Chesapeake Energy Corporation, profile picture
Uploaded byChesapeake Energy Corporation
PPTX, PDF6,138 views

Q1 2018 Earnings

Chesapeake Energy reported financial and operational results for Q1 2018. Net production increased 16% year-over-year to 527,000 boe/d. Adjusted EBITDA increased 11% year-over-year to $740 million. Cash costs increased 5% year-over-year to $6.25/boe. The company expects to continue improving well productivity in its Powder River Basin, South Texas, and Mid-Continent assets through drilling and completion optimizations.

Embed presentation

Download to read offline
2018 Q1 EARNINGS May 2, 2018
FORWARD-LOOKING STATEMENTS This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results include those described under “Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec- filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means. In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law. In addition, this presentation contains time-sensitive information that reflects management's best judgment only as of the date of this presentation. We use certain terms in this presentation such as “Resource Potential,” “Net Reserves” and similar terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2017, File No. 1-13726 and in our other filings with the SEC, available from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. 2Q1 2018 EARNINGS
(4) 16% increase YOY (3) 11% increase YOY(3) 48% increase YOY (1) 40% increase YOY (1) 27% increase YOY 5% increase YOY (2) 1Q’18 FINANCIAL AND OPERATIONAL RESULTS Q1 2018 EARNINGS 3 (1) See non-GAAP reconciliation on pages 18 and 19 (2) See non-GAAP reconciliation on page 20. Free cash flow defined as net cash provided by operating activities less drilling and completion costs, and acquisitions of proved unproved properties and additions to other property and equipment, and inclusive of proceeds from divestitures of proved and unproved properties, sales of other property and equipment and sales of investments. (3) Adjusted for asset sales (4) Cash costs defined as lease operating expenses combined with general and administrative expenses (excluding stock-based compensation)
TRANSFORMATION DELIVERING INCREASED MARGINS • Cash cost leadership • Efforts to attack GP&T yielding positive results • Continued focus on delivering value vs. volume Q1 2018 EARNINGS 4 0 5 10 15 20 25 30 Revenue / Boe Adj. Ebitda / Boe Q1 2017 Q1 2018 $/boe
RETURN ON CAPITAL Q1 2018 EARNINGS 5 $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 0% 5% 10% 15% 20% 25% 2012 2013 2014 2015 2016 2017 2018E $Revenue/boe ReturnonCapital Wtd Avg Revenue/boe OCF/Net Debt+Equity
0 5 10 15 20 25 30 35 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E PRB Turner POWDER RIVER – GROWING TO A CORE ASSET • Oil growth engine • Ramping up activity ˃ Currently running four rigs • Stacked pay opportunities ˃ ~275,000 net acres (75% held) ˃ 13+ prospective horizons Q1 2018 EARNINGS 6 WY ~2.6 bboe gross Recoverable resource potential ~1.7 bboe net ~40% oil, ~58% liquids Equivalent Net Volume (mboe/d)
TURNER – CONTINUOUS IMPROVEMENT • Drilling improvements ˃ Extending laterals ˃ Batch drilling ˃ Slim hole casing design ˃ Drilling days from 60+ to ~21 • Completion improvements ˃ Optimizing cluster spacing design ˃ More efficient stimulation operations • Continue to drive more efficiency ˃ Plan to drill 35 – 40 Turner wells in 2018 Q1 2018 EARNINGS 7 $542 $469 $518 $420 $365 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Turner Avg Completion Cost Per Lateral Foot WY $320 $267 $308 $206 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Turner Avg Drilling Cost Per Foot
0 20 40 60 80 100 120 140 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) SOUTH TEXAS – CONTINUES TO DELIVER • 4 – 5 rig program in 2018 • Stacked pay potential ˃ Upper Eagle Ford and Austin Chalk provide additional resource potential • Improved oil recovery ˃ Proven technology ˃ Evaluating multiple pilot opportunities Q1 2018 EARNINGS 8 TX ~60% oil, ~78% liquids
MID-CON – STACKED PAY POTENTIAL • Oil growth potential ˃ Oswego provides low-cost, high-return oil ˃ Appraising new plays Q1 2018 EARNINGS OK 9 Represents volumes sold in 2017 and 2018 0 10 20 30 40 50 60 70 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) ~28% oil, ~46% liquids
OSWEGO – DELIVERING STRONG RESULTS • Moving to extended laterals and multiwell pads • 76 wells producing, average D&C cost of ~$3.6 million • Continue to grow our position, acquired ~2,900 acres ˃ Added ~25 core locations (1 rig year) ˃ ~75% average working interest Q1 2018 EARNINGS 10 OK 0 2 4 6 8 10 12 14 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Oswego Gross Oil Production (Average mbo/d)
0 25 50 75 100 125 150 175 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) GULF COAST – DEEP HIGH-QUALITY INVENTORY • Acreage position is 100% HBP, 25% developed – ideal for long lateral development • Completions breakthrough is scalable across entire acreage position • Ample takeaway capacity to markets with favorable pricing • Unlocking the Bossier Q1 2018 EARNINGS 11 LA ~100% gas, ~0% liquids
0 20 40 60 80 100 120 140 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) UTICA – FOCUSED ON VALUE • Two-rig program in 2018 ˃ ~10% increase in projected 2018 gas production with reduced capex, driving more value into the program • Oil performance has improved by moving to 1,000' spacing, continuing to optimize development plans ˃ Current gross oil production of 17 mbo/d Q1 2018 EARNINGS 12 OH ~10% oil, ~31% liquids
~40% improvement in IP30 due to completion design UTICA WET GAS IMPROVEMENTS Bars represent minimum and maximum IP30’s in that year along with the dot representing the average New DesignOriginal Design ~65% improvement in IP30 due to completion design Q1 2018 EARNINGS 13 0 200 400 600 800 2014 2015 2016 2017 2018YTD IP30:OilRate,Bopd Oil Rate 0 500 1,000 1,500 2,000 2014 2015 2016 2017 2018 IP30:GrossEqRate,Boepd Equivalent Rate 2018YTD
0 25 50 75 100 125 150 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) MARCELLUS – FREE CASH FLOW ENGINE (1) Excludes Ad Val taxes Q1 2018 EARNINGS 14 PA • Powerhouse shale gas asset ˃ ~75% ROR 2018 program ˃ Technology driving greater value ˃ Working additional market opportunities • Growth potential and portfolio flexibility ˃ 2,040 locations remaining assuming 1,200' spacing • Low maintenance ˃ ~2.1 bcf/d with 10¢/mcf LOE(1) ~34.5 tcf gross Recoverable resource potential ~12.6 tcf net ~100% gas, ~0% liquids
Appendix Q1 2018 EARNINGS 15
HEDGING POSITION AS OF 4/27/18 Q1 2018 EARNINGS 16 (1) As of 4/27/18, does not reflect April and May 2018 settlements (2) Percentages are as of our midpoints from the Management Outlook less the actuals from Q1 2018 Natural Gas 2018 $2.96/mcf HH 57% Swaps 6% Collars $3.00/$3.25/mcf HH NGL 2018 19% Propane Swaps $0.79/gal 1% Ethane Swaps $0.28/gal 10% Butane Swaps $0.88/gal 44% Natural Gasoline Swaps $1.42/gal 10% Isobutane Swaps $0.92/gal Oil 2018 $53.78/bbl WTI 72% Swaps $39.15/$47/$55/bbl WTI 6% Collars 14% NGL Swaps • 8 mmbbls of 2018 LLS-WTI oil basis hedges @ +$3.35 • 41 bcf of 2018 Tenn Zone 4-300 gas basis hedges @ -$0.77 • 4 bcf of 2019 Tetco M3 gas basis hedges @ +$2.24 • 87 bcf of 2019 natural gas hedged with three way collars @ $2.50/$2.80/$3.10 • 12 mmbbls of 2019 oil hedged with swaps @ $57.87
$53 $380 $665 $338 $1,300 $200 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 $2,047 $1,868 $1,300 $1,250 Revolving Credit Facility Secured Unsecured Convertibles $millions $200 million Revolving Credit Facility DEBT MATURITY PROFILE 2018 OUTLOOK(1) Q1 2018 EARNINGS 17 (1) As of 3/31/2018 $9.2 billion Senior Notes & Term Loan 7.10% WACD
Q1 2018 EARNINGS 18 RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited) Three Months Ended March 31, 2018 2017 $ $/Share(b)(c) $ $/Share(b)(c) Net income (loss) available to common stockholders (GAAP) $ 268 $ 0.29 $ 75 $ 0.08 Effect of dilutive securities 36 — Diluted earnings (loss) per common stockholder (GAAP) $ 304 $ 0.29 $ 75 $ 0.08 Adjustments: Unrealized (gains) losses on oil, natural gas and NGL derivatives 119 0.11 (326) (0.36) Restructuring and other termination costs 38 0.04 — — Provision for legal contingencies, net 5 — (2) — Impairments of fixed assets and other — — 391 0.43 Net losses on sales of fixed assets 8 0.01 — — Gain on sales of investments (139) (0.13) Losses on purchases or exchanges of debt — — 7 0.01 Loss on exchange of preferred stock — — 41 0.05 Other 1 — 2 — Adjusted net income available to common stockholders(b) (Non-GAAP) 336 0.32 188 0.21 Preferred stock dividends 23 0.02 23 0.02 Earnings allocated to participating securities 2 — 1 — Total adjusted net income attributable to Chesapeake(b) (c) (Non-GAAP) $ 361 $ 0.34 $ 212 $ 0.23 (a) Our effective tax rate in the three months ended March 31, 2018 was 0%. Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the three months ended March 31, 2017. (b) Adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake, both in the aggregate and per dilutive share, are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) available to common stockholders or earnings (loss) per share. Adjusted net income (loss) available to common stockholders and adjusted earnings (loss) per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because: (i) Management uses adjusted net income (loss) available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. (ii) Adjusted net income (loss) available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Because adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake exclude some, but not all, items that affect net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake may vary among companies, our calculation of adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake may not be comparable to similarly titled financial measures of other companies. (c) Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 60 million and 208 million shares considered antidilutive for the three months ended March 31, 2018 and 2017, respectively and thus excluded from the calculation. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.
RECONCILIATION OF ADJUSTED EBITDA CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited) Three Months Ended March 31, 2018 2017 EBITDA (Non-GAAP) $ 703 $ 455 Adjustments: Unrealized losses (gains) on oil, natural gas and NGL derivatives 119 (326) Restructuring and other termination costs 38 — Provision for legal contingencies, net 5 (2) Other operating expense — 391 Net losses on sales of fixed assets 8 — Gains on sales of investments (139) — Losses on purchases or exchanges of debt — 7 Net income attributable to noncontrolling interests (1) (1) Other — 1 Adjusted EBITDA (Non-GAAP)(a) $ 733 $ 525 Q1 2018 EARNINGS 19 (a) Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to EBITDA because: (i) Management uses adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. (ii) Adjusted EBITDA is more comparable to estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Accordingly, adjusted EBITDA should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss from continuing operations) attributable to common stockholders, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.
RECONCILIATION OF FREE CASH FLOW CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF FREE CASH FLOW DATA ($ in millions) (unaudited) Three Months Ended March 31, 2018 2017 Net cash provided by (used in) operating activities 656 99 Cash flows from investing activities: Drilling and completion costs (442) (433) Acquisitions of proved and unproved properties (63) (95) Proceeds from divestitures of proved and unproved properties 319 892 Additions to other property and equipment (3) (3) Proceeds from sales of other property and equipment 68 19 Proceeds from sales of investments 74 — Net cash used in investing activities (47) 380 Free Cash Flow 609 479 Q1 2018 EARNINGS 20
CORPORATE INFORMATION Q1 2018 EARNINGS 21 HEADQUARTERS 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.com CORPORATE CONTACTS BRAD SYLVESTER, CFA Vice President – Investor Relations and Communications DOMENIC J. DELL’OSSO, JR. Executive Vice President and Chief Financial Officer Investor Relations department can be reached at ir@chk.com PUBLICLY TRADED SECURITIES CUSIP TICKER 7.25% Senior Notes due 2018 #165167CC9 CHK18A 3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19 6.625% Senior Notes due 2020 #165167CF2 CHK20A 6.875% Senior Notes due 2020 #165167BU0 #165167BT3 #U16450AQ8 CHK20 6.125% Senior Notes Due 2021 #165167CG0 CHK21 5.375% Senior Notes Due 2021 #165167CK1 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 CHK22 8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8 #U16450AT2 N/A 5.75% Senior Notes Due 2023 #165167CL9 CHK23 8.00% Senior Notes due 2025 #165167CT2 #U16450AU9 N/A 8.00% Senior Notes due 2027 #165167CV7 #U16450AV7 N/A 5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) #165167834 #165167826 N/A 5.75% Cumulative Convertible Preferred Stock #U16450204 #165167776 #165167768 N/A 5.75% Cumulative Convertible Preferred Stock (Series A) #U16450113 #165167784 #165167750 N/A Chesapeake Common Stock #165167107 CHK

More Related Content

PPTX
TPH Conference 2018
byChesapeake Energy Corporation
 
PPTX
4Q 2018 Earnings
byChesapeake Energy Corporation
 
PPTX
2018 Annual Meeting of Shareholders
byChesapeake Energy Corporation
 
PPTX
June 2019 Update
byChesapeake Energy Corporation
 
PPTX
1Q 2019 Earnings
byChesapeake Energy Corporation
 
PPTX
September 2018 Update
byChesapeake Energy Corporation
 
PPTX
Final august investor presentation
bySandRidgeIR
 
PDF
Eog 0817
byResources1Smith
 
TPH Conference 2018
byChesapeake Energy Corporation
 
4Q 2018 Earnings
byChesapeake Energy Corporation
 
2018 Annual Meeting of Shareholders
byChesapeake Energy Corporation
 
June 2019 Update
byChesapeake Energy Corporation
 
1Q 2019 Earnings
byChesapeake Energy Corporation
 
September 2018 Update
byChesapeake Energy Corporation
 
Final august investor presentation
bySandRidgeIR
 
Eog 0817
byResources1Smith
 

What's hot

PDF
August Investor Presentation
byDevon Energy Corporation
 
PPTX
CHK 2018 Q2 Earnings
byChesapeake Energy Corporation
 
PPTX
2019 Annual Meeting of Shareholders
byChesapeake Energy Corporation
 
PDF
Gulfport Energy Investor Presentation May 2015
byMarcellus Drilling News
 
PPTX
Utica Shale Divestiture and PRB Update
byChesapeake Energy Corporation
 
PDF
Sem group investor presentation august 2017 final
bySemGroupCorporation
 
PPTX
3Q 2019 Earnings
byChesapeake Energy Corporation
 
PPTX
Q1 fiscal 2016 slides final
byRoyalGold
 
PDF
Barclays CEO Energy Conference
byDevon Energy Corporation
 
PDF
Arex 3 q15 results presentation
byApproachResources
 
PPTX
2Q 2019 Earnings
byChesapeake Energy Corporation
 
PDF
CHK 2016 Analyst Day
byChesapeake Energy Corporation
 
PDF
SN November 2016 Corporate Presentation
byMeghan Spicer
 
PDF
Chesapeake Energy Investor Presentation Feb 2015
byMarcellus Drilling News
 
PDF
2015 q1 financial results final
byGoldenStarResources
 
PDF
Enlk and enlc second quarter 2017 operations report
byEnLinkMidstreamLLC
 
PDF
Am website presentation (a) december 2016
byanteromidstream
 
PDF
Crestwood investor deck august 2017
byCrestwoodCorporate
 
PDF
REITWeek 2016 Investor Conference
byIronMInc
 
PDF
EnerCom’s The Oil and Gas Conference 21 Presentation
byApproachResources
 
August Investor Presentation
byDevon Energy Corporation
 
CHK 2018 Q2 Earnings
byChesapeake Energy Corporation
 
2019 Annual Meeting of Shareholders
byChesapeake Energy Corporation
 
Gulfport Energy Investor Presentation May 2015
byMarcellus Drilling News
 
Utica Shale Divestiture and PRB Update
byChesapeake Energy Corporation
 
Sem group investor presentation august 2017 final
bySemGroupCorporation
 
3Q 2019 Earnings
byChesapeake Energy Corporation
 
Q1 fiscal 2016 slides final
byRoyalGold
 
Barclays CEO Energy Conference
byDevon Energy Corporation
 
Arex 3 q15 results presentation
byApproachResources
 
2Q 2019 Earnings
byChesapeake Energy Corporation
 
CHK 2016 Analyst Day
byChesapeake Energy Corporation
 
SN November 2016 Corporate Presentation
byMeghan Spicer
 
Chesapeake Energy Investor Presentation Feb 2015
byMarcellus Drilling News
 
2015 q1 financial results final
byGoldenStarResources
 
Enlk and enlc second quarter 2017 operations report
byEnLinkMidstreamLLC
 
Am website presentation (a) december 2016
byanteromidstream
 
Crestwood investor deck august 2017
byCrestwoodCorporate
 
REITWeek 2016 Investor Conference
byIronMInc
 
EnerCom’s The Oil and Gas Conference 21 Presentation
byApproachResources
 

Similar to Q1 2018 Earnings

PPTX
4Q 2019 Earnings
byChesapeake Energy Corporation
 
PPTX
Goldman Sachs_ Template_2017 31231(3).pptx
byjackkale55
 
PDF
2018SAM-1_Introduction_0.pdf
byPatsyBaader
 
PDF
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
PDF
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
PDF
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
PDF
May 2013 Chesapeake Energy Investor Presentation
byMarcellus Drilling News
 
PDF
CHK January 2021 Roadshow
byChesapeake Energy Corporation
 
PDF
June corporate presentation final
byDenbury
 
PDF
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
PDF
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
PDF
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
PDF
Sd investor presentation 5.8.18
bySandRidgeIR
 
PDF
Sd investor presentation 5.8.18 (1)
bySandRidgeIR
 
PDF
Southwestern Energy July 2015 Update
byMarcellus Drilling News
 
PDF
Chesapeake Presentation at 2016 Heikkinen Energy Conference
byMarcellus Drilling News
 
PDF
February 2021 - Investor Presentation
byChesapeake Energy Corporation
 
PDF
Southwestern Energy Investor Presentation August 2013
byMarcellus Drilling News
 
PDF
J.p.morgan 2018 energy conference final
byDenbury
 
PDF
Ipaa 2018 oil and gas investment symposium
byDenbury
 
4Q 2019 Earnings
byChesapeake Energy Corporation
 
Goldman Sachs_ Template_2017 31231(3).pptx
byjackkale55
 
2018SAM-1_Introduction_0.pdf
byPatsyBaader
 
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
1Q 2021 Earnings Presentation
byChesapeake Energy Corporation
 
May 2013 Chesapeake Energy Investor Presentation
byMarcellus Drilling News
 
CHK January 2021 Roadshow
byChesapeake Energy Corporation
 
June corporate presentation final
byDenbury
 
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
February 9 2021 Investor Presentation
byChesapeake Energy Corporation
 
Sd investor presentation 5.8.18
bySandRidgeIR
 
Sd investor presentation 5.8.18 (1)
bySandRidgeIR
 
Southwestern Energy July 2015 Update
byMarcellus Drilling News
 
Chesapeake Presentation at 2016 Heikkinen Energy Conference
byMarcellus Drilling News
 
February 2021 - Investor Presentation
byChesapeake Energy Corporation
 
Southwestern Energy Investor Presentation August 2013
byMarcellus Drilling News
 
J.p.morgan 2018 energy conference final
byDenbury
 
Ipaa 2018 oil and gas investment symposium
byDenbury
 

More from Chesapeake Energy Corporation

PPTX
Successful Efforts Accounting Conversion Overview
byChesapeake Energy Corporation
 
PPTX
January 2019 Update
byChesapeake Energy Corporation
 
PPTX
December 2018 Update
byChesapeake Energy Corporation
 
PPTX
Citigroup Executive Energy Conference
byChesapeake Energy Corporation
 
PPTX
Bank of America Merrill Lynch 2018 Global Energy Conference
byChesapeake Energy Corporation
 
PPTX
November 2018 Update
byChesapeake Energy Corporation
 
PPTX
Acquisition of WildHorse Resource Development Corporation
byChesapeake Energy Corporation
 
Successful Efforts Accounting Conversion Overview
byChesapeake Energy Corporation
 
January 2019 Update
byChesapeake Energy Corporation
 
December 2018 Update
byChesapeake Energy Corporation
 
Citigroup Executive Energy Conference
byChesapeake Energy Corporation
 
Bank of America Merrill Lynch 2018 Global Energy Conference
byChesapeake Energy Corporation
 
November 2018 Update
byChesapeake Energy Corporation
 
Acquisition of WildHorse Resource Development Corporation
byChesapeake Energy Corporation
 

Q1 2018 Earnings

  • 1.
  • 2.
    FORWARD-LOOKING STATEMENTS This presentationincludes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results include those described under “Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec- filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means. In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this presentation, and we undertake no obligation to update any of the information provided in this presentation, except as required by applicable law. In addition, this presentation contains time-sensitive information that reflects management's best judgment only as of the date of this presentation. We use certain terms in this presentation such as “Resource Potential,” “Net Reserves” and similar terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These terms include reserves with substantially less certainty, and no discount or other adjustment is included in the presentation of such reserve numbers. U.S. investors are urged to consider closely the disclosure in our Form 10-K for the year ended December 31, 2017, File No. 1-13726 and in our other filings with the SEC, available from us at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. 2Q1 2018 EARNINGS
  • 3.
    (4) 16% increase YOY(3) 11% increase YOY(3) 48% increase YOY (1) 40% increase YOY (1) 27% increase YOY 5% increase YOY (2) 1Q’18 FINANCIAL AND OPERATIONAL RESULTS Q1 2018 EARNINGS 3 (1) See non-GAAP reconciliation on pages 18 and 19 (2) See non-GAAP reconciliation on page 20. Free cash flow defined as net cash provided by operating activities less drilling and completion costs, and acquisitions of proved unproved properties and additions to other property and equipment, and inclusive of proceeds from divestitures of proved and unproved properties, sales of other property and equipment and sales of investments. (3) Adjusted for asset sales (4) Cash costs defined as lease operating expenses combined with general and administrative expenses (excluding stock-based compensation)
  • 4.
    TRANSFORMATION DELIVERING INCREASEDMARGINS • Cash cost leadership • Efforts to attack GP&T yielding positive results • Continued focus on delivering value vs. volume Q1 2018 EARNINGS 4 0 5 10 15 20 25 30 Revenue / Boe Adj. Ebitda / Boe Q1 2017 Q1 2018 $/boe
  • 5.
    RETURN ON CAPITAL Q12018 EARNINGS 5 $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 0% 5% 10% 15% 20% 25% 2012 2013 2014 2015 2016 2017 2018E $Revenue/boe ReturnonCapital Wtd Avg Revenue/boe OCF/Net Debt+Equity
  • 6.
    0 5 10 15 20 25 30 35 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E PRB Turner POWDER RIVER– GROWING TO A CORE ASSET • Oil growth engine • Ramping up activity ˃ Currently running four rigs • Stacked pay opportunities ˃ ~275,000 net acres (75% held) ˃ 13+ prospective horizons Q1 2018 EARNINGS 6 WY ~2.6 bboe gross Recoverable resource potential ~1.7 bboe net ~40% oil, ~58% liquids Equivalent Net Volume (mboe/d)
  • 7.
    TURNER – CONTINUOUSIMPROVEMENT • Drilling improvements ˃ Extending laterals ˃ Batch drilling ˃ Slim hole casing design ˃ Drilling days from 60+ to ~21 • Completion improvements ˃ Optimizing cluster spacing design ˃ More efficient stimulation operations • Continue to drive more efficiency ˃ Plan to drill 35 – 40 Turner wells in 2018 Q1 2018 EARNINGS 7 $542 $469 $518 $420 $365 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Turner Avg Completion Cost Per Lateral Foot WY $320 $267 $308 $206 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Turner Avg Drilling Cost Per Foot
  • 8.
    0 20 40 60 80 100 120 140 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume(mboe/d) SOUTH TEXAS – CONTINUES TO DELIVER • 4 – 5 rig program in 2018 • Stacked pay potential ˃ Upper Eagle Ford and Austin Chalk provide additional resource potential • Improved oil recovery ˃ Proven technology ˃ Evaluating multiple pilot opportunities Q1 2018 EARNINGS 8 TX ~60% oil, ~78% liquids
  • 9.
    MID-CON – STACKEDPAY POTENTIAL • Oil growth potential ˃ Oswego provides low-cost, high-return oil ˃ Appraising new plays Q1 2018 EARNINGS OK 9 Represents volumes sold in 2017 and 2018 0 10 20 30 40 50 60 70 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume (mboe/d) ~28% oil, ~46% liquids
  • 10.
    OSWEGO – DELIVERINGSTRONG RESULTS • Moving to extended laterals and multiwell pads • 76 wells producing, average D&C cost of ~$3.6 million • Continue to grow our position, acquired ~2,900 acres ˃ Added ~25 core locations (1 rig year) ˃ ~75% average working interest Q1 2018 EARNINGS 10 OK 0 2 4 6 8 10 12 14 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Oswego Gross Oil Production (Average mbo/d)
  • 11.
    0 25 50 75 100 125 150 175 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume(mboe/d) GULF COAST – DEEP HIGH-QUALITY INVENTORY • Acreage position is 100% HBP, 25% developed – ideal for long lateral development • Completions breakthrough is scalable across entire acreage position • Ample takeaway capacity to markets with favorable pricing • Unlocking the Bossier Q1 2018 EARNINGS 11 LA ~100% gas, ~0% liquids
  • 12.
    0 20 40 60 80 100 120 140 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume(mboe/d) UTICA – FOCUSED ON VALUE • Two-rig program in 2018 ˃ ~10% increase in projected 2018 gas production with reduced capex, driving more value into the program • Oil performance has improved by moving to 1,000' spacing, continuing to optimize development plans ˃ Current gross oil production of 17 mbo/d Q1 2018 EARNINGS 12 OH ~10% oil, ~31% liquids
  • 13.
    ~40% improvement in IP30due to completion design UTICA WET GAS IMPROVEMENTS Bars represent minimum and maximum IP30’s in that year along with the dot representing the average New DesignOriginal Design ~65% improvement in IP30 due to completion design Q1 2018 EARNINGS 13 0 200 400 600 800 2014 2015 2016 2017 2018YTD IP30:OilRate,Bopd Oil Rate 0 500 1,000 1,500 2,000 2014 2015 2016 2017 2018 IP30:GrossEqRate,Boepd Equivalent Rate 2018YTD
  • 14.
    0 25 50 75 100 125 150 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018E Q3 2018E Q4 2018E Equivalent Net Volume(mboe/d) MARCELLUS – FREE CASH FLOW ENGINE (1) Excludes Ad Val taxes Q1 2018 EARNINGS 14 PA • Powerhouse shale gas asset ˃ ~75% ROR 2018 program ˃ Technology driving greater value ˃ Working additional market opportunities • Growth potential and portfolio flexibility ˃ 2,040 locations remaining assuming 1,200' spacing • Low maintenance ˃ ~2.1 bcf/d with 10¢/mcf LOE(1) ~34.5 tcf gross Recoverable resource potential ~12.6 tcf net ~100% gas, ~0% liquids
  • 15.
  • 16.
    HEDGING POSITION AS OF4/27/18 Q1 2018 EARNINGS 16 (1) As of 4/27/18, does not reflect April and May 2018 settlements (2) Percentages are as of our midpoints from the Management Outlook less the actuals from Q1 2018 Natural Gas 2018 $2.96/mcf HH 57% Swaps 6% Collars $3.00/$3.25/mcf HH NGL 2018 19% Propane Swaps $0.79/gal 1% Ethane Swaps $0.28/gal 10% Butane Swaps $0.88/gal 44% Natural Gasoline Swaps $1.42/gal 10% Isobutane Swaps $0.92/gal Oil 2018 $53.78/bbl WTI 72% Swaps $39.15/$47/$55/bbl WTI 6% Collars 14% NGL Swaps • 8 mmbbls of 2018 LLS-WTI oil basis hedges @ +$3.35 • 41 bcf of 2018 Tenn Zone 4-300 gas basis hedges @ -$0.77 • 4 bcf of 2019 Tetco M3 gas basis hedges @ +$2.24 • 87 bcf of 2019 natural gas hedged with three way collars @ $2.50/$2.80/$3.10 • 12 mmbbls of 2019 oil hedged with swaps @ $57.87
  • 17.
    $53 $380 $665 $338 $1,300 $200 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2018 20192020 2021 2022 2023 2024 2025 2026 2027 $2,047 $1,868 $1,300 $1,250 Revolving Credit Facility Secured Unsecured Convertibles $millions $200 million Revolving Credit Facility DEBT MATURITY PROFILE 2018 OUTLOOK(1) Q1 2018 EARNINGS 17 (1) As of 3/31/2018 $9.2 billion Senior Notes & Term Loan 7.10% WACD
  • 18.
    Q1 2018 EARNINGS18 RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in millions except per share data) (unaudited) Three Months Ended March 31, 2018 2017 $ $/Share(b)(c) $ $/Share(b)(c) Net income (loss) available to common stockholders (GAAP) $ 268 $ 0.29 $ 75 $ 0.08 Effect of dilutive securities 36 — Diluted earnings (loss) per common stockholder (GAAP) $ 304 $ 0.29 $ 75 $ 0.08 Adjustments: Unrealized (gains) losses on oil, natural gas and NGL derivatives 119 0.11 (326) (0.36) Restructuring and other termination costs 38 0.04 — — Provision for legal contingencies, net 5 — (2) — Impairments of fixed assets and other — — 391 0.43 Net losses on sales of fixed assets 8 0.01 — — Gain on sales of investments (139) (0.13) Losses on purchases or exchanges of debt — — 7 0.01 Loss on exchange of preferred stock — — 41 0.05 Other 1 — 2 — Adjusted net income available to common stockholders(b) (Non-GAAP) 336 0.32 188 0.21 Preferred stock dividends 23 0.02 23 0.02 Earnings allocated to participating securities 2 — 1 — Total adjusted net income attributable to Chesapeake(b) (c) (Non-GAAP) $ 361 $ 0.34 $ 212 $ 0.23 (a) Our effective tax rate in the three months ended March 31, 2018 was 0%. Due to our valuation allowance position, no income tax effect from the adjustments has been included in determining adjusted net income for the three months ended March 31, 2017. (b) Adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake, both in the aggregate and per dilutive share, are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income (loss) available to common stockholders or earnings (loss) per share. Adjusted net income (loss) available to common stockholders and adjusted earnings (loss) per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because: (i) Management uses adjusted net income (loss) available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. (ii) Adjusted net income (loss) available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Because adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake exclude some, but not all, items that affect net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake may vary among companies, our calculation of adjusted net income (loss) available to common stockholders and total adjusted net income (loss) attributable to Chesapeake may not be comparable to similarly titled financial measures of other companies. (c) Our presentation of diluted net income (loss) available to common stockholders and diluted adjusted net income (loss) per share excludes 60 million and 208 million shares considered antidilutive for the three months ended March 31, 2018 and 2017, respectively and thus excluded from the calculation. The number of shares used for the non-GAAP calculation was determined in a manner consistent with GAAP.
  • 19.
    RECONCILIATION OF ADJUSTEDEBITDA CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited) Three Months Ended March 31, 2018 2017 EBITDA (Non-GAAP) $ 703 $ 455 Adjustments: Unrealized losses (gains) on oil, natural gas and NGL derivatives 119 (326) Restructuring and other termination costs 38 — Provision for legal contingencies, net 5 (2) Other operating expense — 391 Net losses on sales of fixed assets 8 — Gains on sales of investments (139) — Losses on purchases or exchanges of debt — 7 Net income attributable to noncontrolling interests (1) (1) Other — 1 Adjusted EBITDA (Non-GAAP)(a) $ 733 $ 525 Q1 2018 EARNINGS 19 (a) Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to EBITDA because: (i) Management uses adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. (ii) Adjusted EBITDA is more comparable to estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. Accordingly, adjusted EBITDA should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP. Because adjusted EBITDA excludes some, but not all, items that affect net income (loss from continuing operations) attributable to common stockholders, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.
  • 20.
    RECONCILIATION OF FREECASH FLOW CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF FREE CASH FLOW DATA ($ in millions) (unaudited) Three Months Ended March 31, 2018 2017 Net cash provided by (used in) operating activities 656 99 Cash flows from investing activities: Drilling and completion costs (442) (433) Acquisitions of proved and unproved properties (63) (95) Proceeds from divestitures of proved and unproved properties 319 892 Additions to other property and equipment (3) (3) Proceeds from sales of other property and equipment 68 19 Proceeds from sales of investments 74 — Net cash used in investing activities (47) 380 Free Cash Flow 609 479 Q1 2018 EARNINGS 20
  • 21.
    CORPORATE INFORMATION Q1 2018EARNINGS 21 HEADQUARTERS 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.com CORPORATE CONTACTS BRAD SYLVESTER, CFA Vice President – Investor Relations and Communications DOMENIC J. DELL’OSSO, JR. Executive Vice President and Chief Financial Officer Investor Relations department can be reached at ir@chk.com PUBLICLY TRADED SECURITIES CUSIP TICKER 7.25% Senior Notes due 2018 #165167CC9 CHK18A 3mL + 3.25% Senior Notes due 2019 #165167CM7 CHK19 6.625% Senior Notes due 2020 #165167CF2 CHK20A 6.875% Senior Notes due 2020 #165167BU0 #165167BT3 #U16450AQ8 CHK20 6.125% Senior Notes Due 2021 #165167CG0 CHK21 5.375% Senior Notes Due 2021 #165167CK1 CHK21A 4.875% Senior Notes Due 2022 #165167CN5 CHK22 8.00% Senior Secured Second Lien Notes due 2022 #165167CQ8 #U16450AT2 N/A 5.75% Senior Notes Due 2023 #165167CL9 CHK23 8.00% Senior Notes due 2025 #165167CT2 #U16450AU9 N/A 8.00% Senior Notes due 2027 #165167CV7 #U16450AV7 N/A 5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A 2.25% Contingent Convertible Senior Notes due 2038 #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) #165167834 #165167826 N/A 5.75% Cumulative Convertible Preferred Stock #U16450204 #165167776 #165167768 N/A 5.75% Cumulative Convertible Preferred Stock (Series A) #U16450113 #165167784 #165167750 N/A Chesapeake Common Stock #165167107 CHK

Editor's Notes

  • #8 Moved from 40’ to 60’ cluster spacing
  • #9 Large remaining inventory Over ~3,000 undrilled locations after updated development plan Stacked pay potential Upper Eagle Ford and Austin Chalk provide additional resource potential Improved oil recovery Proven technology Evaluating multiple pilot opportunities ~4 rig program in 2018 Projected reduction of 2018 D&C capex of ~$150 million provides flat production, with significantly higher free cash flow
  • #12 Start w/ map describe acreage Announced the divestiture of the “donut” Expect to sell ~130,000 acres, 200 wells, and 100 mmcfd Process is going well Even after the sale we have a great position We can still drill over 2000 wells with over 850 being 10,000’ wells *Acreage Count:  445k net acres pre-divesture (this is adding north donut, south donut, LA acreage not in the core, LA core acreage) 310k net acres post-divesture (actually 312 but rounded down.  This is just subtracting north and south donuts from the above number) Total Co Net Acres tied to EGC (inclusive of Texas, new acquired PXP acreage and “donut”) : 560,779.14 co net acres. Below are the subcategories that bring us to this total: Total Co Net Acres in Texas: 116, 583.88 Total Co Net Acres in North Donut: 54,300 Total Co Net Acres in South Donut: 77,500 Total Co Net Acres contained in LA that are outside of Geologic HVL Core: 59,292.24 Total Co Net Acres in newly defined Geologic HVL Core: 253,103.02 Reasons for changes: Geology updated the HVL Core Outline which will be the “donut hole” and the remainder of our Caddo acreage not associated with any Jefferies packages Texas acreage has increased due to some exploration activity and in part due to the recent PXP acquisition In certain categories above the acreage has decreased due to various reasons, for example the BU electing to allow acreage to expire once wells lost production and data clean-up in preparation for Jefferies Certain categories above have increased due to data clean-up and the PXP transaction. The PXP transaction was approx. 72,000 net acres. All the PXP acreage is accounted for above within the respective categories. There are some leases which CHK did not own any interest in and therefore we  got our co net in entirety through the transaction CHK is in the process of selling Vine some acreage which has been deducted in the above totals *Recently purchased ~72K net acres for $87mm Increases WI to 83%
  • #13 Enhanced completions Improving cumulative production, while continuing to optimize well spacing Untapped potential Rome Trough offers three-stream potential over ~1.4 million net acres