Chesapeake Energy Investory Presentation January 2014

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The latest PowerPoint presentation issued by Chesapeake on Jan. 2 2014 recapping what they believe will be the end results from 2013 (subject to the usual and customary revisions, of course). The presentaiton shows that all of the firings (over 1,200 people) in 2013 had their effect--capital expenditures were down 48% for the year. Income and profits were up (150% and 33% respectively) for the year.

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Chesapeake Energy Investory Presentation January 2014

  1. 1. January 2014 Investor Presentation JANUARY 2014 INVESTOR PRESENTATION
  2. 2. January 2014 Investor Presentation 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 those of historical fact that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, assumptions regarding future natural gas and liquids prices, anticipated asset sales, planned drilling activity and drilling and completion capital expenditures and other anticipated cash outflows, as well as projected cash flow and liquidity, business strategy and other plans and objectives for future operations.  Disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date, and such market prices are subject to significant volatility. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Our ability to generate sufficient operating cash flow to fund future capital expenditures is subject to all the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Pending sales transactions are subject to closing conditions and may not be completed in the time frame anticipated. Further, asset sales we are evaluating as we focus on our strategic priorities are subject to market conditions and other factors beyond our control. Our plans to reduce financial leverage and complexity may take longer to implement if such sales are delayed or do not occur as expected.  Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of our 2012 annual report on Form 10-K filed with the U.S. Securities and Exchange Commission on March 1, 2013. These risk factors include the volatility of natural gas, oil and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; declines in the prices of natural gas and oil potentially resulting in a write-down of our asset carrying values; the availability of capital on an economic basis, including through planned asset sales, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas, oil 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; hedging activities resulting in lower prices realized on natural gas, oil and NGL sales; the need to secure hedging liabilities and the inability of hedging counterparties to satisfy their obligations; drilling and operating risks, including potential environmental liabilities; legislative and regulatory changes adversely affecting our industry and our business, including initiatives related to hydraulic fracturing, air emissions and endangered species; current worldwide economic uncertainty which may have a material adverse effect on our results of operations, liquidity and financial condition; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; losses possible from pending or future litigation and regulatory investigations; cyber attacks adversely impacting our operations; and the loss of key operational personnel or inability to maintain our corporate culture.  Although we believe the expectations and forecasts reflected in 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. 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 this information. 2
  3. 3. January 2014 Investor Presentation 3Q’13 FINANCIAL RESULTS ADJ. EARNINGS/FDS OP. CASH FLOW ADJ. EBITDA 330% YOY 29% YOY 22% YOY $0.43 $1.3 billion $1.4 billion LIQUIDITY $5.2 billion YTD ASSET SALES (1) $4.2 billion TOTAL CAPEX (2) 57% YOY (3) $1.5 billion (1) Includes unrestricted cash and borrowing availability under revolving credit facilities as of 9/30/2013 (2) Includes $3.6 billion of asset sales completed as of 9/30/2013 and ~$600 million of asset sales completed or under contract in 4Q’13 (3) Includes drilling and completion expenditures, leasehold and other Note: Reconciliation of non-GAAP measures to comparable GAAP measures appear on pages 26-27 3
  4. 4. January 2014 Investor Presentation 3Q’13 OPERATIONAL RESULTS TOTAL PRODUCTION LIQUIDS MIX 27% OIL PRODUCTION 2% YOY to 4.0 bcfe/d Up from 21% in 3Q’12 NGL PRODUCTION 23% YOY of Total Production(1) 120 mbbls/d GAS PRODUCTION 31% YOY 10% YOY 58.5 mbbls/d 3.0 bcf/d 3Q’13 total organic production growth rate of ~8% YOY, as adjusted for asset sales (1) Oil and NGL collectively referred to as “liquids” 4
  5. 5. January 2014 Investor Presentation GREAT FUTURE, GREAT ASSETS Natural gas plays Liquid plays Wet-gas window Operating states Utica Shale Marcellus Shale Powder River Basin: Niobrara Shale Anadarko Basin: Mississippi Lime Barnett Shale Anadarko Basin: Cleveland and Tonkawa Tight Sands Anadarko Basin: Texas Panhandle Granite Wash Haynesville/Bossier Shales Anadarko Basin: Colony Granite Wash OKC Headquarters 15.7 tcfe of proved reserves(1) Eagle Ford Shale 4.0 bcfe/d of production (1) Based on SEC pricing. Using 10-year average NYMEX strip prices as of 12/31/12, proved reserves were 19.6 tcfe 13 mm net acres of leasehold 5
  6. 6. January 2014 Investor Presentation IMPROVING STATE OF CHESAPEAKE  Delivered strong third quarter results › Full-year 2013 plan is on track  Implemented new strategy capitalizing on CHK’s speed  Completed transformational review and reorganization › Implementing new operational processes to reduce costs, increase efficiencies and enhance returns › ~20% reduction in E&P workforce  Essential elements for success in place… › Business units › Capital allocation process › Strategic metrics › Performance management/compensation system It’s a new day at CHK – we have reached an inflection point 6
  7. 7. January 2014 Investor Presentation KEY STRATEGIC TENETS  Financial discipline › Balance capital expenditures with cash flow from operations › Competitive capital allocation process › Divest noncore assets and noncore affiliates › Reduce financial and operational risk and complexity › Achieve investment grade metrics  Profitable and efficient growth from captured resources › Develop world-class inventory › Target top-quartile operating and financial metrics › Aggressively benchmark and post appraise our performance › Pursue continuous improvement › Drive value leakage out of operations › New play entry: substitution vs. addition 7
  8. 8. January 2014 Investor Presentation OUR FOCUS  Value-based vs. activity-based drilling program › Core drilling, cost leadership and cycle time improvement will add >$1 billion in PV10 per year  Balance sheet improvement › Continue non-core asset sales program  Production growth in 2014 and beyond › Decrease downtime and optimize base production  Reduce well costs and operating/overhead expenses 8
  9. 9. January 2014 Investor Presentation KEY NEAR-TERM VALUE INITIATIVES  Well cost reduction › Enhances returns on core portfolio › Builds additional economic inventory  Cycle time reduction › 2013 avg. cycle time of ~8 months from spud to TIL › Targeting improvement of 30-60%  Supply chain purchasing power › CHK will no longer be a price taker  Optimizing iron – 40% rig count reduction YOY › More efficient equipment/crews  Completion planning and optimization 9
  10. 10. January 2014 Investor Presentation FOCUSING CAPITAL ON CORE E&P OPERATIONS Drilling and Completion Capex Leasehold Capex $13.2 $13.6 Other Capex Operating Cash Flow $13.4 $6.9 $5.7 59% 41% 55% 66% 82% Devoting >80% capex to drilling and completion activities in 2013 vs. an average of ~50% during 2010-2012 10
  11. 11. January 2014 Investor Presentation NOW POSITIONED TO FOCUS ON EFFICIENCY Pad Drilling in Growth Plays  Target our best rock – improve EURs and IPs  Capture drilling efficiency gains of 15 - 30% by utilizing pre-existing pads and implementing other cost-reduction initiatives  Optimize field development and infrastructure  Right-size drilling program to capture greatest value With HBP efforts largely complete, CHK has greater capital flexibility in 2014 11
  12. 12. January 2014 Investor Presentation EAGLE FORD SHALE 3Q’13 Net Production: CHK leasehold Operated rigs Industry rigs 12% NGL 20% Gas ~95 mboe/d 68% Oil Oil window Wet-gas window Dry-gas window  Connected 100 wells to sales in 3Q’13 with an avg. peak daily rate of ~930 boe/d  788 producing wells and 117 wells WOPL or in various stages of completion(1)  HBP drilling largely complete: ~75% acres HBP’d in the core  ~70% of wells drilling on existing pads in 2H’13E, anticipate ~85% in 2014  Currently operating ten rigs in the play; anticipate ramping to 15+ rigs in 2014 (1) As of 9/30/2013 12
  13. 13. January 2014 Investor Presentation EAGLE FORD GROSS OPERATED OIL PRODUCTION Chesapeake Peers Data Source: IHS Energy CHK is the second-largest gross oil producer with the fastest growth rate in the Eagle Ford Shale 13
  14. 14. January 2014 Investor Presentation UTICA PRODUCTION ACCELERATING AS INFRASTRUCTURE EXPANDS CHK contracted facilities OHIO Third-party facilities CHK leasehold ATEX pipeline CHK/TOT JV outline Operated rigs Industry rigs Nisource/Hilcorp Kensington 200 mmcf/d  3Q’13 daily net production of ~165 mmcfe/d › Up 91% sequentially  Connected 63 wells to sales in 3Q with an avg. peak daily rate of ~6.6 mmcfe/d  Drilled 377 wells in the Utica play as of 9/30 › Includes 169 producing wells, 208 WOPL or in various stages of completion Leesville PENNSYLVANIA  Phase I of processing at Kensington (200 mmcf/d) started 7/13; Phase II (200 mmcf/d) expected to start up 12/13  ATEX ethane pipeline expected to start up 12/13  Currently operating nine rigs in the play Cadiz Seneca Natrium 200 mmcf/d Hastings 180 mmcf/d WEST VIRGINIA (1) CHK contracted facilities reflect plant capacity, not CHK’s contract volumes. 14
  15. 15. January 2014 Investor Presentation NORTHERN MARCELLUS 3Q’13 Net Production: ~825 mmcf/d CHK leasehold CHK core CHK core of the core CHK operated rigs Industry rigs       Connected 37 wells to sales in 3Q with an avg. peak daily rate of ~9.3 mmcfe/d 128 wells WOPL or in various stages of completion as of 9/30/13 Drilling program targeting EUR wells in excess of 10 bcfe gross ~65% of wells drilling on existing pads in 2H’13E; anticipate >80% in 2014 Currently operating five rigs in the play Contracted >550 mmcf/d of new pipeline capacity in 4Q’13 15
  16. 16. January 2014 Investor Presentation EXPECT TO DELIVER STRONG RESULTS IN 2013 ADJ. EBITDA ADJ. NET INCOME TOTAL CAPEX 33% YOY 150% YOY 2012 $3.75 billion 2013E $5.0 billion(1) 2012 $456 mm 2013E $1.14 billion(1) 48% YOY 2012 $13.4 billion 2013E $6.9 billion(2) NET WELLS TO SALES DAILY PRODUCTION OIL PRODUCTION 31% YOY 15% YOY 3% YOY 2012 31.3 mmbbls 2013E 41.0 mmbbls(3) 2012 3,886 bcfe/d 2013E 3,985 bcfe/d(3) 2012 1,225 net wells 2013E 1,045 net wells 2013 efforts are leading to increased profitability (1) 2013E projections assume NYMEX prices on open contracts of $3.50 to $3.75/mcf and $100.00/bbl. 2013E reconciliations on pages 24-25 (2) Total 2013E capex on page 9 (3) Based on the midpoint of 11/6/2013 Outlook on page 23 16
  17. 17. January 2014 Investor Presentation WHAT TO EXPECT GOING FORWARD?  Reduced capital intensity  Targets set on top-quartile operating metrics  Improved operational performance  Reduced financial leverage and complexity improvement through noncore asset and affiliate sales  2014 guidance to be provided in early 2014 Expect greater predictability, reduced risk and less complexity 17
  18. 18. January 2014 Investor Presentation CORPORATE INFORMATION CHESAPEAKE HEADQUARTERS Vice President — Investor Relations and Research DOMENIC J. DELL'OSSO, JR. Executive Vice President and Chief Financial Officer Investor Relations department can be reached by phone at (405) 935-8870 or by email at ir@chk.com 9.5% Senior Notes due 2015 #165167CD7 CHK15K 3.25% Senior Notes due 2016 #165167CJ4 CHK16 6.25% Senior Notes due 2017 #027393390 N/A 6.50% Senior Notes due 2017 #165167BS5 CHK17 #165167CE5 CHK18B 7.25% Senior Notes due 2018 #165167CC9 CHK18A #165167CF2 CHK20A 6.875% Senior Notes due 2020 #165167BU0 CHK20 6.125% Senior Notes Due 2021 #165167CG0 CHK21 5.375% Senior Notes Due 2021 #165167CK21 CHK21A 5.75% Senior Notes Due 2023 #165167CL9 CHK23 2.75% Contingent Convertible Senior Notes due 2035 #165167BW6 CHK35 2.50% Contingent Convertible Senior Notes due 2037 #165167BZ9/ #165167CA3 CHK37/ CHK37A 2.25% Contingent Convertible Senior Notes due 2038 GARY T. CLARK, CFA TICKER 6.625% Senior Notes due 2020 CORPORATE CONTACTS CUSIP 6.875% Senior Notes due 2018 6100 N. Western Avenue Oklahoma City, OK 73118 WEBSITE: www.chk.com PUBLICLY TRADED SECURITIES #165167CB1 CHK38 4.5% Cumulative Convertible Preferred Stock #165167842 #165167834/ #165167826 #U16450204/ #165167776/ #165167768 #U16450113/ #165167784/ #165167750 #165167107 CHK PrD 5.0% Cumulative Convertible Preferred Stock (Series 2005B) 5.75% Cumulative Convertible Preferred Stock 5.75% Cumulative Convertible Preferred Stock (Series A) Chesapeake Common Stock TWITTER.COM/CHESAPEAKE FACEBOOK.COM/CHESAPEAKE YOUTUBE.COM/CHESAPEAKEENERGY N/A N/A N/A CHK 18
  19. 19. January 2014 Investor Presentation APPENDIX
  20. 20. January 2014 Investor Presentation EMPHASIZING HIGHER-RETURN LIQUIDS-RICH PLAYS Operated Rigs % of Operated Drilling and Completion Capex Total Liquids Capex 140 Total Dry Gas Capex 16% 14% 84% 86% 2012 120 2013E 54% 100 70% 80 87% Liquids-rich plays 90% 60 40 46% Natural gas plays 20 0 Jan-10 30% 13% Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 2008 Jan-14 10% 2009 Drilling and Completion Capex ($ in billions) (1) $3.0 $2.5 Average Operated Rig Count 200 175 150 $2.0 2010 Production expense ($/mcfe) G&A ($/mcfe) (2) CHK Liquids % of Total Realized Revenue CHK Liquids % of Total Production $1.80 $1.60 $1.20 $0.94 $1.05 $0.92 $1.0 75 50 $0.5 $0.0 (1) (2) 25 0 65% 70% 60% $0.97 $0.88 125 100 80% $1.40 50% $0.84 $1.00 $1.5 2011 $0.83 $0.86 $0.78 $0.76 40% $0.80 30% $0.60 27% $0.40 $0.38 $0.20 $0.00 4Q’13E assumes mid-point of full year 2013 drilling and completion costs in Outlook as of 11/6/2013 Excluding stock-based compensation and restructuring and other termination benefits $0.41 $0.35 $0.35 $0.39 $0.33 $0.23 $0.25 $0.25 $0.29 20% 10% 0% 20
  21. 21. January 2014 Investor Presentation LIQUIDS-DRIVEN PRODUCTION GROWTH Miss Lime, N. Eagle Ford, Haynesville and other asset sales % Liquids ~178,000 bbls/d in 3Q’13 ~3.0 bcf/d in 3Q’13 E Chesapeake’s dry-gas production peaked in mid-2012. Associated natural gas and liquids are now driving production growth. 21
  22. 22. January 2014 Investor Presentation SENIOR NOTE PROFILE (1) $4,294 Sr. Debt and Term Loan: $12.8 Billion Term Loan Convertibles Other Sr. Notes Average Maturity: 5.1 years Average Interest Rate: 5.9% ($ in MM) $1,800 $1,660 $1,700 $1,112 $650 $500 2013 Rates 2014 $1,100 2015 2016 2017 2018 2019 2020 2021 2.75%(2) 9.5% 3.25% 5.75%(3) 2.5%(2) 6.5% 6.25% 2.25%(2) 7.25% 6.875% 6.625%(4) 6.875% 6.625% 5.375% 6.125% 2022 2023 5.75% Strong liquidity profile: ~$5.2 billion of liquidity as of 9/30/2013 (1) (2) (3) (4) As of 9/30/2013 Recognizes earliest investor put option as maturity for the 2.75% 2035, 2.5% 2037 and 2.25% 2038 Contingent Convertible Senior Notes Interest at LIBOR plus 4.50%; LIBOR rate is subject to a floor of 1.25% per annum COO $650 mm Senior Notes due 2019 22
  23. 23. January 2014 Investor Presentation OUTLOOK SUMMARY (1) 2012 2013E Natural gas (bcf) 1,129 1,080 – 1,090 Oil (mbbls) 31,265 40,000 – 42,000 NGL (mbbls) 17,615 20,000 – 21,000 Natural gas equivalent (bcfe) 1,422 1,440 – 1,468 YOY production increase (adjusted for planned asset sales) 19% 3% Natural gas production increase (decrease) 12% (4%) Liquids YOY production increase 54% 26% % production from liquids 20% 25% % realized revenues from liquids(2) 59% 63% $1.38 $1.20 – $1.35 $4,053 $5,050 – $5,100 ($8,831) ($5,500 – $5,800) ($1,718) ($200 – $250) Operating costs per mcfe: Production expense, production taxes and G&A(3) Operating cash flow ($mm)(2)(4) Drilling and completion costs on proved and unproved properties ($mm) Acquisition of unproved properties, net ($mm) (1) (2) (3) (4) As of 11/6/2013 Assumes NYMEX prices on open contracts of $3.50 to $3.75/mcf and $100.00/bbl in 2013 Excludes expenses associated with stock-based compensation and restructuring and other termination benefits Before changes in assets and liabilities. 23
  24. 24. January 2014 Investor Presentation RECONCILIATION OF 2013 FINANCIAL PROJECTIONS: ADJUSTED EBITDA TO OPERATING CASH FLOW NYMEX Natural Gas Prices $3.00 $4.00 $5.00 $6,820 $7,000 $7,190 Hedging effect(1) (30) (170) (300) Marketing, service operations and other 260 260 260 Production taxes ~4% (230) (240) (240) Production cost (LOE) (1,200) (1,200) (1,200) G&A(2) (470) (470) (470) Net income attributable to noncontrolling interests (180) (180) (180) $4,970 $5,000 $5,060 (180) (180) (180) Noncash interest expense 80 80 80 Stock-based compensation 90 90 90 Restructuring and other termination benefits (70) (70) (70) Net income attributable to noncontrolling interests 180 180 180 $5,070 $5,100 $5,160 As of 11/6/2013 Outlook ($ in mm; oil at $100 NYMEX) O/G revenue (unhedged) Adjusted ebitda Interest expense incl. capitalized interest Operating cash flow(3) (1) (2) (3) Includes effects of estimated realized hedging gains and losses and excludes effects of unrealized hedging gains and losses Includes expense related to stock-based compensation, but excludes restructuring and other termination benefits Before changes in assets and liabilities 24
  25. 25. January 2014 Investor Presentation RECONCILIATION OF 2013 FINANCIAL PROJECTIONS: OPERATING CASH FLOW TO ADJUSTED NET INCOME NYMEX Natural Gas Prices $3.00 $4.00 $5.00 Operating cash flow(1) $5,070 $5,100 $5,160 Oil and gas depreciation (2,540) (2,540) (2,540) Depreciation of other assets (330) (330) (330) Income taxes (38% rate) (800) (810) (830) Noncash interest expense (80) (80) (80) Stock-based compensation (90) (90) (90) Restructuring and other termination benefits 70 70 70 (180) (180) (180) $1,120 $1,140 $1,180 $1.47 $1.50 $1.55 As of 11/6/2013 Outlook ($ in mm; oil at $100 NYMEX) Net income attributable to noncontrolling interests Adjusted net income attributable to Chesapeake Adjusted earnings per fully diluted share (1) Before changes in assets and liabilities 25
  26. 26. January 2014 Investor Presentation RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ($ in mm, except per share data) 9/30/2013 6/30/2013 9/30/2012 $156 $457 $(2,055) Unrealized (gains) losses on derivatives Net (gains) losses on sales of fixed assets 118 (82) (325) (68) 63 4 Impairment of natural gas and oil properties Impairments of fixed assets and other _ 55 _ 143 2,022 23 Restructuring and other termination benefits (Gains) losses on sales of investments Losses on purchases of debt Premium on purchase of preferred shares of a subsidiary Other 39 (2) _ _ (2) 5 6 44 69 3 2 (19) _ _ (5) $282 $334 $35 43 3 43 11 43 _ Total adjusted net income Weighted average fully diluted shares outstanding(2) $328 765 $388 763 $78 754 Adjusted earnings per share assuming dilution(1) $0.43 $0.51 $0.10 Three Months Ended: Net income (loss) available to common stockholders Adjustments, net of tax: Adjusted net income available to common stockholders(1) Preferred stock dividends Earnings allocated to participating securities (1) (2) Adjusted net income available to common stockholders and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with accounting principles generally accepted in the United States (GAAP) because: (i) Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other natural gas and oil producing companies. (ii) Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. (iii) Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. In millions. Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP 26
  27. 27. January 2014 Investor Presentation RECONCILIATION OF OPERATING CASH FLOW, EBITDA AND ADJUSTED EBITDA ($ in mm) 9/30/2013 6/30/2013 9/30/2012 $1,356 $1,281 $949 12 89 169 $1,368 $240 $1,370 $625 $1,118 $(1,971) Interest expense Income tax expense (benefit) 40 147 104 384 36 (1,260) Depreciation and amortization of other assets Natural gas, oil and NGL depreciation, depletion and amortization 79 652 76 645 66 762 $1,158 $1,834 $(2,367) 191 _ (132) 89 (38) (3) _ 63 (3) (576) _ (109) 231 (45) 10 70 7 2 104 3,315 7 38 (41) (31) _ 3 (4) $1,325 $1,424 $1,024 Three Months Ended: Cash provided by operating activities Changes in assets and liabilities Operating cash flow Net income (1) EBITDA(2) Adjustments: Unrealized (gains) losses on natural gas, oil and NGL derivatives Impairment of natural gas and oil properties Net (gains) losses on sales of fixed assets Impairments of fixed assets and other Net income attributable to noncontrolling interests (Gains) losses on sales of investments Losses on purchases of debt Restructuring and other termination benefits Other Adjusted EBITDA(3) (1) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the natural gas and oil exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. (2) Ebitda represents net income (loss) before interest expense, income taxes, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requir ements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. Ebitda is not a measure of financial performance under GAAP. Accordingly, it 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. (3) 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 natural gas and oil 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. 27
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