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.

1. January 2014 Investor Presentation
JANUARY 2014
INVESTOR PRESENTATION

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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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. 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
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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. January 2014 Investor Presentation
APPENDIX

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. 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. 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. 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. 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. 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. 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. 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.
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