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Form 8-K CHESAPEAKE ENERGY CORP For: May 06

May 6, 2015 7:03 AM EDT


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): May 6, 2015
CHESAPEAKE ENERGY CORPORATION
(Exact name of Registrant as specified in its Charter)
Oklahoma
 
1-13726
 
73-1395733
(State or other jurisdiction of
incorporation)
 
(Commission File No.)
 
(IRS Employer Identification No.)
6100 North Western Avenue, Oklahoma City, Oklahoma
 
73118
(Address of principal executive offices)
 
(Zip Code)
 
(405) 848-8000
 
 
(Registrant’s telephone number, including area code)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
*
 
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
*
 
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
*
 
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
*
 
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))






Item 2.02 Results of Operations and Financial Condition.
On May 6, 2015, Chesapeake Energy Corporation issued a press release reporting financial and operating results for the first quarter of 2015. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.
The information in the press release is being furnished, not filed, pursuant to Item 2.02. Accordingly, the information in the press release will not be incorporated by reference into any registration statement filed by Chesapeake Energy Corporation under the Securities Act of 1933, as amended, except as set forth by specific reference in such filing.

Item 7.01 Regulation FD Disclosure

On May 6, 2015, Chesapeake Energy Corporation will make a presentation about its financial and operating results for the first quarter of 2015, as noted in the press release described in Item 2.02 above. Chesapeake has posted the presentation on its website at http://www.chk.com/investors/presentations.

The information in the press release is being furnished, not filed, pursuant to Item 7.01. Accordingly, the information in the press release will not be incorporated by reference into any registration statement filed by Chesapeake Energy Corporation under the Securities Act of 1933, as amended, except as set forth by specific reference in such filing.

Item 9.01 Financial Statements and Exhibits.

(d)    Exhibits.
Exhibit No.
 
Document Description
99.1
 
Chesapeake Energy Corporation press release dated May 6, 2015
 
 
 







SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 
CHESAPEAKE ENERGY CORPORATION
 
 
 
 
By:
 /s/ JAMES R. WEBB
 
James R. Webb
 
Executive Vice President - General Counsel and Corporate Secretary
Date:    May 6, 2015






EXHIBIT INDEX
Exhibit No.
 
Document Description
99.1
 
Chesapeake Energy Corporation press release dated May 6, 2015
 
 
 



 
 
EXHIBIT 99.1
News Release
 
 
 
 

FOR IMMEDIATE RELEASE
MAY 6, 2015

CHESAPEAKE ENERGY CORPORATION REPORTS 2015 FIRST QUARTER
FINANCIAL AND OPERATIONAL RESULTS
OKLAHOMA CITY, May 6, 2015 – Chesapeake Energy Corporation (NYSE: CHK) today reported financial and operational results for the 2015 first quarter. Highlights include:
Average production of approximately 686,000 boe per day, an increase of 14% year over year, adjusted for asset sales
Adjusted net income of $0.11 per fully diluted share and adjusted ebitda of $928 million
2015 total production guidance increased to 640 – 650 mboe per day
2015 capital guidance of approximately $3.5 – $4.0 billion reiterated
Additional 600 – 700 new Eagle Ford locations added following successful down spacing test results

Doug Lawler, Chesapeake’s Chief Executive Officer, commented “Chesapeake is meeting the challenge of low commodity prices head-on and delivered a very strong first quarter. Adjusted for asset sales, our production in the 2015 first quarter grew by 14% compared to the 2014 first quarter. Our cash costs remain at industry-low levels and we expect our assets to continue delivering greater efficiencies even as we reduce our activity levels throughout 2015. We remain on target to balance our capital spending and our cash flow by year-end, and the capital efficiencies that we are seeing in each of our operating areas are helping to strengthen that cash flow. During this challenging commodity price environment, our talented employees and high-quality assets are delivering competitive, differential performance.”
2015 First Quarter Financial Results
For the 2015 first quarter, Chesapeake reported a net loss available to common stockholders of $3.782 billion, or ($5.72) per fully diluted share, which compares to net income available to common stockholders of $374 million, or $0.54 per fully diluted share in the 2014 first quarter. Items typically excluded by securities analysts in their earnings estimates reduced 2015 first quarter net income by approximately $3.824 billion on an after-tax basis and are presented on Page 11 of this release. The primary source of this reduction was an impairment in the carrying value of Chesapeake's oil and natural gas properties largely resulting from significant decreases in the trailing 12-month average first-day-of-the-month oil and natural gas prices as of March 31, 2015, compared to December 31, 2014. Adjusting for this and other items, 2015 first quarter net income available to common stockholders was $42 million, or $0.11 per fully diluted share, which compares to adjusted net income available to common stockholders of $405 million, or $0.59 per fully diluted share, in the 2014 first quarter.
Adjusted ebitda was $928 million in the 2015 first quarter, compared to $1.515 billion in the 2014 first quarter. Operating cash flow was $910 million in the 2015 first quarter, compared to $1.614 billion in the 2014 first quarter. The year-over-year decreases in adjusted ebitda and operating cash flow were primarily the result of lower realized oil, natural gas and natural gas liquid (NGL) prices.
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

 
 
 
INVESTOR CONTACT:
MEDIA CONTACT:
CHESAPEAKE ENERGY CORPORATION
Brad Sylvester, CFA
(405) 935-8870
Gordon Pennoyer
(405) 935-8878
[email protected]
6100 North Western Avenue
P.O. Box 18496
Oklahoma City, OK 73154


calculated in accordance with generally accepted accounting principles are provided on pages 11 13 of this release.
2015 First Quarter Average Daily Production of 686,000 Boe Increased 14% Year Over Year and 2% Sequentially, Adjusted for Asset Sales
Chesapeake’s daily production for the 2015 first quarter averaged approximately 686,000 barrels of oil equivalent (boe), a year-over-year increase of 14%, adjusted for asset sales. Average daily production in the 2015 first quarter consisted of approximately 121,900 barrels (bbls) of oil, 2.9 billion cubic feet (bcf) of natural gas and 75,800 bbls of NGL, which represent year-over-year increases of 17%, 12% and 19%, respectively, adjusted for asset sales.
Capital Spending and Cost Overview
Chesapeake’s drilling and completion capital expenditures during the 2015 first quarter were approximately $1.3 billion, and capital expenditures for leasehold, geological and geophysical costs and other property, plant and equipment were approximately $63 million, for a total of approximately $1.4 billion. Total capital expenditures, including capitalized interest of $123 million, were approximately $1.5 billion in the 2015 first quarter, compared to approximately $1.8 billion in the 2014 fourth quarter and $1.4 billion in the 2014 first quarter and are reconciled below.
 
2015
2014
2014
Activity Comparison
Q1
Q4
Q1
Average operated rig count
54
67
60
Gross wells completed
261
341
225
Gross wells spud
244
308
268
Gross wells connected
262
311
249
 
 
 
 
Type of Cost ($ in millions)
 
 
 
Drilling and completion costs
$1,300
$1,370
$729
Leasehold, G&G and other PP&E
63

252

121

Subtotal capital spending
$1,363
$1,622
$850
Capitalized interest
123

134

178

Purchases of previously leased equipment

25

340

Total capital spending
$1,486
$1,781
$1,368
Chesapeake's focus on cost discipline continued to generate reductions in costs associated with production and general and administrative (G&A) expenses. Average production expenses during the 2015 first quarter were $4.84 per boe, a decrease of 5% from the 2014 fourth quarter and an increase of 2% year over year. G&A expenses (including stock-based compensation) during the 2015 first quarter were $0.91 per boe, a decrease of 34% from the 2014 fourth quarter and 30% year over year.
A summary of the company’s guidance for 2015 is provided in the Outlook dated May 6, 2015, attached to this release as Schedule "A” beginning on Page 14.

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Operational Results Southern Division
Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 113 thousand barrels of oil equivalent (mboe) per day (242 gross operated mboe per day) during the 2015 first quarter, an increase of 7% sequentially. The full-year 2014 average completed well cost was $5.9 million with an average completed lateral length of 5,850 feet and 18 frac stages, compared to the full-year 2013 average completed well cost of $6.9 million with an average completed lateral length of 5,850 feet and 18 frac stages. Well cost-reduction efforts continue and the company anticipates completed well costs of $5.5 million by year-end 2015. The company has successfully drilled five wells with laterals in excess of 10,000 feet. This technical achievement will heavily influence future development in the field as the company prioritizes front-loading its drill schedule with this well design. Chesapeake has successfully completed down spacing tests in various sections of its acreage, adding 600 700 incremental locations to its undrilled inventory. The company plans to test its first Upper Eagle Ford well in the 2015 fourth quarter. The average peak production rate of the 105 wells that commenced first production in the Eagle Ford during the 2015 first quarter was approximately 763 boe per day.
Haynesville Shale and Bossier Shale (Northwest Louisiana): Haynesville net production averaged approximately 616 million cubic feet of natural gas equivalent (mmcf) per day (996 gross operated mmcf per day) during the 2015 first quarter, an increase of 4% sequentially. The full-year 2014 average completed well cost was $8.4 million with an average completed lateral length of 4,900 feet and 14 frac stages, compared to an average completed well cost of $8.9 million in 2013 with an average completed lateral length of 4,400 feet and 18 frac stages. In April 2015, the company placed its initial two modern extended lateral (7,500 feet) Haynesville wells on line, the Nguyen 8-15-14 1H ALT and the Nguyen 5-15-14 2H ALT at peak 24-hour rates of 18.5 mmcf per day and 16.7 mmcf per day, respectively, with flowing surface pressures of approximately 600 PSI per foot greater than surrounding in-unit wells.  The average peak production rate of the 19 wells that commenced first production in the Haynesville during the 2015 first quarter was approximately 15.4 mmcf per day. Chesapeake also recently turned in line two successful tests in the Bossier Shale utilizing enhanced stimulation techniques. These wells are producing at a restricted rate of 12.0 mmcf per day paving the way for future Bossier development of 200 400 wells that can utilize both enhanced stimulation and extended laterals.
Mid-Continent North: Mississippian Lime (Northern Oklahoma): Mississippian Lime net production averaged approximately 32 mboe per day (75 gross operated mboe per day) during the 2015 first quarter, an increase of 11% sequentially. The full-year 2014 average completed well cost was $3.0 million with an average completed lateral length of 4,500 feet, compared to an average completed well cost of $3.5 million in 2013 with an average completed lateral length of 4,500 feet. The company anticipates completed well costs of $2.5 million in 2015, resulting in a 45% capital reduction in three years. The average peak production rate of the 48 wells that commenced first production in the Mississippian Lime during the 2015 first quarter was approximately 733 boe per day.
Operational Results Northern Division
Utica Shale (Eastern Ohio): Utica net production averaged approximately 110 mboe per day (190 gross operated mboe per day) during the 2015 first quarter, an increase of 10% sequentially. The full-year 2014 average completed well cost was $7.2 million with an average completed lateral length of 6,200 feet and 29 frac stages, compared to an average completed well cost of $6.7 million in 2013 with an average completed lateral length of 5,150 feet and 17 frac stages. Chesapeake anticipates average completed well costs of $8.2 million in 2015 while extending laterals to 7,900 feet with 41 frac stages. The average peak production rate of the 38 wells that commenced first production in the Utica during the 2015 first quarter was approximately 1,272 boe per day.
Marcellus Shale (Northern Pennsylvania): Marcellus net production averaged approximately 832 mmcf per day (1.932 gross operated bcf per day) during the 2015 first quarter, an increase of 2% sequentially. The 2014 full-year average completed well cost was $7.5 million with an average completed lateral length of 5,950 feet and 27 frac stages, compared to an average completed well cost of $7.9 million in 2013 with an average completed lateral length of 5,400 feet and 13 frac stages. With ample existing drilled inventory

3


and significant curtailed volumes, Chesapeake expects to maintain production at current levels throughout 2015 in the Marcellus. The average peak production rate of the 16 wells that commenced first production in the northern Marcellus during the 2015 first quarter was approximately 15.8 mmcf per day.
Powder River Basin (PRB): Niobrara and Upper Cretaceous (Wyoming): PRB net production averaged approximately 20 mboe per day (30 gross operated mboe per day) during the 2015 first quarter, an increase of 10% sequentially. The 2014 full-year average completed well cost (including multiple exploratory wells) was $10.6 million per well with an average completed lateral length of 5,425 feet and 20 frac stages, compared to an average completed well cost of $10.1 million per well in 2013 with an average completed lateral length of 5,050 feet and 15 frac stages. Chesapeake continues to improve operational efficiency and has successfully tested multiple Upper Cretaceous test wells. The average peak production rate of the 11 wells that commenced first production in the PRB during the 2015 first quarter was approximately 1,594 boe per day.

4


Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2015 first quarter, as compared to results in prior periods.
 
 
Three Months Ended
 
 
03/31/15
 
12/31/14
 
03/31/14
Oil equivalent production (in mmboe)
 
61.8

 
67.1

 
60.8

Oil production (in mmbbls)
 
11.0

 
11.2

 
9.9

Average realized oil price ($/bbl)(a)
 
62.57

 
76.40

 
85.08

Oil as % of total production
 
18

 
17

 
16

Natural gas production (in bcf)
 
263.8

 
281.6

 
260.0

Average realized natural gas price ($/mcf)(a)
 
2.37

 
1.72

 
3.27

Natural gas as % of total production
 
71

 
70

 
71

NGL production (in mmbbls)
 
6.8

 
9.0

 
7.6

Average realized NGL price ($/bbl)(a)
 
6.99

 
13.11

 
29.23

NGL as % of total production
 
11

 
13

 
13

Production expenses ($/boe) 
 
(4.84
)
 
(5.07
)
 
(4.73
)
Production taxes ($/boe)
 
(0.45
)
 
(0.70
)
 
(0.83
)
General and administrative costs ($/boe)(b)
 
(0.72
)
 
(1.23
)
 
(1.09
)
Stock-based compensation ($/boe)
 
(0.19
)
 
(0.15
)
 
(0.21
)
DD&A of natural gas and liquids properties ($/boe)
 
(11.08
)
 
(10.53
)
 
(10.33
)
DD&A of other assets ($/boe)
 
(0.57
)
 
(0.56
)
 
(1.29
)
Interest expense ($/boe)(a)
 
(0.98
)
 
(0.56
)
 
(0.90
)
Marketing, gathering and compression net margin ($ in millions)(c)
 
(25
)
 
(39
)
 
35

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

 

 
45

Operating cash flow ($ in millions)(d)
 
910

 
873

 
1,614

Operating cash flow ($/boe)
 
14.73

 
13.01

 
26.55

Adjusted ebitda ($ in millions)(e)
 
928

 
916

 
1,515

Adjusted ebitda ($/boe)
 
15.02

 
13.66

 
24.94

Net income (loss) available to common stockholders ($ in millions)
 
(3,782
)
 
586

 
374

Earnings (loss) per share – diluted ($)
 
(5.72
)
 
0.81

 
0.54

Adjusted net income available to common stockholders ($ in millions)(f)
 
42

 
34

 
405

Adjusted earnings per share – diluted ($)
 
0.11

 
0.11

 
0.59


(a)
Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.
(b)
Excludes expenses associated with stock-based compensation and restructuring and other termination costs.
(c)
Includes revenue and operating expenses and excludes depreciation and amortization of other assets.
(d)
Defined as cash flow provided by operating activities before changes in assets and liabilities.
(e)
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 13.
(f)
Defined as net income available to common stockholders, as adjusted to remove the effects of certain items detailed on Page 11.




5


2015 First Quarter Financial and Operational Results Conference Call Information
A conference call to discuss this release has been scheduled for Wednesday, May 6, 2015, at 9:00 am EDT. The telephone number to access the conference call is 913-312-1393 or toll-free 888-797-2983. The passcode for the call is 3887326. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the live conference call, a replay will be available for audio playback at 2:00 pm EDT on Wednesday, May 6, 2015, and will run through 2:00 pm EDT on Wednesday, May 20, 2015. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 3887326. The conference call will also be webcast live on Chesapeake’s website at www.chk.com and a replay will be available following the call. An investor presentation has been posted on the company's website at www.chk.com/investors/presentations. The latest investor presentation that will be referenced during the call provides additional financial and operational disclosure and will be available in the Investor Relations section of the company's website.
Chesapeake Energy Corporation (NYSE: CHK) is the second-largest producer of natural gas and the 11th 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 oil and natural gas assets onshore in the U.S. The company also owns substantial marketing and compression businesses. Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.
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. They include statements that give our current expectations or forecasts of future events, production, production growth and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, capital expenditures, expected efficiency gains, anticipated assets sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other plans and objectives for future operations, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.

Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings).  These risk factors include the volatility of oil, natural gas and NGL prices; write-downs of our oil and natural gas carrying values due to declines in prices; the availability of operating cash flow and other funds to finance reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; the limitations our level of indebtedness may have on our financial flexibility; charges incurred in response to market conditions and in connection with actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event.
In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law.


6




CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions, except per share data)
(unaudited)
 
 
 
 
 
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
REVENUES:
 
 
 
 
Oil, natural gas and NGL
 
$
1,085

 
$
1,766

Marketing, gathering and compression
 
1,675

 
3,015

Oilfield services
 

 
265

Total Revenues
 
2,760

 
5,046

OPERATING EXPENSES:
 
 
 
 
Oil, natural gas and NGL production
 
299

 
288

Production taxes
 
28

 
50

Marketing, gathering and compression
 
1,700

 
2,980

Oilfield services
 

 
220

General and administrative
 
56

 
79

Restructuring and other termination costs
 
(10
)
 
(7
)
Provision for legal contingencies
 
25

 

Oil, natural gas and NGL depreciation, depletion and amortization
 
684

 
628

Depreciation and amortization of other assets
 
35

 
78

Impairment of oil and natural gas properties
 
4,976

 

Impairments of fixed assets and other
 
4

 
20

Net (gains) losses on sales of fixed assets
 
3

 
(23
)
Total Operating Expenses
 
7,800

 
4,313

INCOME (LOSS) FROM OPERATIONS
 
(5,040
)
 
733

OTHER INCOME (EXPENSE):
 
 
 
 
Interest expense
 
(51
)
 
(39
)
Losses on investments
 
(7
)
 
(21
)
Net gain on sales of investments
 

 
67

Other income
 
6

 
6

Total Other Income (Expense)
 
(52
)
 
13

INCOME (LOSS) BEFORE INCOME TAXES
 
(5,092
)
 
746

INCOME TAX EXPENSE (BENEFIT):
 
 
 
 
Current income taxes
 

 
3

Deferred income taxes
 
(1,372
)
 
277

Total Income Tax Expense (Benefit)
 
(1,372
)
 
280

NET INCOME (LOSS)
 
(3,720
)
 
466

Net income attributable to noncontrolling interests
 
(19
)
 
(41
)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
 
(3,739
)
 
425

Preferred stock dividends
 
(43
)
 
(43
)
Earnings allocated to participating securities
 

 
(8
)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS
 
$
(3,782
)
 
$
374

EARNINGS (LOSS) PER COMMON SHARE:
 
 
 
 
Basic
 
$
(5.72
)
 
$
0.57

Diluted
 
$
(5.72
)
 
$
0.54

WEIGHTED AVERAGE COMMON AND COMMON
      EQUIVALENT SHARES OUTSTANDING (in millions):
 
 
 
 
Basic
 
661

 
658

Diluted
 
661

 
765


7




CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
($ in millions)
(unaudited)
 
 
 
 
 
 
 
March 31, 2015
 
December 31, 2014
 
 
 
 
 
Cash and cash equivalents
 
$
2,907

 
$
4,108

Other current assets
 
2,491

 
3,360

Total Current Assets
 
5,398

 
7,468

 
 
 
 
 
Property and equipment, (net)
 
28,385

 
32,515

Other assets
 
590

 
768

Total Assets
 
$
34,373

 
$
40,751

 
 
 
 
 
Current liabilities
 
$
5,366

 
$
5,863

Long-term debt, net of discounts
 
10,623

 
11,154

Other long-term liabilities
 
1,194

 
1,344

Deferred income tax liabilities
 
2,817

 
4,185

Total Liabilities
 
20,000

 
22,546

 
 
 
 
 
Preferred stock
 
3,062

 
3,062

Noncontrolling interests
 
1,295

 
1,302

Common stock and other stockholders’ equity
 
10,016

 
13,841

Total Equity
 
14,373

 
18,205

 
 
 
 
 
Total Liabilities and Equity
 
$
34,373

 
$
40,751

 
 
 
 
 
Common Shares Outstanding (in millions)
 
664

 
663






CHESAPEAKE ENERGY CORPORATION
CAPITALIZATION
($ in millions)
(unaudited)
 
 
 
March 31, 2015
 
December 31, 2014
 
 
 
 
 
Total debt, net of unrestricted cash
 
$
8,601

 
$
7,427

Preferred stock
 
3,062

 
3,062

Noncontrolling interests(a)
 
1,295

 
1,302

Common stock and other stockholders’ equity
 
10,016

 
13,841

Total
 
$
22,974

 
$
25,632

 
 
 
 
 
Total net debt to capitalization ratio
 
37
%
 
29
%
(a) 
Includes third-party ownership as follows:
 
CHK Cleveland Tonkawa, L.L.C.
 
$
1,015

 
$
1,015

 
Chesapeake Granite Wash Trust
 
280

 
287

 
Total
 
$
1,295

 
$
1,302



8


CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA  OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE
(unaudited)
 
 
 
 
 
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
Net Production:
 
 
 
 
Oil (mmbbl)
 
11.0

 
9.9

Natural gas (bcf)
 
263.8

 
260.0

NGL (mmbbl)
 
6.8

 
7.6

Oil equivalent (mmboe)
 
61.8

 
60.8

 
 
 
 
 
Oil, natural gas and NGL Sales ($ in millions):
 
 
 
 
Oil sales
 
$
451

 
$
922

Oil derivatives – realized gains (losses)(a)
 
235

 
(84
)
Oil derivatives – unrealized gains (losses)(a)
 
(110
)
 
10

Total Oil Sales
 
576

 
848

 
 
 
 
 
Natural gas sales
 
425

 
1,005

Natural gas derivatives – realized gains (losses)(a)
 
200

 
(154
)
Natural gas derivatives – unrealized gains (losses)(a)
 
(164
)
 
(154
)
Total Natural Gas Sales
 
461

 
697

 
 
 
 
 
NGL sales
 
48

 
221

Total NGL Sales
 
48

 
221

Total Oil, Natural Gas and NGL Sales
 
$
1,085

 
$
1,766

 
 
 
 
 
Average Sales Price – excluding gains (losses) on derivatives:
 
 
 
 
Oil ($ per bbl)
 
$
41.16

 
$
93.60

Natural gas ($ per mcf)
 
$
1.61

 
$
3.86

NGL ($ per bbl)
 
$
6.99

 
$
29.23

Oil equivalent ($ per boe)
 
$
14.96

 
$
35.35

 
 
 
 
 
Average Sales Price – including realized gains (losses) on derivatives:
 
 
 
 
Oil ($ per bbl)
 
$
62.57

 
$
85.08

Natural gas ($ per mcf)
 
$
2.37

 
$
3.27

NGL ($ per bbl)
 
$
6.99

 
$
29.23

Oil equivalent ($ per boe)
 
$
22.00

 
$
31.44

 
 
 
 
 
Interest Expense ($ in millions):
 
 
 
 
Interest(b)
 
$
62

 
$
58

Derivatives – realized (gains) losses(c)
 
(1
)
 
(3
)
Derivatives – unrealized (gains) losses(c)
 
(10
)
 
(16
)
Total Interest Expense
 
$
51

 
$
39


(a)
Realized gains and losses include the following items: (i) settlements of nondesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program.
(b)
Net of amounts capitalized.
(c)
Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early termination trades. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period.

9


CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
($ in millions)
(unaudited)
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
March 31,
2014
 
 
 
 
 
Beginning cash
 
$
4,108

 
$
837

 
 
 
 
 
Cash provided by operating activities
 
423

 
1,291

 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
Drilling and completion costs(a)
 
(1,306
)
 
(897
)
Acquisition of proved and unproved properties(b)
 
(128
)
 
(187
)
Proceeds from divestitures of proved and unproved properties
 
21

 
49

Additions to other property and equipment
 
(58
)
 
(97
)
Cash paid to purchase leased rigs and compressors
 

 
(340
)
Proceeds from sales of other property and equipment
 
2

 
239

Additions to investments
 
(3
)
 
(3
)
Proceeds from sales of investments
 

 
239

Other
 

 
(2
)
Total cash used in investing activities
 
(1,472
)
 
(999
)
 
 
 
 
 
Cash used in financing activities
 
(152
)
 
(125
)
Change in cash and cash equivalents
 
(1,201
)
 
167

Ending cash
 
$
2,907

 
$
1,004


(a)
Includes capitalized interest of $11 million and $16 million for the three months ended March 31, 2015 and 2014, respectively.
(b)
Includes capitalized interest of $109 million and $158 million for the three months ended March 31, 2015 and 2014, respectively.



10


CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions, except per share data)
(unaudited)
 
 
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
December 31,
2014
 
March 31,
2014
 
 
 
 
 
 
 
Net income (loss) available to common stockholders
 
$
(3,782
)
 
$
586

 
$
374

 
 
 
 
 
 
 
Adjustments, net of tax:
 
 
 
 
 
 
Unrealized (gains) losses on derivatives
 
192

 
(663
)
 
80

Restructuring and other termination costs
 
(7
)
 
(3
)
 
(4
)
Provision for legal contingencies
 
18

 
94

 

Impairment of oil and natural gas properties
 
3,635

 

 

Impairments of fixed assets and other
 
3

 
10

 
12

Net (gains) losses on sales of fixed assets
 
2

 
2

 
(14
)
Net gain on sales of investments
 

 

 
(42
)
Losses on purchases of debt and extinguishment of other financing
 

 
2

 

Tax rate adjustment
 
(17
)
 

 

Other
 
(2
)
 
6

 
(1
)
Adjusted net income available to common stockholders(a)
 
$
42

 
$
34

 
$
405

 
 
 
 
 
 
 
Preferred stock dividends
 
43

 
43

 
43

Earnings allocated to participating securities
 

 
10

 
8

 
 
 
 
 
 
 
Total adjusted net income attributable to Chesapeake
 
$
85

 
$
87

 
$
456

 
 
 
 
 
 
 
Weighted average fully diluted shares outstanding
(in millions)(b)
 
776

 
775

 
767

 
 
 
 
 
 
 
Adjusted earnings per share assuming dilution(a)
 
$
0.11

 
$
0.11

 
$
0.59


(a)
Adjusted net income and adjusted earnings per share assuming dilution are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to net income available to common stockholders or diluted earnings per share. 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 GAAP because:
(i)
Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.
(ii)
Adjusted net income 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.

11


CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
($ in millions)
(unaudited)
 
 
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
December 31,
2014
 
March 31,
2014
 
 
 
 
 
 
 
CASH PROVIDED BY OPERATING ACTIVITIES
 
$
423

 
$
829

 
$
1,291

Changes in assets and liabilities
 
487

 
44

 
323

OPERATING CASH FLOW(a)
 
$
910

 
$
873

 
$
1,614

 
 
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
 
 
 
 
 
 
NET INCOME (LOSS)
 
$
(3,720
)
 
$
668

 
$
466

Interest expense
 
51

 
7

 
39

Income tax expense (benefit)
 
(1,372
)
 
286

 
280

Depreciation and amortization of other assets
 
35

 
38

 
78

Oil, natural gas and NGL depreciation, depletion and amortization
 
684

 
706

 
628

EBITDA(b)
 
$
(4,322
)
 
$
1,705

 
$
1,491

 
 
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
 
 
 
 
 
 
CASH PROVIDED BY OPERATING ACTIVITIES
 
$
423

 
$
829

 
$
1,291

Changes in assets and liabilities
 
487

 
44

 
323

Interest expense, net of unrealized gains (losses) on derivatives
 
61

 
38

 
55

Oil, natural gas and NGL derivative gains (losses), net
 
161

 
1,049

 
(382
)
Cash (receipts) payments on oil, natural gas and NGL derivative settlements, net
 
(413
)
 
(88
)
 
168

Stock-based compensation
 
(23
)
 

 
(20
)
Restructuring and other termination costs
 
10

 
(3
)
 
9

Provision for legal contingencies
 
(25
)
 
(134
)
 

Impairment of oil and natural gas properties
 
(4,976
)
 

 

Impairments of fixed assets and other
 
(2
)
 
(14
)
 
(12
)
Net gains (losses) on sales of fixed assets
 
(3
)
 
(2
)
 
23

Losses on investments
 
(7
)
 
(7
)
 
(21
)
Net gain on sales of investments
 

 

 
67

Losses on purchases of debt and extinguishment of other financing
 

 
(2
)
 

Other items
 
(15
)
 
(5
)
 
(10
)
EBITDA(b)
 
$
(4,322
)
 
$
1,705

 
$
1,491


(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 an oil and natural gas company's ability to generate cash that 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 oil and natural gas 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 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.

12


CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in millions)
(unaudited)
 
 
 
 
 
 
 
THREE MONTHS ENDED:
 
March 31,
2015
 
December 31,
2014
 
March 31,
2014
 
 
 
 
 
 
 
EBITDA
 
$
(4,322
)
 
$
1,705

 
$
1,491

 
 
 
 
 
 
 
Adjustments:
 
 
 
 
 
 
Unrealized (gains) losses on oil, natural gas and NGL derivatives
 
274

 
(916
)
 
144

Restructuring and other termination costs
 
(10
)
 
(5
)
 
(7
)
Provision for legal contingencies
 
25

 
134

 

Impairment of oil and natural gas properties
 
4,976

 

 

Impairments of fixed assets and other
 
4

 
14

 
20

Net (gains) losses on sales of fixed assets
 
3

 
3

 
(23
)
Net gains on sales of investments
 

 

 
(67
)
Losses on purchases of debt and extinguishment of other financing
 

 
2

 

Net income attributable to noncontrolling interests
 
(19
)
 
(29
)
 
(41
)
Other
 
(3
)
 
8

 
(2
)
 
 
 
 
 
 
 
Adjusted EBITDA(a)
 
$
928

 
$
916

 
$
1,515


(a)
Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to ebitda because:
(i)
Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.
(ii)
Adjusted ebitda is more comparable to estimates provided by securities analysts.
(iii)
Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

Accordingly, adjusted EBITDA should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.

13


SCHEDULE "A”
CHESAPEAKE ENERGY CORPORATION
MANAGEMENT’S OUTLOOK AS OF MAY 6, 2015

Chesapeake periodically provides management guidance on certain factors that affect the company’s future financial performance.
 
Year Ending
12/31/2015
Adjusted Production Growth(a)
1% – 3%
Absolute Production
 
Liquids - mbbls
62 – 64
Oil - mbbls
38.5 – 39.5
NGL(b) - mbbls
23.5 – 24.5
Natural gas - bcf
1,025 – 1,040
Total absolute production - mmboe
233 – 237
Absolute daily rate - mboe
640 – 650
Estimated Realized Hedging Effects(c) (based on 4/30/15 strip prices):
 
Oil - $/bbl
$19.33
Natural gas - $/mcf
$0.32
Estimated Basis/Gathering/Marketing/Transportation Differentials to NYMEX Prices:
 
Oil - $/bbl
$7.00 – 9.00
Natural gas - $/mcf
$1.70 – 1.90
NGL - $/bbl
$49.00 – 51.00
Fourth quarter minimum volume commitment (MVC) estimate ($ in millions)
($180) – (200)
Operating Costs per Boe of Projected Production:
 
Production expense
$4.50 – 5.00
Production taxes
$0.45 – 0.55
General and administrative(d)
$1.45 – 1.55
Stock-based compensation (noncash)
$0.20 – 0.25
DD&A of natural gas and liquids assets
$9.50 – 10.50
Depreciation of other assets
$0.60 – 0.70
Interest expense(e)
$1.10 – 1.20
Other ($ millions):
 
Marketing, gathering and compression net margin(f)
($40 – 60)
Net income attributable to noncontrolling interests and other(g)
($30 – 50)
Book Tax Rate
25% – 30%
Capital Expenditures ($ in millions)(h)
$3,000 – 3,500
Capitalized Interest ($ in millions)
$475
Total Capital Expenditures ($ in millions)
$3,475 – 3,975

(a)
Based on 2014 production of 622 mboe/day adjusted for 2014 sales and the potential sale of Cleveland Tonkawa assets in 2015.
(b)
Assumes ethane recovery in the Utica to fulfill Chesapeake’s pipeline commitments, no ethane recovery in the Powder River Basin and partial ethane recovery in the Mid-Continent and Eagle Ford.
(c)
Includes expected settlements for commodity derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration.
(d)
Excludes expenses associated with stock-based compensation.
(e)
Excludes unrealized gains (losses) on interest rate derivatives.
(f)
Includes revenue and operating expenses and excludes depreciation and amortization of other assets.
(g)
Net income attributable to noncontrolling interests of Chesapeake Granite Wash Trust and CHK Cleveland Tonkawa L.L.C.
(h)
Includes capital expenditures for drilling and completion, leasehold, geological and geophysical costs and other property and plant and equipment.

14


Oil, Natural Gas and NGL Hedging Activities
Chesapeake enters into oil, natural gas 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 derivative positions and accounting for oil, natural gas and NGL derivatives.
As of April 30, 2015, the company had downside protection on approximately 43% of its remaining projected 2015 oil production at an average price of $93.48 per bbl of which 12% is hedged under three-way collar arrangements based on an average bought put NYMEX price of $90 per bbl and exposure below an average sold put NYMEX price of $80 per bbl. Approximately 40% of the company's remaining projected 2015 natural gas production has downside protection at an average price of $3.85 per one thousand cubic feet of natural gas (mcf), of which 14% is hedged under three-way collar arrangements based on an average bought put NYMEX price of $4.17 per mcf and exposure below an average sold put NYMEX price of $3.38 per mcf.
The company’s crude oil hedging positions as of April 30, 2015 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 from Closed Trades
and Premiums for
Call Options
($ in millions)
Q2 2015
3,041
 
$
94.49

 
$
61

Q3 2015
2,868
 
94.82

 
62

Q4 2015
2,714
 
95.15

 
63

Total Q2 - Q4 2015
8,623
 
$
94.81

 
$
186

Total 2016 – 2022
 
$

 
$
117

Crude Oil Three-Way Collars
 
 
 
 
 
 
Open Collars (mbbls)
Avg. NYMEX Sold Put Price
Avg. NYMEX Bought Put Price
Avg. NYMEX Sold Call Price
Q2 2015
1,092
$
80.00

$
90.00

$
98.94

Q3 2015
1,104
80.00

90.00

98.94

Q4 2015
1,104
80.00

90.00

98.94

Total Q2 - Q4 2015
3,300
$
80.00

$
90.00

$
98.94

Crude Oil Net Written Call Options
 
 
 
 
Call Options
(mbbls)
Avg. NYMEX
Strike Price
Q2 2015
3,349
$
91.89

Q3 2015
3,386
91.89

Q4 2015
3,386
91.89

Total Q2 - Q4 2015
10,121
$
91.89

Total 2016 – 2017
24,220
$
100.07



15


Crude Oil Basis Protection Swaps
 
 
 
 
Volume
(mbbls)
Avg. NYMEX plus
Q2 2015
1,740
$
5.04

Q3 2015
2,392
3.14

Q4 2015
2,361
3.14

Total Q2 - Q4 2015
6,493
$
3.65


The company’s natural gas hedging positions as of April 30, 2015 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)
from Closed Trades
and Premiums for
Call Options
($ in millions)
Q2 2015
70
 
$
3.64

 
$
(30
)
Q3 2015
78
 
3.54

 
(31
)
Q4 2015
52
 
3.94

 
(31
)
Total Q2 - Q4 2015
200
 
$
3.68

 
$
(92
)
Total 2016 – 2022
37
 
$
3.95

 
$
(187
)
Natural Gas Three-Way Collars
 
 
 
 
 
 
Open Collars
(bcf)
Avg. NYMEX
Sold
Put Price
Avg. NYMEX
Bought
Put Price
Avg. NYMEX
Sold Call Price
Q2 2015
35
$
3.38

$
4.17

$
4.37

Q3 2015
36
3.38

4.17

4.37

Q4 2015
36
3.38

4.17

4.37

Total Q2 - Q4 2015
107
$
3.38

$
4.17

$
4.37

Natural Gas Net Written Call Options
 
 
 
 
Call Options
(bcf)
Avg. NYMEX
Strike Price
Total 2016 – 2020
193
$
9.92

Natural Gas Basis Protection Swaps
 
 
 
 
Volume
(bcf)
Avg. NYMEX plus/(minus)
Q2 2015
22
$
(0.70
)
Q3 2015
37
(0.82
)
Q4 2015
10
(0.34
)
Total Q2 - Q4 2015
69
$
(0.71
)
Total 2016 - 2022
27
$
(0.56
)


16


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