INVESTOR PRESENTATION · presentation for a reconciliation of these measures to the most directly comparable GAAP measures ... Peer group includes: AR, CHK, COG, EQT, GPOR, QEP, RRC,

AUGUST 2019

INVESTOR PRESENTATION

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 thanstatements 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, andactual 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 theirfilings 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 arenot 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 typesof 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 regardingforecasts 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 greateruncertainty 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 ofour 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. Thispresentation 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 assumptionsand 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 applicableSEC 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 “RiskFactors” 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 anduncertainties 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 areaswhere 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 horizontalwells 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 availabilityand 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 arealso available from the SEC on their website at www.sec.gov.

Non-GAAP Measures

Adjusted EBITDA, Net Debt, EBITDA Cash Costs and proved developed Coverage Metrics are financial measures not presented in accordance with generally accepted accounting principles (“GAAP”). The reconciliation of thesenon-GAAP financial measures to the most directly comparable GAAP measures can be found on slides 19 – 20 in the appendix to this presentation.

2Ultra Petroleum Corp. OTCQX: UPLC

COMPANY OVERVIEW

MARKET SNAPSHOT

OTCQX Symbol UPLC

Market Capitalization @ 7/31/19, $ million $31

Net Debt (1) @ 6/30/19, $ million $1,981

Enterprise Value, $ million $2,012

PRODUCTION& RESERVES

2Q19 Production, Bcfe 62.5

SEC Proved Reserves(2), Bcfe 3,063

SEC Proved Developed Reserves, Bcfe 2,351

SEC Proved Developed PV-10, $ billion $2.3

ACREAGE

Net Acreage — Wyoming ~83,000

% Operated 92%

% 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 a non-GAAP financial measure; see slide 20 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

PinedaleField

FOCUSED ON EXECUTION


1. Continue to strengthen the balance sheet2. Maintain strong operating cash flow3. Disciplined deployment of capital, evaluating commodity pricing and investment returns4. Optimize base production with continued emphasis on run times and lease operating expenses5. Enhance value of drilling inventory through reduced well costs 6. Continued horizontal resource validation

Strategic 2019 Objectives

Operational Execution is The Key

Development of Top Tier

Gas Asset

Low Controllable Cash Costs

Manage Pace of

DevelopmentExpansion of

Margin

• Demonstrated ability to flex program up or downquickly in response to price environment

• Adjusted EBITDA Margins of ~60%• Increased gas pricing and reduced

costs will create margin expansion

• Estimated annual EBITDA cash costs below $1.15 per Mcfe

• Combined LOE and G&A of approximately $0.40 per Mcfe

• ~83,000 net acres (92% operated)• Over 4,000 vertical locations

within boundary of core development

2Q19 RESULTS

Guidance Actual

Production, MMcfe/d 660 – 680 687

$/Mcfe $/Mcfe

Lease Operating Expense 0.28 - 0.32 0.25

Facility Lease Expense 0.10 - 0.12 0.11

Production Taxes(1) 0.26 - 0.32 0.26

Gathering Fees (gross)Gathering Fees (net)(2)

*0.27 - 0.31

0.330.29

Transportation 0.00 - 0.00 0.00

Cash G&A(3) 0.05 - 0.08 0.09

DD&A 0.80 - 0.88 0.89

Cash Interest 0.58 - 0.63 0.58

Total Expenses, with Gross Gathering Fees $2.47

EBITDA Cash Costs(4), with Net Gathering Fees $1.00

Actual

Revenue, incl. hedges, $/Mcfe $2.51

EBITDA Cash Costs(4), $/Mcfe ($1.00)

Adjusted EBITDA(4), $/Mcfe $1.51

Production, Bcfe 62.5

Adjusted EBITDA(4) $94.1 million

Notes:

(1) 2Q19 Production Taxes based on physical sales with average realized prices of $2.17 per Mcf and $59.65 per Bbl

(2) Net Gathering Fees include proceeds from liquids processing

(3) Cash G&A excludes debt exchange expense, stock compensation and other non cash items

(4) Adjusted EBITDA and EBITDA Cash Costs are non-GAAPfinancial measures; see slides 19 and 20 to this presentation for a reconciliation of these measures to the most directly comparable GAAP measures

*Only net guidance was provided for the period ending June 30, 2019

2Q19 Adjusted EBITDA(4)2Q19 Results

5

Controllable Cash Costs Performance Drives Strong EBITDA Margin

Ultra Petroleum Corp. OTCQX: UPLC

Lease Operating Expense and Cash G&A 0.33 – 0.40 0.34

Controllable Cash Costs

LOW-DECLINE, LONG-LIVED ASSET BASE


Substantial Production Base From More Than 2,240 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

0

100

200

300

400

500

600

700

800

1/2015 1/2016 1/2017 1/2018 1/2019

MMcfe/d

Pre 2015 Onlines

2015 2016 2017 2018 2019Year 1 Decline: 26%

Year 2 Decline: 16%

Year 3 Decline: 11%

Year 4 Decline: 9%

Final Decline: 7%

LOW COST, LOW DECLINE AND HIGH MARGINS

7

OPEX & Cash G&A per Mcfe

EBITDA Margin (%)

Corporate Base Decline Rates

Adjusted Operating Margins

0%

10%

20%

30%

40%

50%

60%

70%

80%

Peer Peer Peer Peer Peer Peer UPL Peer Peer

0%

10%

20%

30%

40%

50%

Peer Peer Peer Peer Peer Peer Peer UPL Peer

Peer group includes: AR, CHK, COG, EQT, GPOR, QEP, RRC, and SWN

$-

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

Peer Peer Peer UPL Peer Peer Peer Peer Peer

Median: 53%

Median: 24%

Median: $0.36

15%

20%

25%

30%

35%

Peer UPL Peer Peer Peer Peer Peer Peer Peer

Median: 32%


VERTICAL WELL PROGRAM

8

Focused on High-Graded Activity and Well Costs to Generate Returns

Vertical Well Economics2Q19 Average IP = 6.3 MMcfe/d

Ave

rag

e C

um

ula

tive

Pro

du

ctio

n,

MM

cf

Days on Production

Note: Assumes $60 per Bbl WTI oil price

0

100

200

300

400

500

0 50 100 150

1Q17 through 1Q19

2Q19


EUR: 4.5 Bcfe

EUR: 2.9 Bcfe

EUR: 3.5 BcfeEUR Bcfe 3.0 3.5 4.0 EUR

Bcfe 3.0 3.5 4.0 EUR Bcfe 3.0 3.5 4.0 EUR

Bcfe 3.0 3.5 4.0

$3.1 5% 10% 15% $3.1 8% 14% 20% $3.1 12% 18% 26% $3.1 15% 23% 31%

$2.9 7% 12% 18% $2.9 11% 17% 24% $2.9 14% 22% 30% $2.9 19% 27% 37%

$2.7 9% 15% 21% $2.7 13% 20% 28% $2.7 18% 26% 35% $2.7 22% 32% 43%

HHUB - ROX = $2.25/MMBtu




Cap

ex (

$M

M)

Cap

ex (

$M

M)

Cap

ex (

$M

M)

Cap

ex (

$M

M)

WELL COSTS & 2-STRING WELLBORE DESIGNS


$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

Q2 Vertical Well Costs ($MM)

$2.62

$3.19

$2.86

Focus on Technical and Design Improvements Drive Cost Trends Lower

Drilling Optimization:

• 8 successful 2-string wellbores constructed in Q2

• Expanded 2-string use with 11 wells attempted in Q2 after piloting with 2 attempts and 1 success in Q1

• Average savings on successful 2-string wells of $500K compared to our budget of $3.1 MM per vertical well

• Successful 2-string wells and contingency cost result in reduced average well cost over 3-string designs

2-String Development Optimization 8-25 Pad:

• 16% CAPEX reduction vs. 3-string design

• Estimated EUR reduction of 7% vs. 3-string design

• Net improvement in F&D costs of approximately 6%

• Reservoir characterization project can increase precision on placement of 2-string wells

26 wells 11 wells 8 wells

Q2 Average Well Cost

Average 2-String Program

Average Successful2-String


HORIZONTAL PROJECT UPDATE

1H19 Results

• Successfully integrated inversion data for predicting Lower Lance reservoir distribution

• Integrated existing HZ wells into earth model, used to history match production and predict pre-drill HZ well performance

2H19 Planned Activity

• Building inventory of high-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

Advancing Pinedale Reservoir Characterization to Optimize Horizontal Opportunity

Sandstone Probability Model

Depth Structure Model

NW ROCKIES BASIS HAS IMPROVED

NW Rockies basis has improved by 36% over the last 12 months

• Future 12-month average NW Rockies Basis is ($0.43)• Future basis, as of one year ago, was ($0.67)• Development of Permian / Delaware natural gas pipelines:

o Allows natural gas to flow to more natural regional delivery pointso Relieves bid pressure against western Rockies delivery points


-1.00

-0.80

-0.60

-0.40

-0.20

0.00

0.20

July August September October November December January February March April May June

NWROX Pricing ($/MMbtu)

PINEDALE INFRASTRUCTURE OVERVIEW


Opal Provides Multiple Take Away Options and Prices at a Premium

NWPL

Ruby

Kern River

El Paso – North Line

Transwestern

NW

PL

Trans Colorado

GTN

OT/REX

El Paso – CrossoverEl Paso – South Line

MALIN OPAL

PGE

SoCal

STANFIELD

KINGSGATE

San Juan

Permian

CIG

Transwestern

Ultra Petroleum Marketing:• Prices at $0.03 - $0.04 premium to Opal pool (NW Rockies)

• Opal provides multiple take away options and prices at a premium to CIG and Dominion South

• Improvement of NW Rockies Basis future strip of $0.24 on year-over-year comparison

• Development of Permian / Delaware natural gas pipelines allows natural gas to flow to more regionally proximal Gulf Coast delivery points and away from the Rockies delivery points, thereby relieving bid pressure

NW Rockies vs. CIG vs. Dominion South (as a % of Henry Hub)

96%

96%

94%

91%

88%

85% 99

%

95%

94%

92%

87%

87%

77%

83%94

%

84%

54%

56% 72

% 83%

88%

2013 2014 2015 2016 2017 2018 2019 YTDNW Rockies CIG Dominion South

Henry Hub Swaps

HEDGE SUMMARY

6-Month 2019 Pricing with NYMEX & NWROX Hedges(2)

Henry Hub Hedges ($/MMBtu) $2.76

NWROX Basis Hedges ($0.53)

Price per MMBtu $2.24

BTU Factor x1.07

Gas Hedge Realization per Mcf $2.40

WTI Swap $59.19

Realized Price per Mcfe* $2.77

Henry Hub Gas Volumes Hedged(1) Oil Volumes Hedged

NWROX Basis Hedged

0

200

400

600

800

3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21

MMBtu/d

Average Price: $/MMBtu

0

200

400

600

800

3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21

MMBtu/d

Average Price: $/MMBtu

0

1,000

2,000

3,000

4,000

5,000

3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 1Q21

Bbl/d

Average Price: $/Bbl

13

$2.75 $2.77

($0.55)

Updated through July 31, 2019 (see appendix slide 21 for more details)

$58.59 $59.88 $60.00

($0.17)($0.49)

(1) Average prices for 2019 periods reflects swap pricing. Refer to the appendix on slide 21 for additional details on pricing and volume.(2) For collars and deferred puts, the price used to calculate the average realized price for hedged volumes utilizes strip price as of 7/31/19 if above a floor or below a ceiling.

Otherwise, the appropriate floor or ceiling is utilized to calculate average price.

Henry Hub Collars Henry Hub Puts

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

$60.42 $60.33

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

2018 SEC PV-10 Net Debt 6/30/19 PV-10 less Net Debt

PER SHARE RESERVE VALUE

14

Focus on Driving Value


Indicative SEC Proved Reserves Value per Share

$12.15

($10.00)

Valuation ComponentsValue $/Share

2018 SEC Proved Developed PV-10 $2,405 Million $12.15

Net Debt (1) @ 6/30/19 ($1,981) Million ($10.00)

PV-10 less Net Debt $425 Million $2.15

Asset Base: Robust, Low Decline PDP Base with Favorable Operating Margins

Less

Balance Sheet: No Near-Term Maturities & Focused on Efforts to Further Reduce Debt

Focused on Driving Value

Working to Build Value From Both Sides of the Equation

PDPPUD

Boo

k Va

lue

$2.15

Book Value

(1) Net Debt is calculated as par value of debt less cash. Net Debt is a non-GAAP financial measure; see slide 20 for a reconciliation of this measure to the most directly comparable GAAP measure.

JUNE 30, 2019 – DEBT MATURITIES


Strong Coverage Metrics and No Near-Term Maturities

2019 2020 2021 2022 2023 2024 2025

RBL ($325 MM Commitment)• Outstanding: $59 MM • Maturity: April 2022

1st Lien Term Loan• Outstanding: $973 MM • Maturity: April 2024(2)

2nd Lien Notes• Outstanding: $578 MM • Maturity: July 2024

2022 Notes• Outstanding: $150 MM • Maturity: April 2022

2025 Notes• Outstanding: $225 MM • Maturity: April 2025

No Near-Term Maturities

Notes:(1) Coverage ratios are calculated based on year-end 2018 SEC proved developed reserves and debt commitments and balances as of June 30, 2019. (2) 1st Lien Term Loan amortizes at a rate of 0.25% commencing June 2019

Cumulative Coverage Ratios(1)

CommittedBorrowings

OutstandingBorrowings

1st Lien Debt 1.75x 2.20x

2nd Lien Notes 1.21x 1.41x

2022 Notes 1.12x 1.29x

2025 Notes 1.01x 1.15x

2019 FULL-YEAR CAPITAL PLAN AND GUIDANCE

(1) Capital Program reflects transition from three to one rig program(2) Production taxes estimated for 3Q 2019 are based on projected forward NYMEX prices of $2.22 per Mcf and $55.57 per Bbl, less gathering fees(3) Production taxes estimated for FY 2019 are based on projected forward NYMEX prices of $2.70 per Mcf and $56.09 per Bbl, less gathering fees(4) Cash interest expense represents total interest expense excluding the amortization of deferred financing costs, issuance premium and PIK interest

Capital Program = $260 - $290 MM (1)

Pinedale Operated Verticals $220 - $240 MM

Pinedale Non Operated Verticals $22 - $28 MM

Corporate Other $18 - $22 MM

2019 Production Guidance

Full Year 2019, Bcfe 238 – 244

3Q19, MMcfe/d 635 – 655

2019 Expenses(per Mcfe) 3Q 2019 FY 2019

Lease Operating Expense $0.27 - 0.31 $0.26 - 0.30

Facility Lease Expense $0.10 - 0.12 $0.10 - 0.12

Production Taxes(2)(3) $0.24 - 0.30 $0.30 - 0.34

Gathering Fees, grossGathering Fees, net

$0.31 - 0.35$0.27 - 0.31

$0.31 - 0.35$0.27 - 0.31

Transportation Charges $0.00 - 0.00 $0.00 - 0.01

Cash G&A $0.07 - 0.10 $0.08 - 0.11

DD&A $0.85 - 0.90 $0.85 - 0.90

Cash Interest Expense(4) $0.58 - 0.63 $0.58 - 0.62


Full Year 2019 Budgeted Activity Summary

Operated Vertical Wells, Gross / Net 73 / 72.3

Non Operated Vertical Wells, Gross / Net 26 / 7.3

UPSIDE AND OPTIONALITY FOR ULTRA

Management of Base Production and Operating Costs:• Low LOE and G&A maintains approximate 60% operating margin at $2.50/MMBtu Opal/NWROX

• 55,000 BWPD capacity water management system owned by company provides for low water expenses

Reduction in Vertical Well Costs:• Long track record of continuous utilization of technology to reduce costs and cycle times• Recent success in design changes for wellbore construction and completion fluids provide additional cost reduction opportunities

Expand Resource with Horizontal Development:• Horizontal program has verified productive resource beyond the vertical boundary

• Incremental data and analysis demonstrating ability to reduce uncertainty

Continued Improvement to Balance Sheet:• 2L debt exchange reduced debt by approximately $253 million and extended maturities

• Recent recovery of $13.5 million leaves up to $240 million of potential remaining make-whole recovery from the January decision by the 5th Circuit Court of Appeals

Improved Gas Price Realizations Generate Significant Increase to Inventory and Cash Flow:• Can be achieved in the form of HHUB or NW Rockies basis improvements, or both

• Vertical inventory increases from 1,200 to 1,750 with price improvement from $2.50 to $2.75/MMBtu Opal

• With 238 – 244 BCFE of annual production, a $0.25/MMBtu improvement generates over $55 million of additional cash flow on an unhedged basis


Expected to Generate Free Cash Flow in Third & Fourth Quarter 2019

APPENDIX

(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 or non-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.

RECONCILIATION OF ADJUSTED EBITDA AND ADJUSTED EBITDA PER MCFE


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):

For the Six Months Ended For the Quarter Ended June 30, June 30, 2019 2018 2019 2018

Net income $ 97,780 $ 26,933 $ 57,105 $ (20,555 ) Interest expense 65,703 73,552 32,376 37,715 Depletion and depreciation 107,422 102,282 55,768 51,742 Unrealized (gain) loss on commodity derivatives (82,527 ) 61,539 (68,234 ) 53,933 Deferred gain on sale of liquids gathering system — (5,276 ) — (2,638 ) Stock compensation expense 1,521 10,122 681 1,311 Debt exchange expenses 3,039 — 1,217 — Taxes (169 ) 442 (141 ) 9 Other expenses 16,085 853 15,281 639

Adjusted EBITDA (1) $ 208,854 $ 270,447 $ 94,053 $ 122,156 Production (Mcfe) 124,696 143,196 62,499 70,895 Adjusted EBITDA per Mcfe $ 1.67 $ 1.89 $ 1.50 $ 1.72

RECONCILIATION OF EBITDA CASH COSTS AND NET DEBT


Reconciliation of EBITDA Cash Costs (1)

(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.

Reconciliation of Net Debt(2)

as of June 30, 2019

(millions) Total Debt

Revolving Credit Facility 59.00$ Term Loan 973.25$ Second Lien Notes 578.07$ 2022 Senior Unsecured Notes 150.44$ 2025 Senior Unsecured Notes 225.00$ Total Face Value of Indebtedness 1,985.76$

Less: Cash 5.19$

Net Debt 1,980.57$

Total production (MMcfe) 62,499

('000) ($ / Mcfe)

Lease operating expense 15,889$ 0.25$

Facility lease expense 6,543$ 0.11$

Production taxes 16,443$ 0.26$

Gathering fees 20,320$ 0.33$ Less: Other revenues (2,190) (0.04) Gathering fees, net 18,130$ 0.29$

General and administrative expenses 7,433$ 0.12$ Less : Debt exchange expense (1,217)$ (0.02)$ Less: Stock compensation expense (681) (0.01) Cash G&A 5,535$ 0.09$

EBITDA Cash Cost/Mcfe 1.00$

For the Quarter ended June 30, 2019

SUMMARY OF THE HEDGES IN PLACE Updated through July 31, 2019


2021Q3 Q4 Q1 Q2 Q3 Q4 Q1

Natural Gas Swaps:Volume (MMbtu/d) 412,228 355,000 270,000 - - - - NYMEX ($/MMBtu) 2.75$ 2.77$ 2.78$ -$ -$ -$ -$

Natural Gas Collars:Volume (MMbtu/d) 15,000 15,000 130,000 236,000 175,000 290,000 80,000 NYMEX Floor ($/MMBtu) 2.80$ 2.90 2.78$ 2.35$ 2.41$ 2.44 2.46$ NYMEX Ceiling ($/MMBtu) 3.10$ 3.15 3.23$ 2.83$ 2.85$ 2.91 3.05$

Natual Gas Puts:Volume (MMbtu/d) - - - 114,000 160,000 30,000 - NYMEX Put Price ($/MMBtu) -$ -$ -$ 2.35$ 2.41$ 2.44$ -$

Oil Swaps: Volume (Bbl/d) 4,000 3,500 2,500 1,500 1,000 - - NYMEX ($/Bbl) 58.59$ 59.88 60.42$ 60.33$ 60.00$ -$ -$

Natural Gas Basis Swap Contracts *:NW Rockies Volume (MMBtu/d) 420,000 296,793 158,187 - - - - Price Differentials ($MMBtu) (0.55)$ (0.49)$ (0.17)$ -$ -$ -$ -$

* Represents swap contracts that fix the basis differentials for natural gas sold at or near Opal, Wyoming

2019 2020

Documents

INVESTOR PRESENTATION · presentation for a reconciliation of these measures to the most directly comparable GAAP measures ... Peer group includes: AR, CHK, COG, EQT, GPOR, QEP, RRC,