2q18 Earnings Conference Call...Note: Full-year 2018 data. Peer group includes: AR, CHK, COG, EQT,...

December 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 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.

2Ultra Petroleum Corp. OTCQX: UPLC

COMPANY OVERVIEW

MARKET SNAPSHOT

OTCQX Symbol UPLC

Market Capitalization @ 11/29/19, $ million $45

Net Debt (1) @ 9/30/19, $ million $1,988

Enterprise Value, $ million $2,033

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

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 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

PinedaleField

3Q19 ULTRA HIGHLIGHTS

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

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

4

Results

Operations

FinancialDiscipline

❑ Production averaged 654 MMcfe/d, at high end of guidance

❑ Adjusted EBITDA(1) totaled $98 MM

❑ 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

❑ 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

Ultra Petroleum Corp. OTCQX: UPLC

(1) Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures; see slide 21 to this presentation for a reconciliation of these measures to the most directly comparable GAAP measure.(2) Controllable Cash Cost is defined as LOE and Cash G&A combined

(3)

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)Gathering Fees (net)(2)

0.31 – 0.350.27 - 0.31

0.330.29

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

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 are non-GAAPfinancial measures; see slides 21 and 22 to this presentation for a reconciliation of these measures to the most directly comparable GAAP measures

3Q19 Adjusted EBITDA(4)3Q19 Results

5

Controllable Cash Costs Performance Drives Strong EBITDA Result


Lease Operating Expense and Cash G&A ($/Mcfe) 0.34 – 0.41 0.40

Controllable Cash Costs

6

• Focused on continuously improving controllable cash costs with a long-term view of the future to drive favorable EBITDA margins

• Controllable Cash Costs • 3Q19 Actuals were $0.40 / Mcfe• Full-Year Guidance at $0.37 - $0.41 / Mcfe

Continuous Drive to Appropriately Manage Controllable Cash Costs

CONTROLLABLE CASH COST PERFORMANCE


ActualsGuidance

Controllable Cash Costs per Mcfe

OPEX & Cash G&A per Mcfe

$-

$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: $0.36

Ultra

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

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

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

Q1 Q1 Q2 Q2 Q3 Q3

$0.40

$0.34$0.35

MANAGEMENT FOCUS ON EXECUTION


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

Strategic 2019 Objectives

Operational Execution is The Key

Development of

Top Tier

Gas Asset

Low Controllable Cash Costs

Manage Pace of

Development

Expansion of Margin

• 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

• Estimated annual EBITDA cash costs below $1.15 per Mcfe

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

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

within boundary of core development

$1.90

$2.10

$2.30

$2.50

$2.70

$2.90

$3.10

$3.30

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

NYMEX HH NWROX

RESPONSIBLE MANAGEMENT OF CAPITAL PROGRAM FOCUSED ON INVESTMENT RETURNS

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

• Durable borrowing base given the nature of low-decline, long-lived PDP reserve base

• Reduced capital expenditures drives increased Free Cash Flow generation


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

6/03: Reduced rig count from 3 to 2 citing weakening natural gas strip offset by ability to take advantage of improved D&C performance and higher percentage of the drilling program focused on 2-string well design; maintained annual production forecast

8/09: Further reduced rig count from 2 to 1 in response to additional weakening of the forward natural gas strip. Increasing success with 2-string drilling design and outperformance of base production. Noted ability to accelerate FCF result into the 3rd

quarter as a result of this decision

9/16: Announced that drilling program was being suspended noting continued commodity price pressure on investment returns. Preservation of future drilling inventory, generation of FCF and debt repayment. Announced fall borrowing base and completion of 5th Amendment to Credit Facility

$/M

MBtu

19% Decline

0

100

200

300

400

500

600

700

800

1/2015 1/2016 1/2017 1/2018 1/2019 1/2020

MM

cfed

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%

Pre 2015 Onlines

20192015 2016 2017 2018 2019

Estimated Annual Decline Rates

16%

12%10%

7%

0%

5%

10%

15%

20%

25%

30%

35%

40%

Year 2Decline

Year 3Decline

Year 4Decline

FinalDecline

2020

$3.1

$2.9

$2.7

$2.6 $2.6 $2.6$2.4

$2.6

$2.8

$3.0

$3.2

$3.4

1Q 2Q 3Q

$M

M

2-String Design - Average Cost ($million)

WELL COSTS & 2-STRING WELLBORE DESIGNS


$2.62$2.80 $2.86

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

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

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

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

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

With Contingencies

Successful

50%

73%

88%

0%

20%

40%

60%

80%

100%

1Q 2Q 3Q

2-String Design - Success Rate

$3.2 $3.2

$2.8

$2.4

$2.6

$2.8

$3.0

$3.2

$3.4

1Q 2Q 3Q

$M

M

All 2019 Verticals - Average Cost ($million)

0

100

200

300

400

500

0 50 100 150

VERTICAL WELL PROGRAM

11

Improved Well Costs Drive Future Improvement in DC&E Economics

Vertical Well Economics3Q19 Average IP = 5.8 MMcfe/d

Averag

e C

um

ula

tive P

ro

du

cti

on

, M

Mcf

Days on Production

Note: Assumes $60 per Bbl WTI oil price 1Q17 through 2Q19

3Q19


EUR: 4.5 Bcfe

EUR: 2.9 Bcfe

EUR: 3.5 Bcfe


HORIZONTAL PROJECT UPDATE

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 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

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 higher net-to-gross areas in the Mesaverde and Lower Lance

• Leverage expertise beyond Pinedale

Advancing Pinedale Reservoir Characterization to Optimize Horizontal Opportunity

Sandstone Probability Model

Depth Structure Model

FALL 2019 BORROWING BASE AT $1.175 BILLION


Fifth Amendment to the Credit Facility Executed in September

BORROWING BASE ESTABLISHED AT $1.175 BILLION

POSITIVE FREE CASH FLOW OBJECTIVES

PATHWAY TO PURSUE CAPITAL STRUCTURE IMPROVEMENTS

• Semi-annual redetermination, prepared consistently, based on mid-year reserves as prepared by Netherland Sewell & Associates, Inc. under SEC reserve recognition criteria, and run at bank price deck

• Credit Facility commitment established at $200 million from durable PDP reserves underpinned by low decline rates

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

• Repayment of indebtedness

• Capital investments of $5 million per quarter beginning in 2020

• Preserves drilling locations for more constructive future natural gas price environment

• 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 1st Lien proforma leverage is <3.0x; subject to other Term Loan and 2nd Lien Indenture terms

SEPTEMBER 30, 2019 – DEBT MATURITIES


Strong Coverage Metrics and No Near-Term Maturities

2019 2020 2021 2022 2023 2024 2025

RBL ($200 MM Commitment)• Outstanding: $64 MM • Maturity: April 2022

1st Lien Term Loan• Outstanding: $971 MM • Maturity: April 2024(2)

2nd Lien Notes• Outstanding: $581 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 September 30, 2019. (2) 1st Lien Term Loan amortizes at a rate of 0.25% per quarter commencing June 2019.

Cumulative Coverage Ratios(1)

CommittedBorrowings

OutstandingBorrowings

1st Lien Debt 1.95x 2.20x

2nd Lien Notes 1.30x 1.41x

2022 Notes 1.20x 1.29x

2025 Notes 1.07x 1.14x

Henry Hub Swaps

HEDGE SUMMARY

Henry Hub Gas Volumes Hedged(1,2) Oil Volumes Hedged

NWROX Basis Hedged

0

200

400

600

800

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

MMBtu/d

Average Price: $/MMBtu

0

200

400

600

800

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

MMBtu/d

Average Price: $/MMBtu

0

1,000

2,000

3,000

4,000

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

Bbl/d

Average Price: $/Bbl

15

($0.45)

As of December 6, 2019

$59.60

$60.42

($0.07)

(1) Average prices for 2019 periods reflects swap pricing. Refer to the appendix on slide 23 for additional details on pricing and volume.(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.Otherwise, the appropriate floor or ceiling is utilized to calculate average price.

Henry Hub Collars Henry Hub Puts

$60.33

$60.00

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.

PINEDALE INFRASTRUCTURE OVERVIEW


Opal Provides Multiple Take Away Options and Prices at a Premium

Ruby

OT/REX

MALIN OPAL

PGE

SoCal

STANFIELD

KINGSGATE

San

Juan

Permian

CIG

• 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-year 2019 NWROX at 99% of Henry Hub pricing

• Development of Permian / Delaware natural gas pipelines relieves bid pressure against Rockies gas deliveries

96%

96%

94%

91%

88%

85% 99%

95%

94%

92%

87%

87%

77%

82%

94%

84%

54%

56% 72%

83%

85%

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

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

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

2019 Expenses(per Mcfe)

4Q 2019 FY 2019

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, grossGathering Fees, net

$0.31 - 0.35$0.27 - 0.31

$0.32 - 0.34$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


Full Year 2019 Budgeted Activity Summary

Operated Vertical Wells, Gross / Net 71 / 70.3

Non Operated Vertical Wells, Gross / Net 22 / 7.3

(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.

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


UPSIDE AND OPTIONALITY FOR ULTRA

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


Generating Free Cash Flow in Third & Fourth Quarters 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.

(2) Free Cash Flow defined as Adjusted EBITDA less capital expenditures and cash interest

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

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 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$


SUMMARY OF THE HEDGES IN PLACE As of December 6, 2019

2q18 Earnings Conference Call...Note: Full-year 2018 data. Peer group includes: AR, CHK, COG, EQT,...

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Transcript of 2q18 Earnings Conference Call...Note: Full-year 2018 data. Peer group includes: AR, CHK, COG, EQT,...