in a strengthening natural gas and Rockies basis market. Management also works to balance the ability to provide upside exposure for the Company as the increase in future commodity prices has a meaningful impact on our cash flows on unhedged volumes given our low operating costs. The Company remains complaint with its hedging requirements under the terms of its revolving credit facility. As previously disclosed, these hedging requirements phased out completely as of April 2020.

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The table below provides a summary of the hedges in place for the first quarter and as of March 31, 2020:

	Q1 2020			Q2 2020		Q3 2020		Q4 2020		Q1 2021
Natural Gas Swaps:
Volume (MMBtu/d)		260,220			—		—		—		—
NYMEX ($/MMBtu)	$	2.76		$	—	$	—	$	—	$	—
Natural Gas Collars:
Volume (MMBtu/d)		36,374			236,000		175,000		215,000		80,000
NYMEX Floor ($/MMBtu)	$	2.76		$	2.32	$	2.41	$	2.44	$	2.46
NYMEX Ceiling ($/MMBtu)	$	3.19		$	2.83	$	2.85	$	2.92	$	3.05
Natural Gas Puts:
Volume (MMBtu/d)		—			35,593		80,000		30,000		—
NYMEX Strike Price ($/MMBtu)	$	—		$	2.28	$	2.29	$	2.26	$	—
Oil Swaps:
Volume (Bbl/d)		2,750			1,700		1,000		—		—
NYMEX ($/Bbl)	$	60.38		$	59.66	$	60.00	$	—	$	—
Natural Gas Basis Swap Contracts:
NW Rockies Volume (MMBtu/d)(a)		328,187			—		—		—		—
Price Differential ($/MMBtu)	$	(0.06	)	$	—	$	—	$	—	$	—

(a) Represents swap contracts that fix the basis differentials for gas sold at or near Opal, Wyoming.

Continued Exemptive Relief from Canada’s National Instrument51-101

Ultra is pleased to announce that applicable provincial securities commissions in Canada have issued a decision document (the “Decision”) which has the effect of granting Ultra continued exemptive relief from the disclosure requirements contained in Canada’s National Instrument51-101 Standards of Disclosure for Oil and Gas Activities (“NI51-101”) in addition to other continuous disclosure obligations under applicable Canadian securities laws. Ultra had obtained similar exemptive relief in 2005 but was required to obtain this new Decision as a result of the facts underlying the original exemptive relief changing due to the delisting of Ultra’s common stock from the NYSE and Nasdaq.

As a result of the Decision, and provided that certain conditions set out in the Decision are met on anon-going basis, Ultra will not be required to comply with the Canadian requirements of NI51-101 and, accordingly, will not be required to file Form51-101F1 Statement of Reserves Data and Other Oil and Gas Information, Form51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor or Form51-101F3 Report of Management and Directors on Oil and Gas Disclosure. In lieu of such filings, the Decision permits Ultra to provide disclosure in respect of its oil and gas activities in the form permitted by, and in accordance with, the legal requirements of the United States Securities Act of 1933, the United States Securities Exchange Act of 1934 and the rules and regulations of the SEC and the rules and obligations of any exchange upon which Ultra’s common stock is listed (collectively, “U.S. Rules”). The Decision also provides that Ultra is required to file all such oil and gas disclosure and other continuous disclosure with the appropriate Canadian securities commissions on www.sedar.com as soon as practicable after such disclosure is filed with the SEC.

Ultra’s disclosure relating to its oil and gas activities therefore continue to comply with the U.S. Rules rather than NI51-101 and the Canadian Oil and Gas Evaluation Handbook. The U.S. Rules differ in a number of respects from the disclosure otherwise required under Canada’s NI51-101 and the Canadian Oil and Gas Evaluation Handbook and investors are urged to consider these differences when considering all future disclosures made by Ultra relating to its oil and gas activities.

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Ultra Petroleum Corp.

Selected Operating and Financial Data

As of and for the Years and Quarters Ended December 31, 2019 and 2018

All amounts

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	For the Year Ended						For the Quarter Ended
	December 31,						December 31,
	2019			2018			2019			2018
Volumes:
Natural gas (Mcf)		230,121			260,406			53,098			61,489
Oil and condensate (Bbls)		1,683			2,442			378			473
Mcfe - Total		240,219			275,058			55,366			64,327
Revenues:
Natural gas sales	$	637,007		$	722,313		$	147,586		$	242,609
Oil sales		97,231			153,534			22,000			27,560
Other revenue		7,794			16,652			1,343			3,041
Total operating revenues		742,032			892,499			170,929			273,210
Expenses:
Lease operating expenses		70,608			90,290			19,581			19,064
Facility lease expense		25,468			25,947			5,640			6,390
Production taxes		79,459			93,322			18,114			30,699
Gathering fees		78,261			89,294			18,427			20,684
Transportation charges		1,496			512			1,303			76
Total lease operating costs		255,292			299,365			63,065			76,913
Depletion and depreciation		204,227			204,255			47,224			52,301
General and administrative		26,551			25,005			5,473			8,771
Other operating expenses, net		28,889			9,118			2,269			7,519
Total operating expenses		514,959			537,743			118,031			145,504
Other (expense) income, net		392			1,212			88			18
Contract settlement income (expense), net		13,468			12,656			—			15,331
Interest expense		(129,398	)		(148,316	)		(31,322	)		(36,382	)
Deferred gain on sale of liquids gathering system		—			10,553			—			2,638
Realized gain (loss) on commodity derivatives		(58,879	)		(85,413	)		(2,176	)		(82,364	)
Unrealized gain (loss) on commodity derivatives		54,282			(59,799	)		(21,674	)		12,758
Total other (expense) income, net		(120,135	)		(269,107	)		(55,084	)		(88,001	)
Income before income taxes		106,938			85,649			(2,186	)		39,705
Income tax provision (benefit)		(1,050	)		442			(881	)		—
Net income	$	107,988		$	85,207		$	(1,305	)	$	39,705
Adjusted Net Income Reconciliation:
Net income	$	107,988		$	85,207		$	(1,305	)	$	39,705
Contract settlement income (expense), net		(13,468	)		(12,656	)		—			(15,331	)
Debt exchange expenses		—			8,272			—			8,272
Unrealized (gain) loss on commodity derivatives		(54,282	)		59,799			21,674			(12,758	)
Other operating expenses, net		28,889			9,118			2,269			7,519
Adjusted net income(1)	$	69,127		$	149,740		$	22,638		$	27,407
Net cash provided by operating activities	$	302,416		$	310,897		$	19,815		$	1,392
Operating cash flow(2)	$	288,786		$	346,994		$	73,855		$	69,075
(seenon-GAAP reconciliation)
Adjusted EBITDA(5)	$	404,273		$	504,024		$	100,603		$	110,766
(seenon-GAAP reconciliation)
Weighted average shares (000’s)(9)
Basic		197,651			196,964			197,858			197,190
Diluted		197,690			197,541			197,906			197,617
Earnings (loss) per share
Net income (loss) - basic	$	0.55		$	0.43		$	(0.01	)	$	0.20
Net income (loss) - diluted	$	0.55		$	0.43		$	(0.01	)	$	0.20
Adjusted earnings per share(1)
Adjusted net income - basic	$	0.35		$	0.76		$	0.11		$	0.14
Adjusted net income - diluted	$	0.35		$	0.76		$	0.11		$	0.14
Realized Prices
Natural gas ($/Mcf), excluding realized gain on commodity derivatives	$	2.77		$	2.77		$	2.78		$	3.95

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Natural gas ($/Mcf), including realized gain on commodity derivatives	$	2.50		$	2.48		$	2.72		$	2.58
Oil liquids ($/Bbl), excluding realized gain on commodity derivatives	$	57.78		$	62.88		$	58.20		$	58.27
Oil liquids ($/Bbl), including realized gain on commodity derivatives	$	59.97		$	59.44		$	60.53		$	61.74
Costs Per Mcfe
Lease operating expenses	$	0.29		$	0.33		$	0.35		$	0.30
Facility lease expense	$	0.11		$	0.09		$	0.10		$	0.10
Production taxes	$	0.33		$	0.34		$	0.33		$	0.48
Gathering fees (net)	$	0.29		$	0.27		$	0.31		$	0.28
Transportation charges	$	0.01		$	—		$	0.03		$	—
Depletion and depreciation	$	0.85		$	0.74		$	0.85		$	0.81
General and administrative - total	$	0.11		$	0.09		$	0.10		$	0.14
Interest expense, including PIK and the amortization of deferred financing costs and the premium	$	0.54		$	0.54		$	0.57		$	0.57
	$	2.53		$	2.40		$	2.64		$	2.68
Adjusted Margins
Adjusted Net Income Margin(3)		10	%		19	%		14	%		14	%
Adjusted Operating Cash Flow Margin(4)(7)		42	%		43	%		44	%		36	%
Adjusted EBITDA Margin(6)		59	%		63	%		60	%		58	%

	As of
	December 31,			December 31,
	2019			2018
Cash and cash equivalents	$	1,664		$	17,014
Outstanding debt
Credit Agreement		64,700			104,000
Term Loan, secured due 2024		968,756			975,000
Second Lien Notes, secured, due 2024		583,853			545,000
6.875% Senior Notes, unsecured due 2022		150,439			195,035
7.125% Senior Notes, unsecured due 2025		225,000			225,000
Outstanding debt	$	1,992,748		$	2,044,035
Add: Premium on exchange transaction		203,883			228,096
Less: Deferred financing costs		(46,421	)		(56,650	)
Total outstanding debt, net	$	2,150,210		$	2,215,481

	For the Year Ended					For the Quarter Ended
	December 31,					December 31,
	2019			2018		2019		2018
Net cash provided by operating activities	$	302,416		$	310,897	$	19,815	$	1,392
Net changes in operating assets and liabilities and other non-cash ornon-recurring items(7)		(13,630	)		36,097		52,737		67,683
Operating Cash Flow(2)	$	288,786		$	346,994	$	72,552	$	69,075

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	For the Year Ended						For the Quarter Ended
	December 31,						December 31,
	2019			2018			2019			2018
Net income	$	107,988		$	85,207		$	(1,305	)	$	39,705
Interest expense		129,398			148,316			31,322			36,382
Depletion and depreciation		204,227			204,255			47,224			52,301
Contract settlement (income) expense, net		(13,468	)		(12,656	)		—			(15,331	)
Unrealized (gain) loss on commodity derivatives		(54,282	)		59,799			21,674			(12,758	)
Deferred gain on sale of liquids gathering system		—			(10,553	)		—			(2,638	)
Stock compensation expense		2,571			11,824			300			278
Taxes		(1,050	)		442			(881	)		—
Debt exchange expenses		—			8,272			—			8,272
Other operating expenses, net		28,889			9,118			2,269			4,555
Adjusted EBITDA(5)	$	404,273		$	504,024		$	100,603		$	110,766
Capital and PP&E expenditures, net of proceeds received		(241,636	)		(374,387	)		(8,058	)		(90,312	)
Cash interest expense		(145,339	)		(137,812	)		(36,146	)		(34,211	)
Free cash flow(8)	$	17,298		$	(8,175	)	$	56,399		$	(13,757	)
Production (Mcfe)		240,219			275,058			55,366			64,327
Adjusted EBITDA per Mcfe	$	1.68		$	1.83		$	1.82		$	1.72

(1) Adjusted Net Income is defined as Net income adjusted to excludenon-cashmark-to-market gains or losses on commodity derivatives, certain income or expense amounts in order to exclude the volatility associated with the effects ofnon-recurring charges such as contract settlement expenses and other operating expenses.

(2) Operating Cash Flow is defined as Net cash provided by operating activities before changes in operating assets and liabilities and othernon-cash andnon-recurring charges. Management believes that thenon-GAAP measure of operating cash flow is useful as an indicator of an oil and gas exploration and production Company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the Company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.

(3) Adjusted Net Income Margin is defined as Adjusted Net Income divided by Total operating revenues plus Realized gain (loss) on commodity derivatives.

(4) Adjusted Operating Cash Flow Margin is defined as Operating Cash Flow divided by Total operating revenues plus Realized gain (loss) on commodity derivatives.

(5) Earnings before interest, taxes, depletion and amortization (Adjusted EBITDA) is defined as Net income (loss) adjusted to add back interest, taxes, depletion and amortization and certain othernon-recurring ornon-cash charges. Management believes that thenon-GAAP measure of Adjusted EBITDA is useful as an indicator of an oil and gas exploration and production Company’s ability to internally fund exploration and development activities and to service or incur additional debt. Adjusted EBITDA should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.

(6) Adjusted EBITDA Margin is defined as Adjusted EBITDA divided by Total operating revenues plus Realized gain (loss) on commodity derivatives.

(7) For the twelve months and quarter ended December 31, 2019 and 2018, Other operating expenses and legal proceeding recoveries are considerednon-recurring items and are excluded from operating cash flow.

(8) Free Cash Flow is defined as Adjusted EBITDA less capital expenditures and cash interest expense

(9) Year-end PV10 may be considered anon-GAAP financial measure as defined by the SEC. We believe that this presentation ofpre-tax discounted present value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. The Company’syear-end 2019 PV10 valuation is expected to be of similar value to the standardized measure, the most directly comparable GAAP measure to be disclosed in the Company’s10-K, a result of there being no expected future tax impacts in the standardized measure calculation for the period.

(10) March 31, 2020 PV10 may be considered anon-GAAP financial measure as defined by the SEC. The Company’s March 31, 2020 unaudited PV10 valuation is expected to be of similar value to what the standardized measure would be as the most directly comparable GAAP measure, if it were to be disclosed.

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About Ultra Petroleum

Ultra Petroleum Corp. is an independent energy company engaged in domestic natural gas and oil exploration, development and production. The Company is listed on OTCQX and trades under the ticker symbol “UPLC”. Additional information on the Company is available atwww.ultrapetroleum.com. In addition, our filings with the Securities and Exchange Commission (“SEC”) are available by written request to Ultra Petroleum Corp. at 116 Inverness Drive East, Suite 400, Englewood, CO 80112 (Attention: Investor Relations) or on our website (www.ultrapetroleum.com) or from the SEC on their website atwww.sec.gov or by telephone request at1-800-SEC-0330.

This news release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Any statement, including any opinions, forecasts, projections or other statements, other than statements of historical fact, are or may be forward-looking statements. Although the Company believes the expectations reflected in any forward-looking statements herein are reasonable, we can give no assurance that such expectations will prove to have been correct and actual results may differ materially from those projected or reflected in such statements. There are numerous uncertainties inherent in estimating proved reserves, including projecting future rates of production and timing of development. In addition, certain risks and uncertainties inherent in our business as well as risks and uncertainties related to our operational and financial results are set forth in our filings with the SEC, particularly in the section entitled “Risk Factors” included in our Annual Report on Form10-K for the most recent fiscal year, our most recent Quarterly Reports on Form10-Q, and from time to time in other filings made by the Company with the SEC. Some of these risks and uncertainties include, but are not limited to, the Company’s ability to maintain adequate liquidity following the recent default under the terms of our Credit Agreement and Term Loan Agreement resulting from the going concern qualification to our audited, consolidated financial statements in our Annual Report on Form10-K, decrease its leverage or fixed costs, or restructure our balance sheet in a manner that allows us to continue as a going concern over the long term. Some additional risks and uncertainties include, but are not limited to, increased competition, the extreme volatility and negative pressure that oil and natural gas commodity prices have experienced recently that is attributable to decreased demand resulting from COVID and the actions of OPEC and other oil exporting nations, 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.

For further information contact:

Investor Relations

303-708-9740, ext. 9898

Email:IR@ultrapetroleum.com

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