INVESTOR PRESENTATION

D e c e m b e r 2 0 1 9

FORWARD LOOKING STATEMENTS & RISK FACTORS

Forward-Looking Statements and Reserve Estimates

This presentation contains "forward-looking statements" within the meaning of the federal securities laws, including statements about our business strategies and plans, plans for future drilling and resource development, prospective levels of capital expenditures and production and operating costs, and estimates of future results. Any statement in this presentation, including any opinions, forecasts, projections or other statements, other than statements of historical fact, are forward-looking statements. Although we believe the expectations reflected in such forward-looking statements are reasonable, we can give no assurance such expectations are correct, and actual results may differ materially from those projected. In addition, this presentation includes information about our proved reserves. The Securities and Exchange Commission ("SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible oil and gas reserves that meet the SEC's definitions for such terms. This presentation also includes information about oil and gas quantity estimates that are not permitted to be disclosed in SEC filings, including terms or designations such as "estimated ultimate recovery" or "EUR" or "resource" or "resource potential" or other terms bearing similar or related descriptions. These types of estimates do not represent and are not intended to represent any category of reserves based on SEC definitions, do not comply with guidelines established by the American Institute of Certified Public Accountants regarding forecasts of oil and gas reserves estimates, are, by their nature, more speculative than estimates of proved, probable and possible reserves disclosed in SEC filings, and, accordingly, are subject to substantially greater uncertainty of being actually realized. Actual volumes or quantities of oil and gas that may be ultimately recovered will likely differ substantially from such estimates. Factors affecting such ultimate recovery include the scope of our actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, and actual drilling, completion and production results as well as other factors. These estimates may change significantly as the development of properties provides additional data. This presentation also includes estimates of values attributable to the locations on which such oil and gas quantity estimates are based. The estimates of value set forth in this presentation were calculated based on the assumptions and methodologies set forth in this presentation, which differ materially from the assumptions and methodologies oil and gas companies are required to use in calculating PV-10 values of proved reserves disclosed in SEC filings. As a result, the estimates of values included in this presentation do not represent and are not intended to represent the "PV-10" value that would be attributable to such items if such items were calculated based on applicable SEC requirements.

Risk Factors

Certain risks and uncertainties inherent in our operating businesses as well as certain on-going risks 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 most recently-filed Annual Report on Form 10-K, our most recently-filed Quarterly Reports on Form 10-Q, and from time to time in other filings we make with the SEC. Some of the risks and uncertainties related to our business include, but are not limited to, our ability to decrease our 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, including from any horizontal wells we drill in the future, the timing and cost of our future production and development activities, our ability to successfully monetize the properties we are marketing, weather and government regulation, and the availability and cost of oil field services, personnel and equipment.

Investors are encouraged to review and consider the risk factors set forth in our historical and future SEC filings, as well as any set forth in this presentation, in connection with a review and consideration of this presentation. Our SEC filings are available directly from the Company - please send any requests to Ultra Petroleum Corp. at 116 Inverness Drive East, Suite 400, Englewood, CO 80112 (Attention: Investor Relations). Our SEC filings are also available from the SEC on their website at www.sec.gov.

Non-GAAP Measures

Net Debt, Adjusted EBITDA, Free Cash Flow, EBITDA Cash Costs and proved developed Coverage Metrics are financial measures not presented in accordance with generally accepted accounting principles ("GAAP"). The reconciliation of these non-GAAP financial measures to the most directly comparable GAAP measures can be found on slide 21-22 in the appendix to this presentation.

Ultra Petroleum Corp. OTCQX: UPLC

2

COMPANY OVERVIEW

OTCQX Symbol

UPLC

MARKET

Market Capitalization @ 11/29/19, $ million

$45

SNAPSHOT

Net Debt (1)@ 9/30/19, $ million

$1,988

Enterprise Value, $ million

$2,033

Pinedale

Field

PRODUCTION & RESERVES

3Q19 Production, Bcfe

60.2

SEC Proved Reserves(2), Bcfe

3,063

SEC Proved Developed Reserves, Bcfe

2,351

SEC Proved Developed PV-10, $ billion

$2.3

Net Acreage - Wyoming

~83,000

% Operated

92%

ACREAGE

% HBP

86%

Operated Producing Wells

~2,240

Future Drilling Locations

4,000+

  1. Net Debt is calculated as face value of debt less cash. Net Debt is anon-GAAP financial measure; see slide 22 for a reconciliation of this measure to the most directly comparable GAAP measure.
  2. YE18 proved reserves includes an operated PUD program of vertical development for 3 years with 3 rigs.

Ultra Petroleum Corp. OTCQX: UPLC

3

3Q19 ULTRA HIGHLIGHTS

❑Production averaged 654 MMcfe/d, at high end of guidance ❑Adjusted EBITDA(1)totaled $98 MM

Results

❑Total capital investment was $56.4 MM, reflecting improved DC&E costs and reduced activity

❑Controllable Cash Costs(2)of $0.40 per Mcfe

❑Successful DC&E cost reduction of approximately 12% to $2.8 MM per well

Operations

❑7 successful 2-string wellbores of 8 attempted in 3Q19

❑Drilling has been suspended as of mid-September

❑Reduced full year capital investment program to $240 - $250 MM

Financial

❑Achieved positive Free Cash Flow(1)of $5 MM in 3Q19

❑Amended the RBL Credit Facility to eliminate all maintenance financial covenants and established

Discipline

the fall borrowing base at $1.175 billion with unanimous approval from our RBL lenders

    • RBL Credit Facility balance outstanding at end of quarter of $64 MM
  2. Adjusted EBITDA and Free Cash Flow arenon-GAAP financial measures; see slide 21 to this presentation for a reconciliation of these measures to the most directly comparable GAAP measure.
  3. Controllable Cash Cost is defined as LOE and Cash G&A combined

(3)

Ultra Petroleum Corp. OTCQX: UPLC

4

3Q19 RESULTS

Controllable Cash Costs Performance Drives Strong EBITDA Result

3Q19 Results

Guidance

Actual

Production, MMcfe/d

635

-

655

654

$/Mcfe

$/Mcfe

Lease Operating Expense

0.27

-

0.31

0.30

Facility Lease Expense

0.10 - 0.12

0.11

Production Taxes(1)

0.24

-

0.30

0.24

Gathering Fees (gross)

0.31

-

0.35

0.33

Gathering Fees (net)(2)

0.27 - 0.31

0.29

Transportation

0.00 - 0.00

0.00

Cash G&A(3)

0.07

-

0.10

0.10

DD&A

0.85

-

0.90

0.82

Cash Interest

0.58 - 0.63

0.60

Total Expenses, with Gross Gathering Fees

$2.50

EBITDA Cash Costs(4), with Net Gathering Fees

$1.04

Controllable Cash Costs

Lease Operating Expense and Cash G&A ($/Mcfe)

0.34 - 0.41

0.40

3Q19 Adjusted EBITDA(4)

Actual

Revenue, incl. hedges, $/Mcfe

$2.67

EBITDA Cash Costs(4), $/Mcfe

($1.04)

Adjusted EBITDA(4), $/Mcfe

$1.63

Production, Bcfe

60.2

Adjusted EBITDA(4)

$98 million

Notes:

  1. 3Q19 Production Taxes based on physical sales with average realized prices of $2.04 per Mcf and $58.33 per Bbl
  2. Net Gathering Fees include proceeds from liquids processing
  3. Cash G&A excludes stock compensation and other non cash items
  4. Adjusted EBITDA and EBITDA Cash Costs arenon-GAAP financial measures; see slides 21 and 22 to this presentation for a reconciliation of these measures to the most directly comparable GAAP measures

Ultra Petroleum Corp. OTCQX: UPLC

5

CONTROLLABLE CASH COST PERFORMANCE

Continuous Drive to Appropriately Manage Controllable Cash Costs

Controllable Cash Costs per Mcfe

•

Focused on continuously improving controllable cash

$0.45

$0.40

costs with a long-term view of the future to drive

$0.40

favorable EBITDA margins

$0.35

$0.35

$0.34

•

Controllable Cash Costs

$0.30

•3Q19 Actuals were $0.40 / Mcfe

$0.25

•Full-Year Guidance at $0.37 - $0.41 / Mcfe

$0.20

$0.15

OPEX & Cash G&A per Mcfe

$0.10

$0.05

$1.80

$0.00

$1.60

$1.40

Q 1

Q 1

Q 2

Q 2

Q 3

Q 3

Actuals

$1.20

Guidance

$1.00

$0.80

  • Effective cost management focused on LOE and G&A is evidenced by our performance compared to gas weighted peers

$0.60

Median: $0.36

$0.40

$0.20

$-

Peer

Peer

Peer

Ultra

Peer

Peer

Peer

Peer

Peer

Note: Full-year 2018 data. Peer group includes: AR, CHK, COG, EQT, GPOR, QEP, RRC, and SWN

Ultra Petroleum Corp. OTCQX: UPLC

6

MANAGEMENT FOCUS ON EXECUTION

Strategic 2019 Objectives

  1. Continue to strengthen the balance sheet and enhance financial flexibility
  2. Maintain strong operating cash flow
  3. Disciplined deployment of capital with focus on investment returns in current commodity pricing environment
  4. Optimize base production and operating margins, concentrating on run time and lease operating expenses
  5. Enhance value of future drilling inventory through reduced well costs and improved return potential
  6. Continued horizontal resource validation

Operational Execution is The Key

Development of

Top Tier

Gas Asset

Low

Manage Pace

Expansion of

Controllable

of

Margin

Cash Costs

Development

  • ~83,000 net acres (92% operated)
  • Over 4,000 vertical locations
    within boundary of core development
  • Estimated annual EBITDA
    cash costs below $1.15 per Mcfe
  • Combined LOE and Cash G&A of approximately $0.40 per Mcfe
  • Suspended drilling in Sept'19 due to low price environment
  • Demonstrated ability to lower D&C well costs
  • YTD Adjusted EBITDA Margins of ~60%
  • Increased gas pricing and reduced costs create margin expansion

Ultra Petroleum Corp. OTCQX: UPLC

7

RESPONSIBLE MANAGEMENT OF CAPITAL PROGRAM FOCUSED ON INVESTMENT RETURNS

$/MMBtu

Free Cash Flow generation model can be used to repay debt or grow cash balance

  • Durable borrowing base given the nature oflow-decline,long-lived PDP reserve base
  • Reduced capital expenditures drives increased Free Cash Flow generation

$3.30

8/09: Further reduced rig count from 2 to 1

9/16: Announced that drilling program was

NYMEX HH

NWROX

in response to additional weakening of the

being suspended noting continued commodity

$3.10

forward natural gas strip. Increasing

price pressure on investment returns.

success with 2-string drilling design and

Preservation of future drilling inventory,

$2.90

outperformance of base production. Noted

generation of FCF and debt repayment.

ability to accelerate FCF result into the 3rd

Announced fall borrowing base and completion

quarter as a result of this decision

of 5thAmendment to Credit Facility

$2.70

$2.50

6/03: Reduced rig count from 3 to 2 citing

$2.30

weakening natural gas strip offset by ability to

take advantage of improved D&C performance

$2.10

and higher percentage of the drilling program

focused on 2-string well design; maintained

$1.90

annual production forecast

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Data points are 12-month strip as of the 1stof each month

Ultra Petroleum Corp. OTCQX: UPLC

8

LOW-DECLINE,LONG-LIVED ASSET BASE

Substantial and Durable Production Base From More Than 3,300 Wells

Ultra has produced more than 3.5 Tcf of gas and 26.5 million barrels of oil over its 22-year track record in the Pinedale

Ultra Net Production - Projected PDP Decline for 2020 of 19%

Estimated Annual Decline Rates

800

40%

700

35%

600

2015

2016

2017

2018

2019

2020

2019

30%

19%

25%

500

Decline

MMcfed

20%

400

Pre 2015 Onlines

15%

300

10%

200

5%

100

0%

16%

12%

10%

7%

0

1/2015

1/2016

1/2017

1/2018

1/2019

1/2020

Year 2

Year 3

Year 4

Final

Decline

Decline

Decline

Decline

Ultra Petroleum Corp. OTCQX: UPLC

9

WELL COSTS & 2-STRING WELLBORE DESIGNS

Focus on Technical and Design Improvements Drive Cost Trends Lower

Drilling Optimization and Focus on 2-String Design:

•7 successful 2-string wellbores of 8 attempted in 3Q19

100%

80%

•16 total successful 2-string wells drilled YTD for an average cost of $2.6 MM

60%

•Improvement in F&D costs of ~ 6%, net of reduced 2-string EUR

40%

$2.80

$2.86

20%

•Average savings on successful 2-string wells of $500K, a 16% reduction

$2.62

•Reservoir characterization project can enhance value of 2-string wells

0%

$3.4

2-String Design - Average Cost ($million)

$3.4

$3.1

$3.2

$2.9

$3.2

$MM

$3.0

With Contingencies

$MM

$3.0

$2.8

$2.8

$2.7

$2.6

$2.6

$2.6

Successful

$2.6

$2.6

$2.4

$2.4

1Q

2Q

3Q

2-String Design - Success Rate

88%

73%

50%

1Q

2Q

3Q

All 2019 Verticals - Average Cost ($million)

$3.2$3.2

$2.8

1Q

2Q

3Q

Ultra Petroleum Corp. OTCQX: UPLC

10

VERTICAL WELL PROGRAM

Improved Well Costs Drive Future Improvement in DC&E Economics

3Q19 Average IP = 5.8 MMcfe/d

Vertical Well Economics

EUR: 3.5 Bcfe

MMcf

500

EUR: 4.5 Bcfe

Production,

400

300

Cumulative

EUR: 2.9 Bcfe

200

Average

100

3Q19

1Q17 through 2Q19

0

0

50

100

150

Note: Assumes $60 per Bbl WTI oil price

Days on Production

Ultra Petroleum Corp. OTCQX: UPLC

11

HORIZONTAL PROJECT UPDATE

Advancing Pinedale Reservoir Characterization to Optimize Horizontal Opportunity

1H19 Results

  • Successfully integrated 3D seismic inversion data for predicting Lower Lance reservoir distribution
  • Integrated existing HZ wells into earth model and history matched production to predictpre-drill HZ well performance

2H19 Planned Activity

  • Building inventory ofhigh-graded HZ well locations, to provide opportunity and optionality for field appraisal and extension
  • Implementing workflow field wide, over 200- square miles; models also inform optimal well placement and design for vertical development

Future

  • Apply new workflows across Pinedale to further quantify extension of commercial resource from HZ wells and vertical inventory (all zones)
  • Refine inversion to identify highernet-to-gross areas in the Mesaverde and Lower Lance
  • Leverage expertise beyond Pinedale

Depth Structure Model

Sandstone Probability Model

Ultra Petroleum Corp. OTCQX: UPLC

12

FALL 2019 BORROWING BASE AT $1.175 BILLION

Fifth Amendment to the Credit Facility Executed in September

•Semi-annual redetermination, prepared consistently, based on mid-year

reserves as prepared by Netherland Sewell & Associates, Inc. under SEC

BORROWING BASE

reserve recognition criteria, and run at bank price deck

Credit Facility commitment established at $200 million from durable PDP

ESTABLISHED AT

•

$1.175 BILLION

reserves underpinned by low decline rates

•Commitment amount automatically reduces to $120 million in February 2020

POSITIVE FREE

•

Repayment of indebtedness

•

Capital investments of $5 million per quarter beginning in 2020

CASH FLOW

OBJECTIVES

•

Preserves drilling locations for more constructive future natural gas price

environment

PATHWAY TO PURSUE CAPITAL STRUCTURE IMPROVEMENTS

  • Recent amendment eliminates all financial maintenance covenants in the credit agreement
  • More flexible hedging requirements
  • Allows for the repurchase of indebtedness providing the outstanding RBL balance is at zero, that a sufficient cash reserve exists, and the 1stLien proforma leverage is <3.0x; subject to other Term Loan and 2ndLien Indenture terms

Ultra Petroleum Corp. OTCQX: UPLC

13

SEPTEMBER 30, 2019 - DEBT MATURITIES

Strong Coverage Metrics and No Near-Term Maturities

Cumulative Coverage Ratios(1)

Committed

Outstanding

RBL ($200 MM Commitment)

1stLien Term Loan

Borrowings

Borrowings

•

Outstanding: $64 MM

•

Outstanding: $971 MM

1stLien Debt

1.95x

2.20x

•

Maturity: April 2022

•

Maturity: April 2024(2)

2ndLien Notes

1.30x

1.41x

2022 Notes

1.20x

1.29x

2ndLien Notes

2025 Notes

1.07x

1.14x

•Outstanding: $581 MM

•Maturity: July 2024

No Near-Term Maturities

2022 Notes

2025 Notes

•

Outstanding: $150 MM

•

Outstanding: $225 MM

•

Maturity: April 2022

•

Maturity: April 2025

2019

2020

2021

2022

2023

2024

2025

Notes:

  1. Coverage ratios are calculated based onyear-end 2018 SEC proved developed reserves and debt commitments and balances as of September 30, 2019.
  2. 1st Lien Term Loan amortizes at a rate of 0.25% per quarter commencing June 2019.

Ultra Petroleum Corp. OTCQX: UPLC

14

HEDGE SUMMARY

As of December 6, 2019

Henry Hub Gas Volumes Hedged(1,2)

Oil Volumes Hedged

MMBtu/d

800

Average Price: $/MMBtu

600

400

200

0

4Q19

1Q20

2Q20

3Q20

4Q20

1Q21

Henry Hub Swaps

Henry Hub Collars

Henry Hub Puts

Bbl/d

4,000

Average Price: $/Bbl

3,000

$59.60

$60.42

2,000

$60.33

1,000

$60.00

0

4Q19

1Q20

2Q20

3Q20

4Q20

1Q21

NWROX Basis Hedged

MMBtu/d

800

Average Price: $/MMBtu

600

400

($0.45)

($0.07)

200

0

4Q19

1Q20

2Q20

3Q20

4Q20

1Q21

Q4 2019 Pricing with NYMEX & NWROX Hedges(3)

Henry Hub Hedges ($/MMBtu)

$2.77

NWROX Basis Hedges

($0.45)

Price per MMBtu

$2.32

BTU Factor

x1.07

Gas Hedge Realization per Mcf

$2.48

WTI Swap

$59.60

Realized Price per Mcfe*

$2.85

*Price per Mcfe based on 95% natural gas / 5% condensate mix.

(1)

Average prices for 2019 periods reflects swap pricing. Refer to the appendix on slide 23 for additional details on pricing and volume.

15

(2)

Put pricing reflects the inclusion of the deferred premium of ($0.125), ($0.114) and ($0.190) for 2Q20, 3Q20 and 4Q20 respectively.

(3)

For collars and deferred puts, the price used to calculate the average realized price for hedged volumes utilizes strip price as of 12/6/2019 if above a floor or below a ceiling.

PINEDALE INFRASTRUCTURE OVERVIEW

Opal Provides Multiple Take Away Options and Prices at a Premium

  • Realized price at a premium of $0.03 - $0.04 to Opal pool (NWROX)
  • Opal provides multiple take away options and premium prices
  • Ultra sells gas at NWROX basis location
  • NWROX strength relative to CIG
    • ~$0.58 stronger than CIG in Q4 2019
    • Historical CIG pressure has been driven by tight take away from DJ basin
    • NWROX trading into more stable western demand region and less susceptible to general weather risk than CIG
  • Full-year2019 NWROX at 99% of Henry Hub pricing
  • Development of Permian / Delaware natural gas pipelines relieves bid pressure against Rockies gas deliveries

NW Rockies vs. CIG vs. Dominion South

(as a % of Henry Hub)

96%

95%

94%

96%

94%

84%

94%

92%

54%

91%

87%

56%

88%

87%

72%

85%

77%

83%

99%

82%

85%

2013

2014

2015

2016

2017

2018

2019

NW Rockies

CIG

Dominion South

KINGSGATE

STANFIELD

MALIN

OPAL

OT/REX

Ruby

CIG

PGE

San

Juan

SoCal

Permian

Ultra Petroleum Corp. OTCQX: UPLC

16

2019 FULL-YEAR CAPITAL PLAN AND GUIDANCE

Capital Program = $240 - $250 MM (1)

Pinedale Operated Verticals

$205

- $210 MM

Pinedale Non Operated Verticals

$18

- $22 MM

Corporate Other

$17

- $18 MM

2019 Production Guidance

Full Year 2019, Bcfe

239 - 241

4Q19, MMcfe/d

590 - 610

Full Year 2019 Budgeted Activity Summary

Operated Vertical Wells, Gross / Net

71 / 70.3

Non Operated Vertical Wells, Gross / Net

22 / 7.3

2019 Expenses

4Q 2019

FY 2019

(per Mcfe)

Lease Operating Expense

$0.32 - 0.36

$0.28 - 0.30

Facility Lease Expense

$0.10 - 0.12

$0.10 - 0.12

Production Taxes(2)(3)

$0.25 - 0.29

$0.31 - 0.33

Gathering Fees, gross

$0.31 - 0.35

$0.32 - 0.34

Gathering Fees, net

$0.27 - 0.31

$0.28 - 0.30

Transportation Charges

$0.03 - 0.05

$0.00 - 0.02

Cash G&A(4)

$0.10 - 0.14

$0.09 - 0.11

DD&A

$0.81 - 0.85

$0.84 - 0.86

Cash Interest Expense(5)

$0.63 - 0.67

$0.60 - 0.62

  1. Capital Program reflects transition from three to zero rig program.
  2. Production taxes estimated for 4Q 2019 are based on projected forward NYMEX prices for the remainder of the year and realized prices for the periods reported to date per Bbl, less gathering fees.
  3. Production taxes estimated for FY 2019 are based on projected forward NYMEX prices for the remainder of the year and realized prices for the periods reported to date per Bbl, less gathering fees.
  4. Includes estimated severance costs for early retirement and staff reductions in conjunction with reduced drilling activity.
  5. Cash interest expense represents total interest expense excluding the amortization of deferred financing costs, issuance premium and PIK interest.

Ultra Petroleum Corp. OTCQX: UPLC

17

2020 AND FUTURE - PDP MODEL GENERATES SUBSTANTIAL FREE CASH FLOW

  • Production outlook under a PDP decline case
    • 2020 Preliminary Guidance of 182 - 192 Bcfe
    • Predictable 2021 and 2022 production model by applying estimated annual year 2 and year 3 decline rates of 16% and 12%, respectively
  • Capital expenditure of $5 million per quarter beginning in 2020
  • REX firm transport commitment - Monitor and enhance value with optionality to alternate markets and periodic capacity releases
  • LGS lease commitments are a fixed annual obligation
  • Cash Margins remain robust
    • Low controllable cash cost for LOE and G&A
    • Production taxes are variable at approximately 10 - 11% of gross revenues, excluding derivatives
    • Gathering fees are variable, and are incurred at a per Mcf rate
    • Total cash interest expense shrinks as debt is reduced
  • $240 million of potential make whole recovery

Ultra Petroleum Corp. OTCQX: UPLC

18

UPSIDE AND OPTIONALITY FOR ULTRA

Generating Free Cash Flow in Third & Fourth Quarters 2019

Management of Base Production and Operating Costs:

  • Low LOE and G&A expense maintains strong operating margin greater than 50%
  • 55,000 BWPD capacity water management system owned by company provides for low water expenses

Reduction in Vertical Well Costs:

  • Long track record of implementing new technology to reduce costs and cycle times
  • Recent success in design changes for wellbore construction and completion fluids provide additional cost reduction opportunities
  • Successful cost reduction of 12% in 3Q19 to approximately $2.8 MM per well benefits future well economics

Expand Resource with Horizontal Development:

  • Horizontal program has verified productive resource beyond the vertical boundary
  • Incremental data and analysis demonstrating ability to reduce uncertainty and unlocking future activity

Continued Improvement to Balance Sheet:

  • Up to $240 million of potential make whole recovery
    • In November 2019, the Fifth Circuit Court of Appeal's en banc review affirmed its reversal of the primary issue in Ultra's appeal
    • The case has been remanded to the Bankruptcy Court for further consideration of issues not initially ruled upon that were raised by Ultra

Improved Gas Price Realizations Generate Significant Increase to Drillable Inventory Locations and Cash Flow:

  • Can be achieved in the form of HHUB or NW Rockies basis improvements, or both
  • With improved well costs of $2.8 MM vertical inventory increases from 1,336 to 1,925 with price improvement from $2.50 to $2.75/MMBtu Opal
  • With 182 - 192 BCFE of annual production, a $0.25/MMBtu improvement generates approximately $35 million of additional cash flow on an unhedged basis

Ultra Petroleum Corp. OTCQX: UPLC

19

APPENDIX

RECONCILIATION OF ADJUSTED EBITDA, ADJUSTED EBITDA PER MCFE AND FREE CASH FLOW

Reconciliation of Earnings Before Interest, Taxes, Depletion and Amortization (unaudited)

All amounts expressed in US$000's

The following table reconciles net income (loss) as derived from the Company's financial information with earnings before interest, taxes, depletion, and amortization and certain other non-recurring or non-cash charges (Adjusted EBITDA)(1)and to Free Cash Flow(2), as defined below:

For the Quarter Ended

For the Nine Months Ended

September 30,

September 30,

2019

2018

2019

2018

Net income

$

11,513

$

18,563

$

109,294

$

45,502

Interest expense

32,372

38,382

98,074

111,934

Depletion and depreciation

49,581

49,672

157,003

151,954

Unrealized (gain) loss on commodity derivatives

6,570

11,018

(75,957 )

72,557

Deferred gain on sale of liquids gathering system

-

(2,638

)

-

(7,915

)

Stock compensation expense

750

1,424

2,271

11,547

Debt exchange expenses

-

-

1,822

-

Taxes

-

-

(169 )

442

Other expenses

8,896

3,422

26,621

4,275

Legal proceeding recoveries

(11,828 )

-

(13,467 )

-

Adjusted EBITDA (1)

$

97,854

$

119,843

$

305,492

$

390,296

Capital and PP&E expenditures, net of proceeds received

(56,413 )

(22,492 )

(233,578 )

(275,847 )

Cash interest expense

(36,403

)

(35,558

)

(109,647

)

(103,601

)

Free cash flow (2)

$

5,038

$

61,793

$

(37,733 )

$

10,848

Production (Mcfe)

60,159

67,534

184,853

210,731

Adjusted EBITDA per Mcfe

1.63

$

1.77

$

1.65

$

1.85

  1. Earnings before interest, taxes, depletion and amortization (Adjusted EBITDA) is defined as Net income (loss) adjusted to exclude interest, taxes, depletion and amortization and certain other non- recurring ornon-cash charges. Management believes that the non-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.
  2. Free Cash Flow defined as Adjusted EBITDA less capital expenditures and cash interest

Ultra Petroleum Corp. OTCQX: UPLC

21

RECONCILIATION OF EBITDA CASH COSTS AND NET DEBT

Reconciliation of EBITDA Cash Costs(1)

Reconciliation of Net Debt(2)

as of September 30, 2019

(thousands)

Total Debt

Revolving Credit Facility

$

64,000

Term Loan

$

971,194

Second Lien Notes

$

580,960

2022 Senior Unsecured Notes

$

150,439

2025 Senior Unsecured Notes

$

225,000

Total Face Value of Indebtedness

$

1,991,593

Less: Cash

$

3,365

Net Debt

$

1,988,228

  1. EBITDA cash costs include lease operating expense, facility lease expense, production taxes, gathering fees, net, transportation (if any) and cash G&A.
  2. Net Debt is calculated as face value of debt less cash.

Ultra Petroleum Corp. OTCQX: UPLC

22

SUMMARY OF THE HEDGES IN PLACE

As of December 6, 2019

Ultra Petroleum Corp. OTCQX: UPLC

23

Attachments

  • Original document
  • Permalink

Disclaimer

Ultra Petroleum Corporation published this content on 11 December 2019 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 11 December 2019 11:25:04 UTC