2Q17 Earnings Presentation August 02, 2017 Important Disclosures - - PowerPoint PPT Presentation

August 02, 2017

2Q17 Earnings Presentation

Important Disclosures

Forward-Looking Statements

This presentation contains projections and other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act

• f 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance as of this date. No assurances can be given,

however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. For a summary

• f events that may affect the accuracy of these projections and forward-looking statements, see “Risk Factors” in our Form 10-K for the year ended December 31, 2016 filed with the

Securities and Exchange Commission (the “SEC”). SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES This presentation includes non-GAAP measures, such as Adjusted EBITDA, Adjusted Income, Adjusted Income per diluted share, Adjusted G&A and other measures identified as non-GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash

• perating items. Adjusted EBITDA is not a measure of net income as determined by United States generally accepted accounting principles (‘‘GAAP’’).

Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of

• ur operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as

a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our presentation of Adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. We believe that the non-GAAP measure of Adjusted income available to common shareholders (“Adjusted Income”) and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted income and Adjusted income per diluted share below were computed in accordance with GAAP. Adjusted general and administrative expense (“Adjusted G&A”) is a supplemental non-GAAP financial measure that excludes certain non-recurring expenses and non-cash valuation adjustments related to incentive compensation plans. We believe that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure

• f our recurring G&A expense and provides for greater comparability period-over-period. The Appendix table details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.

For a reconciliation of non-GAAP measures to their most directly comparable GAAP measure, please see schedules included in the Appendix.

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Important Disclosures

Reserve-Related Disclosures

Cautionary Note to U.S. Investors: The Securities and Exchange Commission (“SEC”) prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. This presentation discloses estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by the Company. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 1401 Enclave Pkwy, Ste 600, Houston, TX 77077, Attention: Investor Relations, and the Company’s website at www.callon.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery” (or “EUR”) that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves, and accordingly are subject to substantially greater risk of being realized by the Company. EUR estimates and potential horizontal well locations have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from the Company’s estimates. There is no commitment by the Company to drill all of the potential horizontal drilling locations. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, commodity price levels, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of type/decline curves and per-well EURs may change significantly as development of the Company’s oil and gas assets provides additional data. Type/decline curves, estimated EURs, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from existing drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, recovery factors and costs prove correct. As a result, such estimates may change significantly as results from more wells are evaluated. Estimates of EURs do not constitute reserves, but constitute estimates of contingent resources that the SEC has determined are too speculative to include in SEC filings. Unless otherwise noted, Internal Rate of Return (or “IRR”) and Net Present Value (or “NPV”) estimates are before taxes and assume Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic, G&A or other corporate level costs. Investors are urged to consider closely the disclosure in our Form 10-K and other reports filed with the SEC, available on our website or by request by contacting Investor Relations: Callon Petroleum Company, 1401 Enclave Parkway, Suite 600, Houston, TX 77077. You may also email the Company at ir@callon.com. You can also obtain our Form 10-K and other reports filed with the SEC by contacting the SEC directly at 1-800-SEC-0330 or by downloading it from the SEC’s web site http://www.sec.gov.

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Callon Petroleum

4

2017 Activity in All Core Areas 2Q17 Highlights

FINANCIAL RESULTS

• Q/Q production growth of 9% driven

primarily by oil volumes

– Oil mix of ~79% (17,538 Bbl/d)

• 15% sequential reduction in per-unit

LOE; on track to meet FY17 target

• Adj. EBITDA margin of ~73% (1)

OPERATIONAL RESULTS

• WildHorse: WC A delineated across entire

Howard Co. position

• Spur: Solid WC A and WC B DUC results

demonstrate potential with visibility to enhancement via operated program

• Monarch: Successful LSBY well density

pilots support 13 WPS; (Locations: +15%)

2H17 & FY18 OUTLOOK

• Arrival of 4th rig in July to initiate
• perated Delaware Basin program
• Unchanged plan to add a 5th rig in

1Q18

– Now directed to Delaware

• Reiterating 2018 exit rate of 40 MBoe/d

Delaware Basin

Spur Ranger Monarch WildHorse

Midland Basin

1) See the non-GAAP related disclosures in the Appendix.

5

Near-Term Execution

2Q17

• Development activity in all four core operating

areas

• WildHorse development expanded to Central

Howard County

• Initial benefits from infrastructure positively

impacting LOE

1) Source: BMO Capital Markets, “Staring Contest” published 7/12/17. Peers include APA, CXO, CVX, ECA, EGN, EPE, FANG, LPI, OXY, PE, PXD, QEP, RSPP, SM, XOM.

Forecasting 40% Production Growth for 2017

78% 79% 5 10 15 20 25 30 35 1Q17 2Q17 3Q17E 4Q17E Mboe/d MBoe/d % Oil

Per Well 12 Month Cumulative Production (1)

0.0 5.0 10.0 15.0 20.0 25.0 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 CPE Peer 14 Peer 15 Boe 16:1/ft

(2015-2017 wells)

3Q17

• Addition of fourth rig, which arrived at Spur in

July

• Addition of 2nd dedicated frac fleet to support

program development

• WildHorse infrastructure projects substantially

complete

4Q17

• Initial production impact from Spur (10,000 ft

lateral development)

• WildHorse production benefitting fully from

infrastructure and debottlenecking

• Initial results from re-emergence of activity in

Ranger

0% 2% 4% 6% 8% 10% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 CPE

Growth Plan

1) Operating cash flow excluding working capital and phatom settles less total capex. 2) Source: BMO Capital Markets, “Staring Contest” published 7/12/17. Peers include CDEV, CXO, EGN, FANG, PE, RSPP.

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Philosophy Resilient Baseline of Growth (1)

($100) ($50) $0 $50 $100 1H18 2H18 1H19 2H19 Free Cash Flow ($MM) $50 - $55 Band

~35% CAGR from 2017 to 2019 on 5-rig Baseline

2 4 6 10,000 20,000 30,000 40,000 50,000 2017 2018 2019 Baseline # of Rigs Daily Net Production (Boe/d)

2018 Expected Return on Capital Employed (2)

• Baseline program designed to provide ongoing visibility for

near-term cash flow neutrality

• Activity levels biased upward, not downward, given

measured pace of rig additions

• Robust production growth potential without sacrificing

corporate-level returns given breadth of quality inventory and cost structure

• Resilient activity through volatile short-term cycles in a re-

balancing oil market

Free Cash Flow visibility to accelerate beyond 5 rigs CPE ROCE nearly double peer average Upside potential with additional rigs

Operational Update

7

Highlights LOE (including Gathering & Treating) Net Wells Spud: Geographic Breakdown (2)

80% 84% 37% 35% 26% 14% 16% 21% 51% 20% 16% 0% 20% 40% 60% 80% 100% 1Q17 2Q17 3Q17E 4Q17E WildHorse Spur Monarch Ranger

Net Completions: Quarterly Progression (1)

6.6 9.7 11.0 14.0 5 10 15 1Q17 2Q17 3Q17E 4Q17E

• 2nd consecutive quarter with LOE reduction (2Q results
• ver 10% below low end of guidance)
• 9.7 net completions during 2Q17 and on pace to

complete ~42 net wells in 2017

• Operated Delaware Basin program initiated in July

– Currently 3 Midland and 1 Delaware – Starting with 2 single-well pads in L WC A before moving to multi-well pad development

1) 3Q17E and 4Q17E based on midpoint of guidance. 2) Operated Callon wells.

$0 $2 $4 $6 $8 1Q17 2Q17 $/Boe Saltwater disposal Fuel & power Repairs & maintenance Gathering & treating Downhole Jobs / Workover Other LOE

• Program development in full stride

– Two dedicated drilling rigs at WildHorse – Three target zones

• Continued exceptional performance in WC A

– Easternmost and southernmost delineation wells tracking 1 MMBoe type curve

WildHorse WC A: Program Development Progresses South

1) Peak 24-hour rate observed to date during flowback period. 2) Papagiorgio 33-40B #01WA is a non-operated well in which Callon holds a minority working interest.

8

Infrastructure Progress Recent WC A Well Activity Expanding to Fairway Development

Fairway

1 2 Well Zone Lateral Peak-to-Date (1)

Colonial Unit 01AH WC A 7,802’ 1,471 Boe/d Colonial Unit 02AH WC A 7,802’ 1,635 Boe/d Wyndham Unit 01AH WC A 10,000’ 1,177 Boe/d Wyndham Unit 02AH WC A 10,000’ 1,614 Boe/d Papagiorgio 33-40B #01WA (2) WC A 10,000’ 1,500+ Boe/d

4 4 3 5

100%

Complete

100%

Complete

75%

Complete Gathering, Processing & Takeaway Gathering & Takeaway (Pipeline)

Oil Gas Water

WC A successfully delineated across the North-South and East-West extents of CPE’s Howard Co. position, with results throughout tracking or exceeding a 1MMBoe type curve

1 2 3 4 5

Fairway water gathering corridor SWD Capacity

• Operated LSBY wells to date have tracked acquisition type curve
• WildHorse LSBY have exhibited flat production profiles (similar to

Monarch)

• Initiatives to accelerate ramp to peak:

– Optimized completion design with increased near-wellbore focus and more control over frac height (lower sand and fluid loading; employing diverters) – Infrastructure build-out increases peak fluid capacity, accelerating de- watering of formation and early-time oil cut ramp

WildHorse LSBY: Established Base with Upside

1) Garrett-Snell Unit B 36-25 08SH is a non-operated well in which Callon holds a minority working interest.

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YTD 2017 Lower Spraberry Wells Lower Spraberry PDPs Tracking Acquisition Type Curve Commentary

Well IP24 IP30

Wright-Adams Unit 31-42 07SH 750 Boe/d 522 Boe/d Cheek Unit 28-21 09SH 725 Boe/d 572 Boe/d Garrett-Reed Unit 37-48 09SH 829 Boe/d 635 Boe/d Garrett-Snell Unit B 36-25 08SH (1) 1,107 Boe/d 889 Boe/d

1 2 4 3 Sidewinder Maverick Fairway Returning to both Maverick and Sidewinder in 3Q17 to complete Lower Spraberry wells with updated stimulation design 1 2 3 4 20 40 60 80 100 120 140 1 2 3 4 5 6 7 8 9 Cumulative Production (MBoe) Month Average (8 wells) 850 MBOE

50 100 150 Corbets (L WC A) Saratoga (WC B) MBo per 1,000’ Completed Lateral Acquisition Type Curve Acquired Wells EUR

Spur: Optimizing Completions

1) Based on unaudited, internal mid-year reserve report as of July 11, 2017.

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Optimizing Landing Zones for Operated Wells Acquired Wells Tracking Acquisition Type Curves (1) Optimizing Operated Completion Design

U WC A

~50’ lower

L WC A

~60’ lower

CPE Previous Operators

3BS Sand WC B

~55’ higher

L WC A L WC B

11,000’ 11,500’ 12,000’

7,500’ TC: 900 MBoe 7,500’ TC: 1.6 MMBoe GR Δ Log R

Previous Operator Design Callon Design Fluid Type Slickwater Slickwater Stage Spacing (ft.) 125 200 # of Clusters 8 10 - 12 Proppant Loading (lbs. / ft.) ~2,800 ~2,000 Fluid Loading (Bbls / ft.) ~75 ~60 Diverter Employed Yes Yes

Callon operated completions to employ a high-density, near- wellbore design

Monarch: Organic Inventory Replacement

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Pilot Programs Prove 13-Well Spacing in LSBY

Lower LSBY – Consistently Improving Infill Results (2) Upper LSBY – Outperforming in 13 Well Density Pilots

Current 13 WPS Upper/Lower LSBY Spacing

• Results from 2 key sets of tests reinforce optimal LSBY

density at Monarch as 13 wells per section on stack/stagger pattern – Successful full development of Lower LSBY flow unit at Casselman 8 – Four distinct 3-well pads across Monarch testing Upper LSBY and Lower LSBY on 13 wells per section spacing

• Results increased Monarch LSBY inventory by ~15%
• 10+ rig years (1) of remaining inventory in Monarch LSBY

50 100 150 200 250

1 2 3 4 5 6 7 8 9 10 11 12 Cumulative Production (MBoe) Month Pad 1 (2015) Pad 2 (2016) Pad 3 (2017) 1,000 MBoe 800 MBoe 50 100 150 200 250 1 2 3 4 5 6 7 8 9 10 11 12 Month UL (Cass 10) UL (Cass 40) LL 1 (Cass 10) LL 2 (Cass 10) LL 1 (Cass 40) LL 2 (Cass 40) 1,000 MBoe 800 MBoe

1) Based on spud-to-spud cycle time assumption of 15 wells per rig per year. 2) Years in parentheses next to “Pad X” reflect dates of completion and flowback for each respective pad.

Casselman 8 – full section development of a single flow unit over time

• Recent offset results yielding meaningfully higher early-

time rates

• First two Callon-operated L WC B wells since 2015

exploiting latest completion techniques

• Strong WC C prospectivity across Ranger points to

significant upside potential

Ranger: Additional Upside Emerging

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Performance Step Change in Recent Area Wells

Well Zone IP30/1000’ (1)

CPE

Eaglehead A 01LH L WC B Flowing Back Eaglehead A 02LH L WC B Flowing Back Turner AR Unit B #8HK L WC B 171 Boe/d

Peers

Taylor 45-33 460IH WC C 302 Boe/d Stiles 9-26 1HB L WC B 238 Boe/d Hamman 30 #1HM L WC B 268 Boe/d University 3-19#30H WC A 152 Boe/d State Carter #1HB U WC B 130 Boe/d Hartgrove 22 #1HM U WC B 136 Boe/d LSBY Shale

Dean

WC A WC B L WC B WC C WC D/Cline

7,500’ 8,000’ 8,500’ 9,000’ 9,500’ 10,000’

1 2 3 4 5 6 7 8 9 8 9 6 5 4 7 1 2 3

GR Δ Log R

1) Sources: DrillingInfo and peer investor presentations.

2Q17 Summary Results

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Revenue Drivers Cash Operating Expenses Reduced 13% Q/Q

$5.70 $6.61 $5.56 $2.92 $2.43 $2.67 $2.01 $3.21 $2.38 $0 $5 $10 $15 2Q16 1Q17 2Q17 $/Boe LOE Gathering Adj Cash G&A Production Taxes 13.5 20.4 22.2 $36.88 $44.27 $40.71 $0 $20 $40 $60 5 10 15 20 25 2Q16 1Q17 2Q17 $/Boe MBoe/d Production Unhedged Realized Price

Cash Generation ($/Boe)

$28.90 $34.02 $32.32 $14.30 $30.20 $31.67 $0 $10 $20 $30 $40 2Q16 1Q17 2Q17 $/Boe Operating Margin Cash Operational CAPEX

• Unhedged revenue per Boe benefits from best-in-class
• il content and pipeline offtake
• Total cash costs of $11.06 per Boe (including G&A)
• Strong operating margins continued to minimize cash

flow outspend in volatile price environment

• Internal operating margins in excess of capital

expenditures

1) See the non-GAAP related disclosures in the Appendix. 2) Operational capital includes drilling and completion, facilities, land and seismic. Presented on a cash basis.

(2) (1)

Financial Positioning

1) Assumes elected commitment amount of $500 MM. 2) At issuance as of May 19, 2017. 3) Net Debt at June 30, 2017 divided by annualized 2Q17 Adjusted EBITDA. See Appendix for the reconciliation of Adjusted EBITDA.

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Capitalization ($MM) Debt Maturity Summary ($MM)

$0 $200 $400 $600 2017 2018 2019 2020 2021 2022 2023 2024

Senior Notes No Near-Term Maturities $650MM Borrowing Base $500MM Elected Commitment

Highlights

June 30, 2017 Cash $139 Credit Facility $0 Senior Notes due 2024 $600 Total Debt $600 Stockholders’ Equity $1,816 Total Capitalization $2,416

Total Liquidity (1) $639 Net Debt to LQA Adj EBITDA (3) 1.9x

• Successfully extended revolving credit facility

– Borrowing base increased to $650MM; CPE elected commitment of $500MM – Undrawn facility with $639MM (1) of liquidity as of June 30th

• Raised an additional $200MM in the high yield market on an
• pportunistic basis (YTW 5.2%) (2)
• Target a long-term leverage ratio of < 2.0x Net Debt /

Annualized Adjusted EBITDA (3)

• Continued to add to oil hedge position for 2H17 (~50% of

guidance midpoint) and 2018 (~40% of current consensus estimates)

Guidance Summary

1) Excludes stock-based compensation and corporate depreciation and amortization. See the Non-GAAP related disclosures in the Appendix. 2) Excludes certain non-recurring expenses and non-cash valuation adjustments. See the non-GAAP related disclosures in the Appendix. 3) All interest expense anticipated to be capitalized. 4) Includes drilling, completions, facilities, seismic, land and other items. Excludes capitalized expenses.

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Guidance

2Q17 Guidance 2Q17 Actual 3Q17 Guidance FY17 Guidance

Total production (MBoepd) 21.5 - 23.5 22.2 23.0 - 25.0 22.5 - 25.5 Oil production 16.6 - 18.1 (76%-78%) 17.5 (79% ) 17.9 - 19.5 (77%) 17.6 - 19.9 (78%) Income Statement Expenses (per BOE) LOE, including workovers $6.25 - $7.00 $5.56 $6.00 - $6.50 $5.75 - $6.25 Gathering and treating $0.40 - $0.50 $0.45 $0.40 - $0.50 $0.40 - $0.50 Production taxes, including ad valorem (% of unhedged revenues) 7% 6% 7% 7% Adjusted G&A: cash component (1) $2.25 - $2.50 $2.67 $2.25 - $2.50 $2.00 - $2.50 Adjusted G&A: non-cash component (2) $0.50 - $0.75 $0.53 $0.50 - $0.75 $0.50 - $1.00 Interest expense (3) $0.00 $0.00 $0.00 $0.00 Effective income tax rate 0% 1% 0% 0% Capital expenditures ($MM, accrual basis) Operational (4) $90 - $100 $84 $110 - $130 $350 Capitalized expenses (cash component) $10 - $12 $12 $12 - $17 $40 - $45 Net operated horizontal completions: Midland Basin 9 - 11 9 ~10 ~39 Delaware Basin 1 1 ~1 ~3

Highlights

• Increased expectations

for FY17 oil mix (+2%

• ver previous midpoint)
• Reduced LOE guidance

for FY17 based on delivered 1H17 results and further WildHorse efficiencies

• Increased operational

capital to high end of previous range – Extending planned lateral lengths – Increased working interest in drill wells from 1H17 acquisitions

Appendix

Oil Hedge Contracts (1)

1) Hedge contracts as of July 31, 2017.

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~50% of 2H17 Guidance Volumes Hedged

Crude Oil (Bbl, $/Bbl) 3Q17 4Q17 2H17 2018

Swaps Strike Price 184,000 $45.74 184,000 $45.74 368,000 $45.74 730,000 $50.03 Swaps combined with Short Puts Swap Price Short Put 184,000 $44.50 $30.00 184,000 $44.50 $30.00 368,000 $44.50 $30.00

• Deferred Premium Put Spreads

Premium Long Put Short Put 253,000 $2.45 $50.00 $40.00 253,000 $2.45 $50.00 $40.00 506,000 $2.45 $50.00 $40.00

• Costless Collars

Ceiling Floor 340,400 $58.19 $47.50 340,400 $58.19 $47.50 680,800 $58.19 $47.50

• Three-way Collars

Ceiling Floor Short Put

• 3,467,500

$60.86 $48.95 $39.21 Midland Basin Oil Differential Swap Price 552,000 ($0.52) 552,000 ($0.52) 1,104,000 ($0.52) 2,737,500 ($1.03)

Total Hedge Volume Weighted Average Floor Price 961,400 $47.25 961,400 $47.25 1,922,800 $47.25 4,197,500 $49.14

Price Protection Over $45 through 2018

10,450 10,450 11,500 $47.25 $47.25 $49.14 $0 $10 $20 $30 $40 $50 $60 2,000 4,000 6,000 8,000 10,000 12,000 3Q17 4Q17 FY2018 $/Bbl Bbl/d Hedged Volume (Bbl/d) Swap/Long Put Price ($/Bbl)

Natural Gas Hedge Contracts (1)

1) Hedge contracts as of July 31, 2017.

18

~35% of 2H17 Guidance Volumes Hedged

Natural Gas (MMBtu, $/MMBtu) 3Q17 4Q17 2H17 2018

Swaps Strike Price 368,000 $3.39 124,000 $3.39 492,000 $3.39

• Costless Collars

Ceiling Floor 368,000 $3.68 $3.00 856,000 $3.77 $3.23 1,224,000 $3.74 $3.16 720,000 $3.84 $3.40 Three-way Collars Ceiling Floor Short Put 368,000 $3.71 $3.00 $2.50 368,000 $3.71 $3.00 $2.50 736,000 $3.71 $3.00 $2.50

• Total Hedge Volume

Weighted Average Floor Price 1,104,000 $3.13 1,348,000 $3.18 2,452,000 $3.16 720,000 $3.40

Price Protection Over $3 through 1Q18

12,000 14,652 8,000 $3.13 $3.18 $3.40 $0 $1 $2 $3 $4 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 3Q17 4Q17 1Q18 $/MMBtu MMBtu/d Hedged Volume (MMBtu/d) Swap/Long Put Price ($/MMBtu)

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Quarterly Cash Flow Statement

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Non-GAAP Reconciliation (1)

1) See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures. 2) Adjusted EBITDA inclusive of Pro forma Adjustments is used primarily for the purpose of calculating compliance with covenants, such as Debt/EBITDA calculations, and includes the impact of acquisitions closed during prior periods as if they were completed at the beginning of the reporting period.

(2)

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Non-GAAP Reconciliation (1)

1) See “Important Disclosure” slides for disclosures related to Supplemental Non-GAAP Financial Measures.