Chesapeake Energy Corporation Reports Financial and Operational Results for the 2013 Full Year and Fourth Quarter

Chesapeake Energy Corporation (NYSE: CHK) today reported financial and operational results for the 2013 full year and fourth quarter. Key information related to the 2013 full year is as follows:

Adjusted net income per fully diluted share increases to $1.50 in the 2013 full year from $0.61 in the 2012 full year
Adjusted ebitda increases 34% year over year to $5.016 billion
Average daily production rises 3% year over year to 669,600 boe per day
Average daily production, adjusted for asset sales, increases 11% year over year
Combined 2013 per unit production and G&A expenses decline 15% year over year
2013 year-end proved reserves increase to 2.7 bboe
2013 asset sales total $4.4 billion; 2014 asset sales already completed or anticipated total approximately $1 billion, excluding possible oilfield services division and other strategic asset dispositions

Doug Lawler, Chesapeake’s Chief Executive Officer, said, "2013 was a foundational year in which we focused on optimizing our business processes, implementing a disciplined capital budget, decreasing per unit cash costs, selling noncore assets and reducing liabilities. We believe that the impact of these efforts on our capital efficiency and returns will become even more evident in 2014 as we continue to drive well performance up and well costs and per unit cash costs down. In 2014 we plan to reduce drilling and completion costs, before drilling carry credits, by nearly $900 million, while still generating comparable production growth year over year."

For the 2013 full year Chesapeake reported net income available to common stockholders of $474 million, or $0.73 per fully diluted share. These results include the after-tax impact of the following items typically excluded by securities analysts in their earnings estimates:

a charge of $341 million for the impairment of certain of the company’s property and equipment and other assets;
a $154 million charge for restructuring and other termination costs;
charges of $120 million for the purchase of debt and the extinguishment of a lease obligation in the Fort Worth, Texas area;
net losses of $95 million on certain investments, primarily related to our proportionate share of an estimated impairment recorded by FTS International, Inc. on its non-depreciable assets;
a net gain of $187 million on sales of certain of the company’s fixed assets; and
noncash unrealized gains of $100 million from the company’s derivative instruments.

In total, these items reduced net income available to common stockholders for the 2013 full year by approximately $422 million on an after-tax basis. Adjusting for these items, 2013 full-year net income available to common stockholders was $896 million, or $1.50 per fully diluted share, which compares to adjusted net income available to common stockholders of $285 million, or $0.61 per fully diluted share, in the 2012 full year. This increase is primarily the result of substantially higher year-over-year oil production, higher realized oil, natural gas and natural gas liquids (NGL) prices, and lower per unit production and general and administrative (G&A) expenses.

For the 2013 full year the company reported adjusted ebitda of $5.016 billion, an increase of 34% year over year. Operating cash flow, which is cash flow provided by operating activities before changes in assets and liabilities, was $4.956 billion in 2013, an increase of 26% year over year. Full-year 2013 operating cash flow was negatively impacted by approximately $120 million due to the extinguishment of certain financing obligations in the Fort Worth, Texas area, $73 million of employee restructuring and other termination costs as well as $63 million of charges primarily related to the termination of rig lease and other commitments. The charges were the result of the company's strategic decision to reduce leverage and balance sheet complexity and are excluded from adjusted net income.

2013 Full-Year Average Daily Production Increases 3% Year over Year to 670 Mboe per Day; Oil Production Increases 32% Year over Year to More Than 112 Mbbls per Day

Chesapeake’s daily production for the 2013 full year averaged approximately 669,600 barrels of oil equivalent (boe), an increase of 3% compared to the 2012 full year. The company’s 2013 average daily production consisted of approximately 112,600 barrels (bbls) of oil, 57,200 bbls of NGL and 3.0 billion cubic feet (bcf) of natural gas.

In 2013 average daily oil production increased 32% year over year, average daily NGL production increased 19% year over year and natural gas production decreased 3% year over year. Liquids accounted for 25% of total production, up from 20% during the 2012 full year. Adjusted for asset sales, the company's total 2013 production increased approximately 11% year over year.

2013 Fourth Quarter Results

For the 2013 fourth quarter Chesapeake reported a net loss available to common stockholders of $159 million, or $0.24 per fully diluted share. Items typically excluded by securities analysts in their earnings estimates decreased 2013 fourth quarter net income by approximately $320 million on an after-tax basis. Adjusting for these items, 2013 fourth quarter net income available to common stockholders was $161 million, or $0.27 per fully diluted share, which compares to adjusted net income available to common stockholders of $146 million, or $0.26 per fully diluted share, in the 2012 fourth quarter.

For the 2013 fourth quarter Chesapeake reported adjusted ebitda of $1.132 billion, an increase of 4% year over year. Operating cash flow was $995 million, a decrease of 13% year over year. Operating cash flow was negatively impacted in the 2013 fourth quarter by approximately $120 million due to the extinguishment of certain financing obligations in the Fort Worth, Texas area, $34 million of employee restructuring and other termination costs, as well as $37 million of charges primarily related to the termination of rig lease commitments. The charges were the result of the company's strategic decision to reduce leverage and balance sheet complexity and are excluded from adjusted net income.

2013 full-year and fourth quarter adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are non-GAAP financial measures. Reconciliations of these measures to comparable financial measures calculated in accordance with generally accepted accounting principles are provided on pages 15 – 19 of this release.

2013 Fourth Quarter Average Daily Production Increases 2% Year over Year to 665 Mboe per Day; Oil Production Increases 15% Year over Year to More Than 111 Mbbls per Day

Chesapeake’s daily production for the 2013 fourth quarter averaged approximately 665,100 boe, an increase of 2% from the 2012 fourth quarter and a 1% decrease from the 2013 third quarter. This decrease is primarily due to a planned reduction in well connections during the fourth quarter as the company completed most of its well inventory reduction initiatives in the 2013 second and third quarters. Severe weather also negatively impacted the company's production in October and December. Average daily production in the 2013 fourth quarter consisted of approximately 111,300 bbls of oil, 63,700 bbls of NGL and 2.9 bcf of natural gas.

For the 2013 fourth quarter average daily oil production increased 15% year over year and decreased 7% sequentially, average daily NGL production increased 26% year over year and 9% sequentially and natural gas production decreased 3% year over year and 1% sequentially. Liquids accounted for 26% of total production during the 2013 fourth quarter, up from 23% during the 2012 fourth quarter and down from 27% during the 2013 third quarter. Adjusted for asset sales, the company's total production in the 2013 fourth quarter increased approximately 10% year over year.

Asset Sales Update

In 2014 the company has already received $209 million of net proceeds from the sale of its common equity ownership interest in Chaparral Energy, Inc. Additionally, in connection with certain asset sales in 2012 and 2013, the company believes that it will receive proceeds in excess of $150 million during 2014 that were held back for title review or other purposes at the time of closing. Currently, Chesapeake is marketing or has under contract sales of certain real estate and other non-E&P assets, excluding its oilfield services division, Chesapeake Oilfield Services (COS), which are expected to generate proceeds of approximately $650 million during 2014. Together, the items listed above are expected to generate proceeds of approximately $1 billion, and the company believes the sale of these assets will have minimal impact on its 2014 operating cash flow guidance.

Domenic J. Dell'Osso, Jr., Chesapeake's Chief Financial Officer, said, "In 2013 we improved our net working capital, net long-term debt and other long-term liability position by more than $900 million, in aggregate. As outlined, we have good visibility into approximately $1 billion of proceeds from asset sales in 2014. We are continuing to review and refine our portfolio for assets that fit best with the company’s strategy of profitable growth from captured resources and expect to have additional asset dispositions in 2014, potentially including a spin-off of COS to Chesapeake shareholders or an outright sale. Closing such incremental transactions would enable us to further reduce financial complexity and overall leverage."

Capital Spending and Cost Overview

During the 2013 full year Chesapeake operated an average of 71 rigs and invested approximately $5.5 billion in drilling and completion activities. This level of capital spending represented a decrease of 38% compared to the 2012 full year. Chesapeake spud a total of 1,097 gross wells and completed 1,359 gross wells during the 2013 full year, compared to 1,653 gross wells spud and 1,562 gross wells completed during the 2012 full year.

During the 2013 fourth quarter Chesapeake operated an average of 57 rigs and invested approximately $1.2 billion in drilling and completion activities. This level of capital spending represented a decrease of approximately $100 million, or 8%, compared to the 2013 third quarter. Chesapeake spud a total of 239 gross wells and completed 274 gross wells during the 2013 fourth quarter, compared to 253 gross wells spud and 321 gross wells completed during the 2013 third quarter. During 2014 Chesapeake plans to operate 55 – 65 rigs.

Net expenditures for the acquisition of unproved properties were approximately $60 million during the 2013 fourth quarter and approximately $205 million for the 2013 full year. Other capital expenditures were approximately $390 million during the 2013 fourth quarter and approximately $1.0 billion for the 2013 full year. These include approximately $235 million of expenditures in the 2013 fourth quarter to purchase rigs and compressors subject to sale leaseback arrangements as part of a strategic initiative to reduce leverage and facilitate asset sales and possible spin-off or sale of COS.

Average production expenses during the 2013 full year were $4.74 per boe, a decrease of 14% year over year. G&A expenses (excluding share-based compensation and restructuring and other termination costs) during the 2013 full year were $1.62 per boe, a decrease of 17% year over year.

Average production expenses during the 2013 fourth quarter were $4.62 per boe, an increase of 2% from the 2013 third quarter. G&A expenses (excluding share-based compensation and restructuring and other termination costs) during the 2013 fourth quarter were $1.79 per boe, an increase of 5% from the 2013 third quarter.

A complete summary of the company’s guidance for 2014 was provided in the Outlook dated February 6, 2014 and is attached to this release as Schedule "A” beginning on Page 20.

Total Proved Reserves Increase to 2.7 Bboe

The company's December 31, 2013 proved reserves were 2.7 billion barrels of oil equivalent (bboe), a 2% increase from year-end 2012. During 2013 Chesapeake added 332 million barrels of oil equivalent (mmboe) through extensions and discoveries, net of downward revisions primarily associated with the elimination of certain future proved undeveloped locations. The company's year-end 2013 total proved reserves also increased by 162 mmboe due to the effect of higher natural gas prices, and decreased by 189 mmboe as the result of net divestitures. Chesapeake's proved developed reserves as a percentage of total proved reserves increased to 68% at December 31, 2013 from 57% at December 31, 2012. Additional information on reserves changes can be found on Page 12.

The following table presents Chesapeake’s December 31, 2013 proved reserves, estimated future net cash flows from proved reserves discounted at an annual rate of 10% before income taxes (PV-10) and proved developed percentage using alternative pricing methods.

Pricing Method

Natural Gas Price

($/mcf)

Oil Price

($/bbl)

Proved

Reserves

(Bboe)

PV-10

(billions)

Proved

Developed

Percentage

Trailing 12-month average (SEC)(a) $3.67 $96.82 2.678 $21.7 68% 12/31/13 average NYMEX strip(b) $4.34 $81.48 2.732 $22.2 69%

a) Reserve volumes estimated using Securities and Exchange Commission (SEC) reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2013. This pricing yields estimated proved reserves for SEC reporting purposes.

b) The 10-year average NYMEX strip is an alternative pricing scenario that illustrates the sensitivity of proved reserves to a different pricing assumption. Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company’s proved reserves than the historical 12-month average price.

Operational Update

The company continues to achieve strong operational results and well cost reductions in each of its most active plays. Chesapeake employs conservative choke management practices in several of its key operating areas in order to maximize ultimate reservoir recovery and optimize use of midstream capacity.

Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 87,000 boe per day (191,000 gross operated boe per day) during the 2013 fourth quarter. This production represents an increase of 39% year over year and a decrease of 8% sequentially. Fourth quarter production was adversely affected by weather impacts as well as a planned inventory reduction that occurred during the 2013 second and third quarters. Approximately 68% of the company’s Eagle Ford production in the 2013 fourth quarter was oil, 14% was NGL and 18% was natural gas.

Chesapeake operated an average of 12 rigs and connected 65 gross wells to sales during the 2013 fourth quarter in the Eagle Ford, compared to 13 average operated rigs and 100 gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 65 wells that commenced first production in the Eagle Ford during the 2013 fourth quarter was approximately 800 boe per day.

As of December 31, 2013, Chesapeake had 862 producing wells and 109 wells awaiting pipeline or in various stages of completion in the Eagle Ford.

During 2014 Chesapeake plans to reduce average completed well costs in the Eagle Ford to $6.4 million or less per well, which would represent an approximate 7% reduction year over year. Production growth is expected to accelerate in the Eagle Ford during the 2014 second quarter as the company substantially increases its rig count and well connections.

Mid-Continent (Oklahoma, Texas Panhandle, southern Kansas): Chesapeake's production in the Mid-Continent comes primarily from five plays: the Mississippi Lime, Granite Wash, Cleveland, Tonkawa and Hogshooter. Aggregate net production from these plays during the 2013 fourth quarter averaged 104,000 boe per day (192,000 gross operated boe per day), which was flat year over year and a decrease of 4% sequentially. Approximately 32% of the company’s Mid-Continent production during the 2013 fourth quarter was oil, 23% was NGL and 45% was natural gas.

During the 2013 fourth quarter Chesapeake operated an average of 17 rigs and connected 70 gross wells to sales, compared to 22 average operated rigs and 89 gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 70 wells that commenced first production in the Mid-Continent during the 2013 fourth quarter was approximately 875 boe per day.

As of December 31, 2013, the company had 32 wells awaiting pipeline connection or in various stages of completion in the Mid-Continent.

As Chesapeake has optimized its drilling program and reduced its rig count in the Mid-Continent, drilling success rates and program rates of return have improved significantly. Given the reduction in drilling activity coupled with 2013 asset sales, the company anticipates that net production from the Mid-Continent will decline during 2014 on a year-over-year basis.

Haynesville Shale (Northwest Louisiana, East Texas): Chesapeake’s 2013 fourth quarter average daily net production in the Haynesville was approximately 540 million cubic feet of natural gas equivalent (mmcfe) per day (880 gross operated mmcfe per day), a decrease of 51% year over year and 19% sequentially. All of the company's production in the Haynesville consists of natural gas.

During the 2013 fourth quarter Chesapeake operated an average of four rigs and connected 12 gross wells to sales, compared to two average operated rigs and four gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 12 wells that commenced first production in the Haynesville during the 2013 fourth quarter was approximately 12.8 mmcfe per day.

As of December 31, 2013, Chesapeake had 11 wells awaiting pipeline connection or in various stages of completion in the Haynesville.

Utica Shale (eastern Ohio, Pennsylvania, West Virginia): Utica net production averaged approximately 189 mmcfe per day (345 gross operated mmcfe per day) during the 2013 fourth quarter, an increase of 309% year over year and 15% sequentially from the 2013 third quarter.

During the 2013 fourth quarter Chesapeake operated an average of nine rigs and connected 49 gross wells to sales in the Utica, compared to 11 average operated rigs and 63 gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 49 wells that commenced first production in the Utica during the 2013 fourth quarter was approximately 7.7 mmcfe per day.

As of December 31, 2013, Chesapeake had drilled a total of 425 wells in the Utica, which included 230 producing wells and 195 wells awaiting pipeline connection or in various stages of completion.

Midstream processing infrastructure build-out delays and operational issues impacted Chesapeake's growth ramp in the Utica during the second half of 2013 and will continue to have an impact to a lesser degree in the first quarter of 2014. As a result of the infrastructure and operational issues, the vast majority of Chesapeake's wells that are connected to sales lines are on restricted choke and have not been producing at full capacity. Service resumed at the Natrium processing plant in January 2014, and assuming the mid-year addition of the third phase of gas processing at the Kensington facility, Chesapeake anticipates that it will achieve net production of 700 mmcfe per day in the Utica by year-end 2014.

Northern Marcellus Shale (Pennsylvania): Chesapeake's production from the northern Marcellus continued to grow during the 2013 fourth quarter. Average daily net production in this play was approximately 880 mmcfe per day (2,100 gross operated mmcfe per day), an increase of 36% year over year and 7% sequentially. All of the company's production in the northern Marcellus consists of natural gas.

During the 2013 fourth quarter Chesapeake operated an average of five rigs and connected 33 gross wells to sales, compared to five average operated rigs and 37 gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 33 wells that commenced first production in the northern Marcellus during the 2013 fourth quarter was approximately 10.8 mmcfe per day.

As of December 31, 2013, Chesapeake had 112 wells awaiting pipeline connection or in various stages of completion in the northern Marcellus.

Chesapeake's wells in the northern Marcellus continue to exceed expectations, and at current rig levels and projected natural gas prices the company expects this region to contribute substantial positive cash flow in 2014. In the three-year period ended December 31, 2013, net daily production from the northern Marcellus grew 56% on a compounded annual basis.

Southern Marcellus Shale (Pennsylvania, West Virginia): During the 2013 fourth quarter, Chesapeake’s average daily net production in the southern wet-gas portion of the Marcellus was approximately 285 mmcfe per day (460 gross operated mmcfe per day), an increase of 82% year over year and 3% sequentially. Approximately 12% of the company’s southern Marcellus production was oil, 18% was NGL and 70% was natural gas.

During the 2013 fourth quarter Chesapeake operated an average of two rigs and connected 13 gross wells to sales, compared to three average operated rigs and 30 gross wells connected to sales during the 2013 third quarter. The average peak daily production rate of the 13 wells that commenced first production in the southern Marcellus during the 2013 fourth quarter was approximately 8.1 mmcfe per day.

As of December 31, 2013, Chesapeake had 47 wells awaiting pipeline connection or in various stages of completion in the southern Marcellus.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2013 fourth quarter and 2013 full year and compares them to results in prior periods.

Three Months Ended Full Year Ended 12/31/13 09/30/13 12/31/12 12/31/13 12/31/12 Oil equivalent production (in mmboe) 61.2 62.0 60.3 244.4 237.0 Oil production (in mmbbls) 10.2 11.0 8.9 41.1 31.3 Average realized oil price ($/bbl)(a) 89.58 92.09 92.23 92.53 91.74 Oil as % of total production 17 18 15 17 13 NGL production (in mmbbls) 5.9 5.4 4.6 20.9 17.6 Average realized NGL price ($/bbl)(a) 31.76 26.52 27.12 27.87 29.37 NGL as % of total production 9 9 8 8 7 Liquids as % of realized revenue(b) 68 65 62 64 59 Liquids as % of unhedged revenue(b) 69 69 59 64 63 Natural gas production (in bcf) 271 273 280 1,095 1,129

Average realized natural gas price ($/mcf)(a)

1.90 2.26 2.07 2.23 2.07 Natural gas as % of total production 74 73 77 75 80 Natural gas as % of realized revenue 32 35 38 36 41 Natural gas as % of unhedged revenue 31 31 41 36 37 Production expenses ($/boe) (4.62 ) (4.55 ) (4.96 ) (4.74 ) (5.50 ) Production taxes ($/boe) (0.91 ) (0.99 ) (0.77 ) (0.94 ) (0.79 ) General and administrative costs ($/boe)(c) (1.79 ) (1.71 ) (1.38 ) (1.62 ) (1.96 ) Share-based compensation ($/boe) (0.19 ) (0.21 ) (0.27 ) (0.24 ) (0.30 ) DD&A of natural gas and liquids properties ($/boe) (10.53 ) (10.52 ) (10.80 ) (10.59 ) (10.58 ) D&A of other assets ($/boe) (1.32 ) (1.28 ) (1.18 ) (1.28 ) (1.28 ) Interest expense ($/boe)(a) (0.86 ) (0.65 ) (0.28 ) (0.65 ) (0.35 )

Marketing, gathering and compression net margin ($ in millions)(d)

9 23 41 99 119

Oilfield services net margin ($ in millions)(d)

52 38 16 159 142 Operating cash flow ($ in millions)(e) 995 1,413 1,138 4,956 3,920 Operating cash flow ($/boe) 16.26 22.80 18.88 20.28 16.54 Adjusted ebitda ($ in millions)(f) 1,132 1,325 1,088 5,016 3,754 Adjusted ebitda ($/boe) 18.51 21.38 18.06 20.52 15.84

Net income (loss) available to common stockholders ($ in millions)

(159 ) 156 250 474 (940 ) Earnings (loss) per share – diluted ($) (0.24 ) 0.24 0.39 0.73 (1.46 )

Adjusted net income available to common stockholders ($ in millions)(g)

161 282 146 896 285 Adjusted earnings per share – diluted ($) 0.27 0.43 0.26 1.50 0.61

(a) Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.

(b) "Liquids” includes both oil and NGL.

(d) Includes revenue and operating costs and excludes depreciation and amortization of other assets, general and administrative expenses, impairments of fixed assets and other, and gains or losses on sales of fixed assets.

(e) Defined as cash flow provided by operating activities before changes in assets and liabilities.

(f) Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on Page 19.

(g) Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 15.

2013 Fourth Quarter and Full-Year Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, February 26, 2014, at 9:00 am EST. The telephone number to access the conference call is 913-312-9330 or toll-free 888-801-6507. The passcode for the call is 9127661. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the conference call, a replay will be available for audio playback at 2:00 pm EST on Wednesday, February 26, 2014, and will run through 2:00 pm EST on Wednesday, March 12, 2014. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 9127661. The conference call will also be webcast live on Chesapeake’s website at www.chk.com in the "Events” subsection of the "Investors” section of the website. The webcast of the conference will be available on the company’s website for one year.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 10th largest producer of oil and natural gas liquids in the U.S. Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional natural gas and oil assets onshore in the U.S. The company also owns substantial marketing, compression and oilfield services businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

Any separation of COS is subject to satisfaction of several conditions, some of which are beyond our control, including market conditions, board approvals, consents, regulatory review and approvals, among others. There can be no assurance that the proposed separation will lead to a sale or spin-off or any other transaction, or that if any transaction is pursued, that it will be consummated.

This news release and the accompanying Outlook include "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 that give our current expectations or forecasts of future events. They include production forecasts, estimates of operating costs, planned development drilling, expected capital expenditures, expected efficiency gains, anticipated asset sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. 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 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 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; oilfield services shortages, gathering system and transportation capacity constraints and various transportation interruptions that could adversely affect our revenues and cash flow; adverse developments and losses in connection with pending or future litigation and regulatory investigations; and cyber attacks adversely impacting our operations. 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. Further, the timing of and amount of proceeds from future asset sales, which are subject to changes in market conditions and other factors beyond our control, will affect our ability to reduce financial leverage and complexity and enhance our liquidity. 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 this release or the accompanying Outlook.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per share data)

(unaudited)

Three Months Ended December 31, Year Ended December 31, 2013 2012 2013 2012 REVENUES: Natural gas, oil and NGL $ 1,608 $ 1,657 $ 7,052 $ 6,278 Marketing, gathering and compression 2,689 1,721 9,559 5,431 Oilfield services 244 161 895 607 Total Revenues 4,541 3,539 17,506 12,316 OPERATING EXPENSES: Natural gas, oil and NGL production 282 299 1,159 1,304 Production taxes 56 47 229 188 Marketing, gathering and compression 2,680 1,681 9,461 5,312 Oilfield services 193 145 736 465 General and administrative 121 99 457 535 Restructuring and other termination costs 45 3 248 7

Natural gas, oil and NGL depreciation, depletion and amortization

644 651 2,589 2,507 Depreciation and amortization of other assets 80 71 314 304 Impairment of natural gas and oil properties — — — 3,315 Impairments of fixed assets and other 203 59 546 340 Net gains on sales of fixed assets (12 ) (272 ) (302 ) (267 ) Total Operating Expenses 4,292 2,783 15,437 14,010 INCOME (LOSS) FROM OPERATIONS 249 756 2,069 (1,694 ) OTHER INCOME (EXPENSE): Interest expense (63 ) (14 ) (227 ) (77 ) Losses on investments (189 ) (16 ) (226 ) (103 ) Gains (losses) on sales of investments — 31 (7 ) 1,092 Losses on purchases of debt and extinguishment of other financing (123 ) (200 ) (193 ) (200 ) Other income 7 6 26 8 Total Other Income (Expense) (368 ) (193 ) (627 ) 720 INCOME (LOSS) BEFORE INCOME TAXES (119 ) 563 1,442 (974 ) INCOME TAX EXPENSE (BENEFIT): Current income taxes 13 23 22 47 Deferred income taxes (58 ) 196 526 (427 ) Total Income Tax Expense (Benefit) (45 ) 219 548 (380 ) NET INCOME (LOSS) (74 ) 344 894 (594 ) Net income attributable to noncontrolling interests (42 ) (44 ) (170 ) (175 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE (116 ) 300 724 (769 ) Preferred stock dividends (43 ) (43 ) (171 ) (171 ) Premium on purchase of preferred shares of a subsidiary — — (69 ) — Earnings allocated to participating securities — (7 ) (10 ) — NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (159 ) $ 250 $ 474 $ (940 ) EARNINGS (LOSS) PER COMMON SHARE: Basic $ (0.24 ) $ 0.39 $ 0.73 $ (1.46 ) Diluted $ (0.24 ) $ 0.39 $ 0.73 $ (1.46 ) WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): Basic 656 644 653 643 Diluted 656 704 653 643

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

($ in millions)

(unaudited)

December 31, 2013 December 31, 2012 Cash and cash equivalents $ 837 $ 287 Other current assets 2,819 2,661 Total Current Assets 3,656 2,948 Property and equipment (net) 37,134 37,167 Other assets 992 1,496 Total Assets $ 41,782 $ 41,611 Current liabilities $ 5,515 $ 6,266 Long-term debt, net of discounts 12,886 12,157 Other long-term liabilities 1,834 2,485 Deferred income tax liabilities 3,407 2,807 Total Liabilities 23,642 23,715 Preferred stock 3,062 3,062 Noncontrolling interests 2,145 2,327 Common stock and other stockholders’ equity 12,933 12,507 Total Equity 18,140 17,896 Total Liabilities and Equity $ 41,782 $ 41,611 Common Shares Outstanding (in millions) 664 664

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

($ in millions)

(unaudited)

December 31, 2013 December 31, 2012 Total debt, net of unrestricted cash $ 12,049 $ 12,333 Preferred stock 3,062 3,062 Noncontrolling interests(a) 2,145 2,327 Common stock and other stockholders’ equity 12,933 12,507 Total $ 30,189 $ 30,229 Total debt to capitalization ratio 40 % 41 %

(a) Includes third-party ownership as follows:

CHK Cleveland Tonkawa, L.L.C. $ 1,015 $ 1,015 CHK Utica, L.L.C. 807 950 Chesapeake Granite Wash Trust 314 356 Other 9 6 Total $ 2,145 $ 2,327

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

12 MONTHS ENDED DECEMBER 31, 2013

(unaudited)

Mmboe(a) Beginning balance, December 31, 2012 2,615 Production (244 ) Acquisitions 2 Divestitures (189 ) Revisions - changes to previous estimates (192 ) Revisions - price 162 Extensions and discoveries 524 Ending balance, December 31, 2013 2,678 Proved reserves growth rate before acquisitions and divestitures 10 % Proved reserves growth rate after acquisitions and divestitures 2 % Proved developed reserves 1,809 Proved developed reserves percentage 68 % PV-10 ($ in millions)(a) $ 21,676

(a) Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2013 of $3.67 per mcf of natural gas and $96.82 per bbl of oil, before field differential adjustments.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)

December 31, 2013 December 31, 2012 Standardized measure of discounted future net cash flows $ 17,390 $ 14,666 Discounted future cash flows for income taxes 4,286 3,107 Discounted future net cash flows before income taxes (PV-10) $ 21,676 $ 17,773

PV-10 is discounted (at 10%) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with Accounting Standards Codification Topic 932. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company.

The company’s PV-10 and standardized measure were calculated using the following prices, before field differentials: $3.67 per mcf of natural gas and $96.82 per bbl of oil as of December 31, 2013 and $2.76 per mcf of natural gas and $94.84 per bbl of oil as of December 31, 2012, before field differential adjustments.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA - NATURAL GAS, OIL AND NGL PRODUCTION, SALES AND INTEREST EXPENSE

(unaudited)

Three Months EndedDecember 31, Twelve Months EndedDecember 31, 2013 2012 2013 2012 Net Production: Natural gas (bcf) 270.5 280.2 1,094.6 1,128.8 Oil (mmbbl) 10.2 8.9 41.1 31.3 NGL (mmbbl) 5.9 4.6 20.9 17.6 Oil equivalent (mmboe) 61.2 60.3 244.4 237.0 Natural Gas, Oil and NGL Sales ($ in millions): Natural gas sales $ 498 $ 645 $ 2,430 $ 2,004 Natural gas derivatives – realized gains (losses)(a) 17 (63 ) 9 328 Natural gas derivatives – unrealized gains (losses) (127 ) 70 (52 ) (331 ) Total Natural Gas Sales 388 652 2,387 2,001 Oil sales 937 790 3,911 2,829 Oil derivatives – realized gains (losses)(a) (19 ) 34 (108 ) 39 Oil derivatives – unrealized gains (losses) 116 54 280 857 Total Oil Sales 1,034 878 4,083 3,725 NGL sales 186 126 582 526 NGL derivatives – realized gains (losses)(a) — — — (9 ) NGL derivatives – unrealized gains (losses) — 1 — 35 Total NGL Sales 186 127 582 552 Total Natural Gas, Oil and NGL Sales $ 1,608 $ 1,657 $ 7,052 $ 6,278

Average Sales Price – excluding gains (losses) on derivatives:

Natural gas ($ per mcf) $ 1.84 $ 2.30 $ 2.22 $ 1.77 Oil ($ per bbl) $ 91.46 $ 88.44 $ 95.17 $ 90.49 NGL ($ per bbl) $ 31.76 $ 27.20 $ 27.87 $ 29.89 Oil equivalent ($ per boe) $ 26.49 $ 25.90 $ 28.33 $ 22.61

Average Sales Price – excluding unrealized gains (losses) on derivatives(a):

Natural gas ($ per mcf) $ 1.90 $ 2.07 $ 2.23 $ 2.07 Oil ($ per bbl) $ 89.58 $ 92.23 $ 92.53 $ 91.74 NGL ($ per bbl) $ 31.76 $ 27.12 $ 27.87 $ 29.37 Oil equivalent ($ per boe) $ 26.44 $ 25.41 $ 27.92 $ 24.12 Interest Expense (Income) ($ in millions): Interest(b) $ 56 $ 17 $ 169 $ 84 Derivatives – realized (gains) losses (3 ) — (9 ) (1 ) Derivatives – unrealized (gains) losses 10 (3 ) 67 (6 ) Total Interest Expense $ 63 $ 14 $ 227 $ 77

(a) Includes settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.

(b) Net of amounts capitalized.

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

($ in millions)

(unaudited)

THREE MONTHS ENDED: December 31,2013 December 31,2012 Beginning cash $ 987 $ 142 Cash provided by operating activities 1,028 860 Cash flows from investing activities:

Drilling and completion costs on proved and unproved properties(a)

(1,117 ) (1,377 ) Acquisition of proved and unproved properties(b) (211 ) (295 ) Sale of proved and unproved properties 668 3,386 Geological and geophysical costs (17 ) (28 ) Additions to other property and equipment(c) (333 ) (735 ) Proceeds from sales of other assets 126 2,273 Investments, net (36 ) (134 ) Other — 80 Total cash provided by (used in) investing activities (920 ) 3,170 Cash used in financing activities (258 ) (3,899 )

Change in cash and cash equivalents classified as current assets held for sale

— 14 Change in cash and cash equivalents (150 ) 145 Ending cash $ 837 $ 287

(a) Includes capitalized interest of $15 million for the three months ended December 31, 2013.

(b) Includes capitalized interest of $159 million and $153 million for the three months ended December 31, 2013 and 2012, respectively.

(c) Includes approximately $235 million for the purchase of rigs and compressors out of sale leaseback transactions in the 2013 fourth quarter.

TWELVE MONTHS ENDED: December 31,2013 December 31,2012 Beginning cash $ 287 $ 351 Cash provided by operating activities 4,614 2,837 Cash flows from investing activities:

Drilling and completion costs on proved and unproved properties(d)

(5,552 ) (8,707 ) Acquisition of proved and unproved properties(e) (974 ) (2,385 ) Sale of proved and unproved properties 3,409 5,612 Geological and geophysical costs (52 ) (193 ) Additions to other property and equipment(f) (972 ) (2,651 ) Proceeds from sales of other assets 922 2,492 Investments, net 71 1,605 Other 181 (757 ) Total cash used in investing activities (2,967 ) (4,984 ) Cash provided by (used in) financing activities (1,097 ) 2,083 Change in cash and cash equivalents 550 (64 ) Ending cash $ 837 $ 287

(d) Includes capitalized interest of $62 million and $30 million for the 12 months ended December 31, 2013 and 2012, respectively.

(e) Includes capitalized interest of $730 million and $776 million for the 12 months ended December 31, 2013 and 2012, respectively.

(f) Includes approximately $240 million for the purchase of rigs and compressors out of sale leaseback transactions in 2013.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per share data)

(unaudited)

THREE MONTHS ENDED: December 31, 2013 September 30, 2013 December 31, 2012

Net income (loss) available to common stockholders

$ (159 ) $ 156 $ 250 Adjustments, net of tax: Unrealized (gains) losses on derivatives 13 118 (78 ) Restructuring and other termination costs 28 39 2 Impairments of fixed assets and other 126 55 36 Net gains on sales of fixed assets (7 ) (82 ) (166 ) Losses on investment 84 — — Gains on sales of investments — (2 ) (19 ) Losses on purchases of debt and extinguishment of other financing 76 — 122 Other — (2 ) (1 )

Adjusted net income available to common stockholders(a)

161 282 146 Preferred stock dividends 43 43 43 Earnings allocated to participating securities — 3 7 Total adjusted net income attributable to Chesapeake $ 204 $ 328 $ 196

Weighted average fully diluted shares outstanding (in millions)(b)

767 765 754 Adjusted earnings per share assuming dilution(a) $ 0.27 $ 0.43 $ 0.26

(a) 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.

(b) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS

($ in millions, except per share data)

(unaudited)

TWELVE MONTHS ENDED: December 31, 2013 December 31, 2012 Net income (loss) available to common stockholders $ 474 $ (940 ) Adjustments, net of tax: Unrealized gains on derivatives (100 ) (347 ) Restructuring and other termination costs 154 4 Impairment of natural gas and oil properties — 2,022 Impairments of fixed assets and other 341 208 Net gains on sales of fixed assets (187 ) (163 ) (Gains) losses on investments 95 (622 ) Losses on purchases of debt and extinguishment of other financing 120 122 Other (1 ) 1 Adjusted net income available to common stockholders(a) 896 285 Preferred stock dividends 171 171 Premium on purchase of preferred shares of a subsidiary 69 — Earnings allocated to participating securities 10 — Total adjusted net income attributable to Chesapeake $ 1,146 $ 456 Weighted average fully diluted shares outstanding (in millions)(b) 765 755 Adjusted earnings per share assuming dilution(a) $ 1.50 $ 0.61

(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.

(b) Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED: December 31, 2013 September 30, 2013 December 31, 2012 CASH PROVIDED BY OPERATING ACTIVITIES $ 1,028 $ 1,361 $ 860 Changes in assets and liabilities (33 ) 52 278 OPERATING CASH FLOW(a) $ 995 $ 1,413 $ 1,138 THREE MONTHS ENDED: December 31, 2013 September 30, 2013 December 31, 2012 NET INCOME (LOSS) $ (74 ) $ 240 $ 344 Interest expense 63 40 14 Income tax expense (benefit) (45 ) 147 219 Depreciation and amortization of other assets 80 79 71 Natural gas, oil and NGL depreciation, depletion and amortization 644 652 651 EBITDA(b) $ 668 $ 1,158 $ 1,299 THREE MONTHS ENDED: December 31, 2013 September 30, 2013 December 31, 2012 CASH PROVIDED BY OPERATING ACTIVITIES $ 1,028 $ 1,361 $ 860 Changes in assets and liabilities (33 ) 52 278 Interest expense, net of unrealized gains (losses) on derivatives 53 40 17 Natural gas, oil and NGL derivative gains (losses), net (13 ) (253 ) 96

Cash payments on natural gas, oil and NGL derivative settlements, net

30 19 17 Share-based compensation (20 ) (22 ) (27 ) Restructuring and other termination costs (11 ) (60 ) (2 ) Impairments of fixed assets and other (166 ) (59 ) (59 ) Net gains on sales of fixed assets 12 132 272 Losses on investments (189 ) (23 ) (17 ) Gains on sales of investments — 3 31 Losses on purchases of debt and extinguishment of other financing (3 ) — (200 ) Other items (20 ) (32 ) 33 EBITDA(b) $ 668 $ 1,158 $ 1,299

(a) 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.

(b) 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 requirements. 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.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

($ in millions)

(unaudited)

TWELVE MONTHS ENDED: December 31, 2013 December 31, 2012 CASH PROVIDED BY OPERATING ACTIVITIES $ 4,614 $ 2,837 Changes in assets and liabilities 342 1,083 OPERATING CASH FLOW(a) $ 4,956 $ 3,920 TWELVE MONTHS ENDED: December 31, 2013 December 31, 2012 NET INCOME (LOSS) $ 894 $ (594 ) Interest expense, net of unrealized gains 227 77 Income tax expense (benefit) 548 (380 ) Depreciation and amortization of other assets 314 304 Natural gas, oil and NGL depreciation, depletion and amortization 2,589 2,507 EBITDA(b) $ 4,572 $ 1,914 TWELVE MONTHS ENDED: December 31, 2013 December 31, 2012 CASH PROVIDED BY OPERATING ACTIVITIES $ 4,614 $ 2,837 Changes in assets and liabilities 342 1,083 Interest expense, net of unrealized gains on derivatives 159 83 Natural gas, oil and NGL derivative gains, net 129 919 Cash (receipts) payments on natural gas, oil and NGL derivative settlements, net 91 (234 ) Share-based compensation (98 ) (120 ) Restructuring and other termination costs (175 ) (2 ) Impairment of natural gas and oil properties — (3,315 ) Impairments of fixed assets and other (483 ) (316 ) Net gains on sales of fixed assets 302 267 Losses on investments (229 ) (164 ) Gains (losses) on sales of investments (7 ) 1,092 Losses on purchases of debt and extinguishment of other financing (40 ) (200 ) Other items (33 ) (16 ) EBITDA(b) $ 4,572 $ 1,914

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

THREE MONTHS ENDED: December 31, 2013 September 30, 2013 December 31, 2012 EBITDA $ 668 $ 1,158 $ 1,299 Adjustments: Unrealized (gains) losses on natural gas, oil and NGL derivatives 10 191 (125 ) Restructuring and other termination costs 45 63 3 Impairments of fixed assets and other 203 89 59 Net gains on sales of fixed assets (12 ) (132 ) (272 ) Losses on investment 136 — — Gains on sales of investments — (3 ) (31 ) Losses on purchases of debt and extinguishment of other financing 123 — 200

Net income attributable to noncontrolling interests

(42 ) (38 ) (44 ) Other 1 (3 ) (1 ) Adjusted EBITDA(a) $ 1,132 $ 1,325 $ 1,088 TWELVE MONTHS ENDED: December 31, 2013 December 31, 2012 EBITDA $ 4,572 $ 1,914 Adjustments: Unrealized (gains) losses on natural gas, oil and NGL derivatives (228 ) (561 ) Restructuring and other termination costs 248 7 Impairment of natural gas and oil properties — 3,315 Impairments of fixed assets and other 550 340 Net gains on sales of fixed assets (302 ) (267 ) Losses on investments 146 — (Gains) losses on sales of investments 7 (1,019 ) Losses on purchases of debt and extinguishment of other financing 193 200 Net income attributable to noncontrolling interests (170 ) (175 ) Adjusted EBITDA(a) $ 5,016 $ 3,754

(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 natural gas and oil producing companies.

(ii) Adjusted ebitda is more comparable to estimates provided by securities analysts.

SCHEDULE "A”MANAGEMENT’S OUTLOOK AS OF FEBRUARY 6, 2014

Chesapeake periodically provides management guidance on certain factors that affect the company’s future financial performance. Please note that the company has changed its oil and natural gas unit equivalent reporting convention to oil equivalent. Combined oil, natural gas and NGL volume amounts are shown below in boe rather than mcfe.

Chesapeake Energy Corporation Consolidated Projections

Year Ending

12/31/2014

Absolute Production Growth(a): Liquids 14 – 18% Oil 1 – 5% NGL(b) 40 – 45% Natural gas (2) – 0% Total Production 2 – 4% Daily Equivalent Rate - mboe 680 – 695 NYMEX Price(c) (for calculation of realized hedging effects only): Oil - $/bbl $90.40 Natural gas - $/mcf $4.16 Estimated Realized Hedging Effects(d) (based on assumed NYMEX prices above): Oil - $/bbl ($2.80) Natural gas - $/mcf ($0.07) Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: Oil - $/bbl $2.80 – 4.80 NGL - $/bbl $63.00 – 67.00 Natural gas - $/mcf $1.60 – 1.70 Operating Costs per Boe of Projected Production: Production expense $4.25 – 4.75 Production taxes $0.85 – 0.95 General and administrative(e) $1.20 – 1.40 Share-based compensation (noncash) $0.15 – 0.20 DD&A of natural gas and liquids assets $10.50 – 11.50 Depreciation of other assets $1.20 – 1.30 Interest expense(f) $0.95 – 1.05 Other ($ millions): Marketing, gathering and compression net margin(g) $50 – 75 Oilfield services net margin(g) $175 – 225 Net income attributable to noncontrolling interests and other(h) ($160 – 190) Book Tax Rate 38% Weighted Average Shares Outstanding (in millions): Basic 657 – 661 Diluted 767 – 771 Operating Cash Flow before Changes in Assets and Liabilities ($ in millions) (i)(j) $5,100 – 5,300 Total Capital Expenditures ($ in millions) $5,200 – 5,600

a) Growth ranges based on the midpoint of company Outlook issued on 11/6/2013.

b) Assumes ethane recovery in the Utica and southern Marcellus to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Rockies, minimal ethane recovery in the Eagle Ford and partial ethane recovery in the Mid-Continent.

c) NYMEX natural gas and oil prices have been updated for actual contract prices through January and February, respectively.

d) Includes expected settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.

e) Excludes expenses associated with share-based compensation and restructuring and other termination costs.

f) Does not include gains (losses) on interest rate derivatives for settlement periods beyond 2014.

g) Includes revenue and operating costs and excludes depreciation and amortization of other assets.

h) Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust, CHK Utica, LLC and CHK Cleveland Tonkawa, LLC.

i) A non-GAAP financial measure. We are unable to provide reconciliation to projected cash provided by operating activities, the most comparable GAAP measure, because of uncertainties associated with projecting future changes in assets and liabilities.

j) Assumes NYMEX prices on open contracts of $90.00 per bbl and $4.00 per mcf and production growth rate ranges as shown above.

Natural Gas, Oil and NGL Hedging Activities

Chesapeake enters into natural gas, oil and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end and year-end derivative positions and accounting for natural gas, oil and NGL derivatives.

As of January 31, 2014, the company had downside protection on approximately 68% of its projected 2014 natural gas production at an average price of $4.15 per mcf. Approximately 58% of the company's projected 2014 oil production had downside protection at an average price of $93.92 per bbl.

The company’s natural gas hedging positions as of January 31, 2014 were as follows:

Open Natural Gas Swaps; Gains (Losses) from Closed

Natural Gas Trades and Call Option Premiums

Open

Swaps

(bcf)

Avg. NYMEX

Price of

Open Swaps

Total Gains(Losses)fromClosed Trades andPremiums for CallOptions ($in millions)

Q1 2014 169 $ 4.36 $ (26 ) Q2 2014 106 4.08 (12 ) Q3 2014 111 4.08 (15 ) Q4 2014 111 4.08 (21 ) Total 2014 497 $ 4.18 $ (74 ) Total 2015 44 $ 4.53 $ (131 ) Total 2016 – 2022 0 - $ (187 )

Natural Gas Three-Way Collars

Open

Collars

(bcf)

Avg. NYMEX

Sold Put Price

Avg. NYMEX

Bought Put Price

Avg. NYMEX

Ceiling Price

Q1 2014 48 $ 3.57 $ 4.08 $ 4.39 Q2 2014 51 3.57 4.09 4.38 Q3 2014 57 3.55 4.09 4.38 Q4 2014 71 3.49 4.11 4.37 Total 2014 227 $ 3.54 $ 4.09 $ 4.38 Total 2015 174 $ 3.38 $ 4.21 $ 4.41

Natural Gas Swaptions

Swaptions

(bcf)

Avg. NYMEX

Strike Price

Q1 2014 0 $ — Q2 2014 12 4.80 Q3 2014 0 — Q4 2014 0 — Total 2014 12 $ 4.80

Natural Gas Written Call Options

Call Options

(bcf)

Avg. NYMEX

Strike Price

Total 2016 – 2020 193 $ 9.92

Natural Gas Basis Protection Swaps

Volume

(bcf)

Avg. NYMEXplus/(minus)

Q1 2014 8 $ 1.68 Q2 2014 20 $ (0.49 ) Q3 2014 20 $ (0.50 ) Q4 2014 12 $ (0.44 ) Total 2014 60 $ (0.19 ) Total 2015 31 $ (0.34 ) Total 2016 - 2022 8 $ (1.02 )

The company’s crude oil hedging positions as of January 31, 2014 were as follows:

Open Crude Oil Swaps; Gains (Losses) from Closed

Crude Oil Trades and Call Option Premiums

Open

Swaps

(mbbls)

Avg. NYMEX

Price of

Open Swaps

Total Gains(Losses) fromClosed Trades andPremiums for CallOptions ($ inmillions)

Q1 2014 7,217 $ 94.37 $ (44 ) Q2 2014 7,114 93.97 (46 ) Q3 2014 5,137 93.57 (48 ) Q4 2014 5,112 93.58 (49 ) Total 2014 24,580 93.92 $ (187 ) Total 2015 693 89.48 $ 252 Total 2016 – 2022 0 — $ 117

Crude Oil Written Call Options

Call Options

(mbbls)

Avg. NYMEX

Strike Price

Q1 2014 612 $ 83.53 Q2 2014 619 83.53 Q3 2014 626 83.53 Q4 2014 626 83.53 Total 2014 2,483 $ 83.53 Total 2015 15,823 $ 93.12 Total 2016 – 2017 24,220 $ 100.07

Crude Oil Basis Protection Swaps

Volume (mbbls) Avg. NYMEX plus Q4 2014 90 $ 6.00 Q4 2014 91 6.00 Q4 2014 92 6.00 Q4 2014 92 6.00 Total 2014 365 $ 6.00

Chesapeake Energy CorporationInvestor Contact:Gary T. Clark, CFA, 405-935-8870ir@chk.comorMedia Contact:Gordon Pennoyer, 405-935-8878media@chk.com

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