3Q 2019 Earnings

3Q 2019 Earnings

• 1.
  3Q 2019 EARNINGS November5, 2019
• 2.
  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, cost-cutting measures, reductions in expenditures, proposed refinancing transactions, capital exchange transactions, asset divestitures, reductions in capital expenditures, operational efficiencies, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, expected lateral lengths of wells, anticipated timing and number of wells to be placed into production, expected oil growth trajectory, anticipated timing of execution of new gathering agreement, expected savings in connection with new oil gathering and pipeline agreements, projected capital expenditures, 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 our ability to comply with the covenants under our revolving credit facilities and other indebtedness and the related impact on our ability to continue as a going concern, 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 news release, and we undertake no obligation to update any of the information provided in 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. FORWARD-LOOKING STATEMENT 3Q 2019 Earnings 2
• 3.
  BUSINESS STRATEGY Our strategyremains unchanged – resilient to commodity price volatility Financial discipline Profitable and efficient growth from captured resources Exploration Business development STRATEGIC GOALS Margin enhancement Free cash flow Net debt to EBITDAX of 2X Excellence in HSER 3Q 2019 Earnings 3
• 4.
  0 20 40 60 80 100 120 140 1Q'19 2Q'19 3Q'194Q'19E 2019 TIL Schedule (1) 0 20 40 60 80 100 120 140 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19E Total Oil Volume (mbo/d)(1) INVESTING IN OUR HIGHEST-MARGIN OPPORTUNITIES 3Q 2019 Earnings (1) Based on 11/5/19 Outlook 0 60 120 180 240 300 360 420 4Q'18 1Q'19 2Q'19 3Q'19 4Q'19E Total Gas + NGL Volume (mboe/d)(1) 26% 4Q’19E Oil Gas 4 19% 4Q’18
• 5.
  3Q 2019 Earnings BRAZOSVALLEY STRATEGIC PORTFOLIO ADDITION Established field net oil production record of ~40 mbo/d for the month of October Recognized a 30% improvement in peak rate of oil wells(1) Well cost reduced per lateral foot by 21%(1) 5 (1) Data compared to 2018 WRD results (2) Represents average net production volumes for 3Q’19 (3) Projected 2019 mix (4) Based on 11/5/19 Outlook 2019 Activity(4) Wells to Turn in Line 81 Rigs 4 Frac Crews 2 Total Capex (millions) $665 – $685 Overview 3Q’19 Production 53 mboe/d(2) Net Acres ~470,000 2019 Production Mix(3) GasOil NGL 18%71% 11% 2019 TIL Schedule(4) 9 22 22 204 1 3 1Q'19 2Q'19 3Q'19 4Q'19E Gas Oil
• 6.
  2 3 4 5 6 0 5 10 15 20 25 30 35 40 45 50 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 RigCount NetOperatedOilRate(mbo/d) 773 682 ~890 0 100 200 300 400 500 600 700 800 900 1,000 2017 2018 2019E ~30% increase PeakRate of Oil Wells by TIL Date (boe/d)(1) $1,109 $1,057 ~$830 $0 $200 $400 $600 $800 $1,000 $1,200 2017 2018 2019E ~21% decrease Well Cost per Lateral Foot by Spud Date(1) REDEFINING THE ECONOMICS OF THE PLAY 3Q 2019 Earnings 6 (1) Based on 11/5/19 Outlook 5 rigs 4 rigs 2/2019: CHK acquired asset with field rate declining: 37 mbo/d Net Oil Rate Rigs
• 7.
  0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 0 30 6090 CumulativeOilProduction(bo) Producing Days OPTIMIZED COMPLETIONS DOING MORE FOR LESS 3Q 2019 Earnings 7 (1) Normalized to average lateral length of 8,200’ (2) 44 Wells with optimized completion design 2018 Average for Eagle Ford Wells(1) 2019 CHK Completions(1,2) 15% decrease per lateral foot completion costs
• 8.
  Since transaction close: Placed13 wells to sales with peak rates >1,000 bo/d(1) compared to: 2018 Three wells reached a peak rate of >1,000 bo/d(1) Oil window recently expanded to the northwest, increasing oil portfolio EXPANSION CONTINUES 3Q 2019 Earnings 8 (1) 24-hour peak rate Miles 1050 20 2019 Eagle Ford TIL Well Non-Operated Eagle Ford Well >1,000 bo/d Offset Operator Well >1,000 bo/d Eagle Ford Oil Window TERRY EF UNIT 1H Peak Rate: 1,119 bo/d, 459 mcf/d 7,612' Lateral W DELAMATER HCX1 1H Peak Rate: 1,223 bo/d, 612 mcf/d 10,950' Lateral W DELAMATER HCX2 2H Peak Rate: 1,205 bo/d, 651 mcf/d 10,826' Lateral TONY T 2H Peak Rate: 1,094 bo/d, 588 mcf/d 8,266' Lateral SCARPINATO 3H Peak Rate: 1,042 bo/d, 404 mcf/d 7,037' Lateral SCHOENEMAN C 3H Peak Rate: 1,143 bo/d, 521 mcf/d 8,654' Lateral SCHOENEMAN C 1H Peak Rate: 1,332 bo/d, 581 mcf/d 9,362' Lateral MCCOY 1H Peak Rate: 1,124 bo/d, 341 mcf/d 8,731' Lateral BARWISE EF UNIT 1H Peak Rate: 1,044 bo/d, 325 mcf/d 7,613' Lateral EASY RIDER 3H Peak Rate: 1,486 bo/d, 510 mcf/d 6,824' Lateral SORSBY 1H Peak Rate: 1,175 bo/d, 226 mcf/d 9,689' Lateral BEACH 1H Peak Rate: 1,331 bo/d, 235 mcf/d 11,884' Lateral PABST 4HE Treadstone operated; CHK WI 50% Peak Rate: 1,333 bo/d, 181 mcf/d 8,622' Lateral
• 9.
  3Q 2019 Earnings POWDERRIVER BASIN OIL GROWTH ENGINE First Niobrara well drilled since 2014 delivering record results GP&T/boe expected to be reduced by ~25% in 2019 Recent Turner four-well pad turned in line for ~$6mm per well 9 (1) Represents average net production volumes for 3Q’19 (2) Based on 11/5/19 Outlook (3) Projected 2019 mix 2019 TIL Schedule(2) Overview 3Q’19 Production 39 mboe/d(1) Net Acres ~213,000 2019 Activity(2) Wells to Turn in Line 72 Rigs ~5 Frac Crews ~2 Total Capex (millions) $505 – $525 2019 Production Mix(3) GasOil NGL 36%50% 14% 13 16 26 17 1Q'19 2Q'19 3Q'19 4Q'19E Oil
• 10.
  LEBAR 25-34-70 USA ANB 23H 9,386' Lateral NW FETTER 15-33-71 A 6H 6,094' Lateral BARTON 32-34-67 USA A 1H 9,572' Lateral 2019 CHK Niobrara Well CHK Niobrara Well Offset Operator Well Niobrara Outline Miles 0 5 10 RECORD NIOBRARA RESULTS 3Q 2019 Earnings 10 Lebar 25-34-70 USA A NB 23H • Highest 80-day Niobrara cumulative oil production in basin’s history • IP of ~1,600 bo/d with strong deliverability • 9,386' LL well drilled in 27 days Anticipate PRB 2020 drilling program will be ~25% Niobrara 220 200 180 160 140 120 100 80 60 40 20 0 Cummboe Days 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 LEBAR 25-34-70 USA A NB 23H ~70% Oil Recent Competitor TILs (public) Recent CHK liquids window TILs Niobrara Cum BOE vs Time NW FETTER 15-33-71 A 6H BARTON 32-34-67 USA A 1H
• 11.
  0 50000 100000 150000 200000 250000 300000 350000 400000 450000 1 2 34 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 400 300 200 0 100 Production(mboe) Months All CHK Turner Wells Peer Companies with 20+ Turner Wells(1) PRB Turner Production(1) Miles 0 5 10 CHK Turner Well LEADING IN THE TURNER 3Q 2019 Earnings 11 20-month cumulative production more than 40% greater than the most active Turner peers Nine isolated wells underperformed Chesapeake’s field average • Lower reservoir quality • Edge of development area, no additional drilling planned Months CHK Turner Well Performance 0 50000 100000 150000 200000 250000 300000 1 2 3 4 5 6 7 8 9 300 100 0 200 CHK Offset Turner Wells 9 CHK Turner Isolated Wells Production(mboe) (1) PRB Turner wells with a first production date after 1/1/15; Production data pulled from RS Energy Group ~40% greater
• 12.
  MARCELLUS FOUNDATIONAL ASSET 3Q 2019Earnings Projected to generate ~$300mm in free cash flow(1) Ten years of drilling inventory at $1.50 – $1.75/mcf break-even(2) 35% of 3Q wells had a max IP >60 mmcf/d 12 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses; Based on 11/5/19 Outlook (2) Assumes current drilling activity level (3) Represents average net production volumes for 3Q’19 (4) Projected 2019 mix (5) Based on 11/5/19 Outlook 2019 TIL Schedule(5) Overview 3Q’19 Production 928 mmcf/d(3) Net Acres ~540,000 2019 Activity(5) Wells to Turn in Line 44 Rigs ~2 Frac Crews ~1 Total Capex (millions) $190 – $210 2019 Production Mix(4) Gas 100% 9 14 17 4 1Q'19 2Q'19 3Q'19 4Q'19E Gas
• 13.
  MAXIMIZING VALUE, DEFINING CAPITALEFFICIENCY Capital efficiency drivers: • Proper spacing (1,200' – 1,500') • Longer laterals, no performance degradation • Optimized completions driving value per foot 3Q 2019 Earnings 13 4,000' – 7,000' (110 wells) 7,000' – 9,000' (44 wells) 9,000' – 12,000' (18 wells) >12,000' (8 wells) Months 12.00 10.00 8.00 6.00 4.00 2.00 0 1 2 3 4 5 6 7 8 9 10 11 12 Average of Cumulative Gas Production (bcf) 0.61 mmcf/ft 0.60 mmcf/ft 0.61 mmcf/ft 0.78 mmcf/ft DEREMER 2HC Max IP: 85 mmcf/d Miles 20100 Lower Marcellus Well >30 mmcf/d Lower Marcellus Core Lower Marcellus Core Expansion ANGIE 6HC Max IP: 78 mmcf/d JOEGUSWA 5HC Max IP: 73 mmcf/d JOEGUSWA 4HC Max IP: 63 mmcf/d AMCOR 2HC Max IP: 84 mmcf/d AMCOR 3HC Max IP: 64 mmcf/d RUTH 2HC Max IP: 73 mmcf/d RUTH 1HC Max IP: 63 mmcf/d MCGAVIN E WYO 6H Max IP: 62 mmcf/d
• 14.
  SOUTH TEXAS FREE CASHFLOW MACHINE Projected to generate ~$300mm in free cash flow (1) Optimized spacing and completions driving value Multi-zone high-margin oil growth potential 3Q 2019 Earnings 14 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses; Based on 11/5/19 Outlook (2) Represents average net production volumes for 3Q’19 (3) Projected 2019 mix (4) Based on 11/5/19 Outlook 2019 TIL Schedule(4) Overview 3Q’19 Production 94 mboe/d(2) Net Acres ~235,000 2019 Activity(4) Wells to Turn in Line 134 Rigs 4 Frac Crews ~2 Total Capex (millions) $510 – $540 2019 Production Mix(3) GasOil NGL 25%56% 19% 29 17 47 41 1Q'19 2Q'19 3Q'19 4Q'19E Oil
• 15.
  GULF COAST CONSISTENT PERFORMANCE 3Q2019 Earnings Projected to generate ~$150mm in free cash flow(1) Access to premium markets Base optimization yielding significant results 15 (1) Free cash flow defined as net revenue less all operating costs and capital expenditures, excluding general and administrative and interest expenses; Based on 11/5/19 Outlook (2) Represents average net production volumes for 3Q’19 (3) Projected 2019 mix (4) Based on 11/5/19 Outlook 2019 TIL Schedule(4) Overview 3Q’19 Production 694 mmcf/d(2) Net Acres ~301,000 2019 Activity(4) Wells to Turn in Line 24 Rigs ~1 Frac Crews ~1 Total Capex (millions) $130 – $150 2019 Production Mix(3) Gas 100% 10 9 5 1Q'19 2Q'19 3Q'19 4Q'19E Gas
• 16.
  3Q 2019 Earnings High-grading2020 and 2021 program Integrating new 3D data and recent appraisal program results MID-CONTINENT GROWTH OPTIONALITY 16 (1) Represents average net production volumes for 3Q’19 (2) Projected 2019 mix (3) Based on 11/5/19 Outlook 2019 TIL Schedule(3) Overview 3Q’19 Production 22 mboe/d(1) Net Acres ~764,000 2019 Activity(3) Wells to Turn in Line 14 Rigs 0 Frac Crews ~1 Total Capex (millions) $75 – $95 2019 Production Mix(2) GasOil NGL 41%35% 24% 9 5 1Q'19 2Q'19 3Q'19 4Q'19E Oil
• 17.
  GP&T: IMPROVING OURCASH MARGIN Gas gathering and crude transportation restructurings in South Texas and Brazos Valley improves long-term field economics • Incentivizes new horizon development, simplifies A&D transactions, prevents shut-in of volumes Engaged with midstream and downstream providers in all basins and key contracts identified for future improvements 3Q 2019 Earnings 17 (1) Based on 11/5/19 Outlook $7.35 $4.00 $4.50 $5.00 $5.50 $6.00 $6.50 $7.00 $7.50 $8.00 2018 2019E MARCELLUS Optimized Fixed Fee (Dry) August 2015 SOUTH TEXAS Optimized Fixed Fee November 2019 GULF COAST Optimized Fixed Fee July 2015 MID-CONTINENT Optimized Fixed Fee August 2016 POWDER RIVER Optimized Fixed Fee October 2017 $5.90 – $6.40 (1)
• 18.
  $millions $301 $294 $338 $209 $850 $1,245 $2,383 $1,090 $900 BVL $1,504 CHK $618 -$113-$129 -$55 -$186 -$210 2020 2021 2022 2023 2024 2025 2026 2027 2020 2021 2022 2023 2024 2025 2026 2027 PRUDENTLY MANAGING OUR MATURITIES 3Q 2019 Earnings 18 Unsecured Senior Notes Revolving Credit Facility BVL Senior Notes(1) Reduction in Unsecured Senior Notes (1) The BVL RCF was used to source the $82mm principal decrease in the 2025 BVL Senior Notes $693 million reduction in unsecured senior notes $35 million savings in annual interest expense
• 19.
  HEDGE POSITION –CHK + BVL AS OF 10/31/19(1) (1) Includes October and November 2019 derivative contracts that have settled (2) Does not include swaptions W E I G H T E D A V E R A G E P R I C E OIL Volume (mmbbl) Hedge % Fixed Call ($ per bbl) Put Swaps: 2019 6.8 55% $60.20 2020 15.5 $58.60 Collars: 2019 1.5 12% $67.75 $58.00 2020 1.8 $83.25 $65.00 Swaptions: 2020 2.2 $63.15 Puts: 2019 0.8 7% $54.31 Total 2019 9.1 74% Total 2020(2) 17.3 NATURAL GAS Volume (bcf) Fixed Call ($ per mcf) Put Swaps: 2019 117.6 63% $2.84 2020 264.7 $2.76 Three-way collars: 2019 14.6 8% $3.10 $2.50/$2.80 Collars: 2019 9.2 5% $2.91 $2.75 Swaptions: 2020 106.1 $2.77 2021 14.6 $2.80 2022 14.6 $2.80 Total 2019 141.4 75% Total 2020(2) 264.7 3Q 2019 Earnings 19
• 20.
  CORPORATE INFORMATION 3Q 2019Earnings As of 9/30/19 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 [email protected] Publicly Traded Securities Cusip Ticker 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 5.75% Senior Notes Due 2023 #165167CL9 CHK23 7.00% Senior Notes due 2024 #165167DA2 N/A 8.00% Senior Notes due 2025 #165167CT2 #165167CU9 #U16450AU9 N/A 7.50% Senior Notes due 2026 #165167DB0 N/A 8.00% Senior Notes due 2026 #165167DC8 #U16450AY1 N/A 8.00% Senior Notes due 2027 #165167CV7 #U16450AV7 N/A 5.50% Contingent Convertible Senior Notes due 2026 #165167CY1 N/A 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 20