CHK-2015.03.31_10Q
Table of Contents









UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
[X]    Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended March 31, 2015
[  ]    Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from                      to                     
Commission File No. 1-13726

Chesapeake Energy Corporation
(Exact name of registrant as specified in its charter)
Oklahoma
 
73-1395733
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. 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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X]     NO [ ] 
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X]     NO [ ] 
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer [X] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ]      NO [X]
As of April 30, 2015, there were 665,135,444 shares of our $0.01 par value common stock outstanding.





CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2015


 
Page
Condensed Consolidated Financial Statements (Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Table of Contents
PART I. FINANCIAL INFORMATION


Item 1.
Condensed Consolidated Financial Statements (Unaudited)
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

 
 
March 31,
2015
 
December 31,
2014
 
 
($ in millions)
CURRENT ASSETS:
 
 
 
 
Cash and cash equivalents ($1 and $1 attributable to our VIE)
 
$
2,907

 
$
4,108

Restricted cash
 
38

 
38

Accounts receivable, net
 
1,643

 
2,236

Short-term derivative assets ($12 and $16 attributable to our VIE)
 
612

 
879

Other current assets
 
198

 
207

Total Current Assets
 
5,398

 
7,468

PROPERTY AND EQUIPMENT:
 
 
 
 
Oil and natural gas properties, at cost based on full cost accounting:
 
 
 
 
Proved oil and natural gas properties
($488 and $488 attributable to our VIE)
 
60,769

 
58,594

Unproved properties
 
9,129

 
9,788

Other property and equipment
 
3,094

 
3,083

Total Property and Equipment, at Cost
 
72,992

 
71,465

Less: accumulated depreciation, depletion and amortization
(($318) and ($251) attributable to our VIE)
 
(44,700
)
 
(39,043
)
Property and equipment held for sale, net
 
93

 
93

Total Property and Equipment, Net
 
28,385

 
32,515

LONG-TERM ASSETS:
 
 
 
 
Investments
 
268

 
265

Long-term derivative assets
 
—

 
6

Other long-term assets
 
322

 
497

TOTAL ASSETS
 
$
34,373

 
$
40,751

 
 
 
 
 

The accompanying notes are an integral part of these condensed consolidated financial statements.
1
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – (Continued)
(Unaudited)

 
 
March 31,
2015
 
December 31,
2014
 
 
($ in millions)
CURRENT LIABILITIES:
 
 
 
 
Accounts payable
 
$
1,630

 
$
2,049

Current maturities of long-term debt, net
 
885

 
381

Accrued interest
 
137

 
150

Deferred income tax liabilities
 
214

 
207

Short-term derivative liabilities
 
26

 
15

Other current liabilities ($12 and $15 attributable to our VIE)
 
2,474

 
3,061

Total Current Liabilities
 
5,366

 
5,863

LONG-TERM LIABILITIES:
 
 
 
 
Long-term debt, net
 
10,623

 
11,154

Deferred income tax liabilities
 
2,817

 
4,185

Long-term derivative liabilities
 
191

 
218

Asset retirement obligations, net of current portion
 
452

 
447

Other long-term liabilities
 
551

 
679

Total Long-Term Liabilities
 
14,634

 
16,683

CONTINGENCIES AND COMMITMENTS (Note 4)
 
 
 
 
EQUITY:
 
 
 
 
Chesapeake Stockholders’ Equity:
 
 
 
 
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
7,251,515 shares outstanding
 
3,062

 
3,062

Common stock, $0.01 par value, 1,000,000,000 shares authorized:
665,109,487 and 664,944,232 shares issued
 
7

 
7

Paid-in capital
 
12,436

 
12,531

Retained earnings (deficit)
 
(2,256
)
 
1,483

Accumulated other comprehensive loss
 
(134
)
 
(143
)
Less: treasury stock, at cost; 1,585,667 and 1,614,312 common shares
 
(37
)
 
(37
)
Total Chesapeake Stockholders’ Equity
 
13,078

 
16,903

Noncontrolling interests
 
1,295

 
1,302

Total Equity
 
14,373

 
18,205

TOTAL LIABILITIES AND EQUITY
 
$
34,373

 
$
40,751


The accompanying notes are an integral part of these condensed consolidated financial statements.
2
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


 
 
Three Months Ended
March 31,
 
 
2015
 
2014
  
 
($ in millions except per share data)
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

CASH DIVIDEND DECLARED PER COMMON SHARE
 
$
0.0875

 
$
0.0875

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

 
658

Diluted
 
661

 
765


The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)


 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
NET INCOME (LOSS)
 
$
(3,720
)
 
$
466

OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
 
 
 
 
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($1) and $1
 
(1
)
 
3

Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $7 and $7
 
10

 
11

Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0 and ($3)
 
—

 
(5
)
Other Comprehensive Income (Loss)
 
9

 
9

COMPREHENSIVE INCOME (LOSS)
 
(3,711
)
 
475

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(19
)
 
(41
)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE
 
$
(3,730
)
 
$
434




The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
NET INCOME (LOSS)
 
$
(3,720
)
 
$
466

ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
 
 
 
 
Depreciation, depletion and amortization
 
719

 
706

Deferred income tax expense (benefit)
 
(1,372
)
 
277

Derivative (gains) losses, net
 
(172
)
 
363

Cash receipts (payments) on derivative settlements, net
 
408

 
(157
)
Stock-based compensation
 
23

 
20

Impairment of oil and natural gas properties
 
4,976

 
—

Net (gains) losses on sales of fixed assets
 
3

 
(23
)
Impairments of fixed assets and other
 
2

 
12

Losses on investments
 
7

 
21

Net gains on sales of investments
 
—

 
(67
)
Restructuring and other termination costs
 
(10
)
 
(9
)
Provision for legal contingencies
 
25

 
—

Other
 
21

 
5

Changes in assets and liabilities
 
(487
)
 
(323
)
Net Cash Provided By Operating Activities
 
423

 
1,291

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
Drilling and completion costs
 
(1,306
)
 
(897
)
Acquisitions of proved and unproved properties
 
(128
)
 
(187
)
Proceeds from divestitures of proved and unproved properties
 
21

 
49

Additions to other property and equipment
 
(58
)
 
(437
)
Proceeds from sales of other property and equipment
 
2

 
239

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

 
239

Other
 
—

 
(2
)
Net Cash Used In Investing Activities
 
(1,472
)
 
(999
)
 
 
 
 
 

The accompanying notes are an integral part of these condensed consolidated financial statements.
5
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – (Continued)
(Unaudited)



 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
Proceeds from credit facilities borrowings
 
—

 
421

Payments on credit facilities borrowings
 
—

 
(362
)
Cash paid for common stock dividends
 
(59
)
 
(58
)
Cash paid for preferred stock dividends
 
(43
)
 
(43
)
Cash paid on financing derivatives
 
—

 
(15
)
Distributions to noncontrolling interest owners
 
(29
)
 
(53
)
Other
 
(21
)
 
(15
)
Net Cash Used In Financing Activities
 
(152
)
 
(125
)
Net increase (decrease) in cash and cash equivalents
 
(1,201
)
 
167

Cash and cash equivalents, beginning of period
 
4,108

 
837

Cash and cash equivalents, end of period
 
$
2,907

 
$
1,004

 
 
 
 
 
 
 
 
 
 
Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
 
 
 
 
 
SUPPLEMENTAL CASH FLOW INFORMATION:
 
 
 
 
Interest paid, net of capitalized interest
 
$
43

 
$
75

Income taxes paid, net of refunds received
 
$
47

 
$
—

 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
 
Change in accrued drilling and completion costs
 
$
63

 
$
(168
)
Change in accrued acquisitions of proved and unproved properties
 
$
16

 
$
7

Change in accrued additions to other property and equipment
 
$
—

 
$
(2
)




The accompanying notes are an integral part of these condensed consolidated financial statements.
6
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)


 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
PREFERRED STOCK:
 
 
 
 
Balance, beginning and end of period
 
$
3,062

 
$
3,062

COMMON STOCK:
 
 
 
 
Balance, beginning and end of period
 
7

 
7

PAID-IN CAPITAL:
 
 
 
 
Balance, beginning of period
 
12,531

 
12,446

Stock-based compensation
 
12

 
5

Exercise of stock options
 
—

 
5

Dividends on common stock
 
(59
)
 
—

Dividends on preferred stock
 
(43
)
 
—

Increase (decrease) in tax benefit from stock-based compensation
 
(5
)
 
3

Balance, end of period
 
12,436

 
12,459

RETAINED EARNINGS (DEFICIT):
 
 
 
 
Balance, beginning of period
 
1,483

 
688

Net income (loss) attributable to Chesapeake
 
(3,739
)
 
425

Dividends on common stock
 
—

 
(58
)
Dividends on preferred stock
 
—

 
(43
)
Balance, end of period
 
(2,256
)
 
1,012

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
 
 
 
 
Balance, beginning of period
 
(143
)
 
(162
)
Hedging activity
 
9

 
14

Investment activity
 
—

 
(5
)
Balance, end of period
 
(134
)
 
(153
)
TREASURY STOCK – COMMON:
 
 
 
 
Balance, beginning of period
 
(37
)
 
(46
)
Purchase of 12,401 and 10,156 shares for company benefit plans
 
—

 
—

Release of 41,046 and 26,007 shares from company benefit plans
 
—

 
—

Balance, end of period
 
(37
)
 
(46
)
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY
 
13,078

 
16,341

NONCONTROLLING INTERESTS:
 
 
 
 
Balance, beginning of period
 
1,302

 
2,145

Net income attributable to noncontrolling interests
 
19

 
41

Distributions to noncontrolling interest owners
 
(26
)
 
(50
)
Balance, end of period
 
1,295

 
2,136

TOTAL EQUITY
 
$
14,373

 
$
18,477


The accompanying notes are an integral part of these condensed consolidated financial statements.
7
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)





1.
Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation ("Chesapeake" or the "Company") and its subsidiaries were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. These financial statements were prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP.
This Form 10-Q relates to the three months ended March 31, 2015 (the "Current Quarter") and the three months ended March 31, 2014 (the "Prior Quarter"). Chesapeake's annual report on Form 10-K for the year ended December 31, 2014 ("2014 Form 10-K") includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The results for the Current Quarter are not necessarily indicative of the results to be expected for the full year.

8
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




2.
Earnings Per Share
Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.
Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the Current Quarter and the Prior Quarter, our contingent convertible senior notes did not have a dilutive effect, and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes.
For the Current Quarter, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock, were excluded from the calculation of diluted EPS as the effect was antidilutive.
 
 
Net Income
Adjustments
 
Shares
 
 
($ in millions)
 
(in millions)
Three Months Ended March 31, 2015
 
 
 
 
Common stock equivalent of our preferred stock outstanding:
 
 
 
 
5.75% cumulative convertible preferred stock
 
$
21

 
59

5.75% cumulative convertible preferred stock (series A)
 
$
16

 
42

5.00% cumulative convertible preferred stock (series 2005B)
 
$
3

 
6

4.50% cumulative convertible preferred stock
 
$
3

 
6

Participating securities
 
$
—

 
2

For the Prior Quarter, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the Prior Quarter is as follows: 
 
 
Income (Numerator)
 
Weighted
Average
Shares
(Denominator)
 
Per
Share
Amount  
 
 
(in millions, except per share data)
Three Months Ended March 31, 2014
 
 
 
 
 
 
Basic EPS
 
$
374

 
658

 
$
0.57

Effect of Dilutive Securities:
 
 
 
 
 
 
Assumed conversion as of the beginning of the period
    of preferred shares outstanding during the period:
 
 
 
 
 
 
Common shares assumed issued for 5.75% cumulative convertible preferred stock
 
21

 
56

 
 
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)
 
16

 
39

 
 
Common shares assumed issued for 5.00% cumulative convertible preferred stock
(series 2005B)
 
3

 
5

 
 
Common shares assumed issued for 4.50% cumulative convertible preferred stock
 
3

 
6

 
 
Outstanding stock options
 
—

 
1

 
 
Diluted EPS
 
$
417

 
765

 
$
0.54



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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




3.
Debt
Our long-term debt consisted of the following as of March 31, 2015 and December 31, 2014:
 
 
March 31,
2015
 
December 31,
2014
 
 
($ in millions)
3.25% senior notes due 2016
 
$
500

 
$
500

6.25% euro-denominated senior notes due 2017(a)
 
369

 
416

6.5% senior notes due 2017
 
660

 
660

7.25% senior notes due 2018
 
669

 
669

Floating rate senior notes due 2019
 
1,500

 
1,500

6.625% senior notes due 2020
 
1,300

 
1,300

6.875% senior notes due 2020
 
500

 
500

6.125% senior notes due 2021
 
1,000

 
1,000

5.375% senior notes due 2021
 
700

 
700

4.875% senior notes due 2022
 
1,500

 
1,500

5.75% senior notes due 2023
 
1,100

 
1,100

2.75% contingent convertible senior notes due 2035(b)
 
396

 
396

2.5% contingent convertible senior notes due 2037(b)
 
1,168

 
1,168

2.25% contingent convertible senior notes due 2038(b)
 
347

 
347

Revolving credit facility
 
—

 
—

Discount on senior notes(c)
 
(210
)
 
(231
)
Interest rate derivatives(d)
 
9

 
10

Total debt, net
 
11,508

 
11,535

Less current maturities of long-term debt, net(e)
 
(885
)
 
(381
)
Total long-term debt, net
 
$
10,623

 
$
11,154

___________________________________________
(a)
The principal amount shown is based on the exchange rate of $1.0731 to €1.00 and $1.2098 to €1.00 as of March 31, 2015 and December 31, 2014, respectively. See Note 8 for information on our related foreign currency derivatives.
(b)
The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:
Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.
Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the first quarter of 2015, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the second quarter of 2015 under this provision.
The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the Current Quarter or the Prior Quarter. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.
The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:
    Contingent  
    Convertible  
    Senior  Notes    
 
Holders' Demand
Repurchase Dates
 
Common Stock
 Price Conversion 
Thresholds
 
 Contingent Interest
First Payable
(if applicable)
2.75% due 2035
 
November 15, 2015, 2020, 2025, 2030
 
$
45.14

 
May 14, 2016
2.5% due 2037
 
May 15, 2017, 2022, 2027, 2032
 
$
59.71

 
November 14, 2017
2.25% due 2038
 
December 15, 2018, 2023, 2028, 2033
 
$
100.35

 
June 14, 2019
Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash.
(c)
Discount as of March 31, 2015 and December 31, 2014 included $203 million and $224 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method.
(d)
See Note 8 for further discussion related to these instruments.
(e)
As of March 31, 2015, includes 3.25% Senior Notes due March 2016 and 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (b) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes. As of March 31, 2015 and December 31, 2014, there was $11 million and $15 million, respectively, of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035.
Chesapeake Senior Notes and Contingent Convertible Senior Notes
The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect 100% owned subsidiaries. See Note 17 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries.
We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.
We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.
In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 6.775% Senior Notes due 2019 (the 2019 Notes). The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and

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(Unaudited)




effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee moved the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest from the redemption date. On March 20, 2015, the Company filed its opposition to the Trustee’s motion and cross-moved for a judgment requiring the Company to pay restitution in an amount that would disgorge the benefit the Company achieved from refinancing the 2019 Notes in 2013 and that would return the parties to the economic positions they would have been in if the par redemption had never taken place. The District Court held argument on the motion and cross-motion on May 1, 2015. The District Court had not ruled as of May 5, 2015.
On December 30, 2014, six former holders of the 2019 Notes filed a putative class action against the Company on behalf of all former holders who purchased their 2019 Notes before the Company issued its notice of special early redemption at par in March 2013 and sold their 2019 Notes after the Company issued the early redemption notice but before the notes were redeemed at par in May 2013. The plaintiffs alleged that the Company breached the indenture in connection with its special early par redemption, causing the market value of the notes to decline and injuring the class members when they sold their 2019 Notes. The plaintiffs filed an amended class action complaint on March 2, 2015 and subsequently entered into a stipulation by which the action was dismissed with prejudice and without costs on March 16, 2015.
No scheduled principal payments are required on our senior notes until 2016 unless the holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the $396 million principal amount of notes.
Revolving Credit Facility
In December 2014, we entered into a five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. The aggregate commitments under the facility may be increased up to an additional $1.0 billion, and the December 2019 maturity date may be extended for two one-year periods at our request and with the consent of the participating lenders. As of March 31, 2015, we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are currently unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to Ba3 (Moody’s Investors Services, Inc.) or BB- (Standard & Poor’s Ratings Services) or lower.
Revolving loans under the credit facility bear interest at a fluctuating rate per annum equal to the highest of (i) the federal funds effective rate plus 0.5%, (ii) the administrative agent’s prime rate or (iii) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), and/or LIBOR rates (LIBOR loans), at our election, plus an applicable margin rate depending on our credit rating (currently 0.625% per annum for ABR loans and 1.625% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, the ability of the Company and its restricted subsidiaries to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. In addition, the credit facility requires us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65%; and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0; provided, however, that the leverage ratio will not apply during any period in which our credit rating, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services, meets certain investment grade thresholds, as defined in the credit agreement.
Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in

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(Unaudited)




an aggregate principal amount of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
Fair Value of Debt
We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which would include borrowings under our revolving credit facility (which was undrawn as of March 31, 2015 and December 31, 2014), is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. 
 
 
March 31, 2015
 
December 31, 2014
 
 
Carrying
Amount
 
Estimated
Fair Value
 
Carrying
Amount
 
Estimated
Fair Value
 
 
 
 
($ in millions)
 
 
Short-term debt (Level 1)
 
$
885

 
$
895

 
$
381

 
$
396

Long-term debt (Level 1)
 
$
10,614

 
$
10,762

 
$
11,144

 
$
11,656

Long-term debt (Level 2)
 
$
—

 
$
—

 
$
—

 
$
—

4.
Contingencies and Commitments
Contingencies
Litigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.
July 2008 Common Stock Offering Litigation. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. The plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiffs’ petition for rehearing on November 12, 2014. On April 10, 2015, the plaintiffs filed a writ of certiorari with the United States Supreme Court.
Shareholder Derivative Litigation. A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions allege breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for volumetric production payments. With the dismissal of the federal securities class action now affirmed (in July 2014), the parties have stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015.
Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and gas rights in various states. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state agency representatives and continues to respond to such subpoenas and demands.
On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleged that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. In resolution of both criminal complaints and with no admission of wrongdoing, on April 24, 2015, the Company entered a plea of no contest to one count of misdemeanor attempted antitrust violation and one count of misdemeanor false pretenses. The plea has been taken under advisement for a period of 11 months by the Court and will be dismissed if Chesapeake fulfills the terms of a settlement agreement with the Attorney General. As part of the settlement, Chesapeake will contribute no more than $25 million to a compensation fund established to compensate Michigan landowners for unfunded oil and gas leases in 2010.
Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we have accrued a loss contingency of $100 million for this matter. We estimate the range of potential loss between $100 million to $380 million, plus prejudgment interest. The high end of this range is based upon the indenture trustee’s request in February 2015 that the Court order us to pay noteholders the “make-whole” amount (as defined in the indenture) less the par amount already paid. Our $100 million accrual is based on an estimate of the remedy required to restore the redeemed noteholders and the Company to the economic positions they would have been in had the 2019 Notes not been redeemed.
Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and natural gas liquids (NGL). The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages for royalty underpayment in various states, including cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices.
Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and have negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. The court will hold a fairness hearing on the plaintiff’s motion for preliminary approval of the settlement filed on January 2, 2015. The Company accrued a loss contingency for the settlement amount in the 2014 fourth quarter. Although Chesapeake believes that its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. There can be no assurance the court will approve the settlement, however, and the final resolution of the Oklahoma royalty claims could differ from the amount accrued.
Chesapeake is also defending lawsuits alleging royalty underpayment in Texas. On April 8, 2015, Chesapeake obtained a transfer order from the Texas Multidistrict Litigation Panel to transfer a substantial portion of these lawsuits filed since June 2014 to the 348th District Court of Tarrant County for pre-trial purposes. These lawsuits, which are primarily related to the Barnett Shale, generally allege that Chesapeake underpaid royalties by making improper deductions and using incorrect production volumes. In addition to allegations of breach of contract, these lawsuits allege fraud, conspiracy and antitrust violations by Chesapeake. Chesapeake expects that additional lawsuits will be filed by new plaintiffs making similar allegations. The lawsuits seek direct damages in varying amounts, together with exemplary damages, attorneys’ fees, costs and interest. Chesapeake believes its royalty calculations and payment practices were appropriate and has not accrued a loss contingency with respect to the multidistrict litigation.
We believe losses are reasonably possible in certain of the other pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years. Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws.
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

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(Unaudited)




Commitments
Gathering, Processing and Transportation Agreements
We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying condensed consolidated balance sheets; however, they are reflected as adjustments to oil, natural gas and NGL sales prices used in our proved reserves estimates.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
 
 
March 31,
2015
 
 
($ in millions)
2015
 
$
1,359

2016
 
1,926

2017
 
1,932

2018
 
1,713

2019
 
1,428

2020 – 2099
 
6,173

Total
 
$
14,531

In addition to the gathering, processing and transportation agreements discussed above, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees will vary depending on the applicable agreement. Two of these agreements, one for production in the Anadarko Basin in northwestern Oklahoma and the Texas panhandle and the other for production in the Haynesville/Bossier Shales in northwestern Louisiana, contain cost-of-service based fees that are redetermined annually through 2019 and 2020, respectively. The annual upward or downward fee adjustment for these two contracts is capped at 15% of the then-current fees at the time of redetermination. To the extent the actual rate of return on capital expended by the counterparty over the term of the agreement differs from the applicable rate of return, a payment is due to (from) the midstream service company.
Drilling Contracts
We have contracts with various drilling contractors, including those entered into with Seventy Seven Energy Inc. (SSE) in connection with the spin-off of our oilfield services business in June 2014, to utilize drilling services with terms ranging from three months to three years at market-based pricing. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2015, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $398 million.
Pressure Pumping Contracts
In connection with the spin-off of our oilfield services business in June 2014, we entered into an agreement with a subsidiary of SSE for pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven, five and three pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. As of March 31, 2015, the aggregate undiscounted minimum future payments under this agreement were approximately $367 million.

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(Unaudited)




Drilling Commitments
We have committed to drill wells for the benefit of CHK Cleveland Tonkawa, L.L.C. and Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 6 for discussion of these commitments.
Natural Gas and Liquids Purchase Commitments
We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 9 for further discussion of our VPP transactions.
Net Acreage Maintenance Commitments
Under the terms of our joint venture agreements with Total and Sinopec (see Note 9), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates.
Other Commitments
In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc. (Sundrop), a privately held cellulosic biofuels company based in Longmont, Colorado. We also provided Sundrop with a one-time option to require us to purchase up to $25 million in additional preferred equity securities following the full payment of the initial investment, subject to the occurrence of specified milestones. As of March 31, 2015, we had funded our $155 million commitment in full and the milestones related to Sundrop’s preferred equity call option had not been met. See Note 10 for further discussion of this investment.
As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects.
Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Note 9 for further discussion of our VPP transactions.
While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.

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(Unaudited)




5.
Other Liabilities
Other current liabilities as of March 31, 2015 and December 31, 2014 are detailed below.
 
 
March 31,
2015
 
December 31,
2014
 
 
($ in millions)
Revenues and royalties due others
 
$
833

 
$
1,176

Accrued oil, natural gas and NGL drilling and production costs
 
443

 
385

Joint interest prepayments received
 
203

 
189

Accrued compensation and benefits
 
170

 
344

Other accrued taxes
 
66

 
55

Accrued dividends
 
102

 
101

Other
 
657

 
811

Total other current liabilities
 
$
2,474

 
$
3,061

Other long-term liabilities as of March 31, 2015 and December 31, 2014 are detailed below.
 
 
March 31,
2015
 
December 31,
2014
 
 
($ in millions)
CHK Utica ORRI conveyance obligation(a)
 
$
213

 
$
220

CHK C-T ORRI conveyance obligation(b)
 
131

 
135

Financing obligations
 
30

 
30

Unrecognized tax benefits
 
46

 
45

Other
 
131

 
249

Total other long-term liabilities
 
$
551

 
$
679

____________________________________________
(a)
$16 million and $14 million of the total $229 million and $234 million obligations are recorded in other current liabilities as of March 31, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation.
(b)
$25 million and $23 million of the total $156 million and $158 million obligations are recorded in other current liabilities as of March 31, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




6.
Equity
Common Stock
The following is a summary of the changes in our common shares issued for the Current Quarter and the Prior Quarter:
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
(in thousands)
Shares issued as of January 1
 
664,944

 
666,192

Restricted stock issuances (net of forfeitures and cancellations)(a)
 
151

 
(1,236
)
Stock option exercises
 
14

 
259

Shares issued as of March 31
 
665,109

 
665,215

___________________________________________
(a)
In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.
Preferred Stock
The following reflects the shares outstanding of our preferred stock for the Current Quarter and the Prior Quarter:
 
 
5.75%
 
5.75% (A)
 
4.50%
 
5.00%
(2005B)  
 
 
(in thousands)
Shares outstanding as of January 1, 2015 and 2014 and shares outstanding as of March 31, 2015 and 2014
 
1,497

 
1,100

 
2,559

 
2,096

Dividends
Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.

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(Unaudited)




Accumulated Other Comprehensive Income (Loss)
For the Current Quarter and the Prior Quarter, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
 
 
Cash Flow
Hedges
 

Investments
 
Net Change
 
 
($ in millions)
Balance, December 31, 2014
 
$
(143
)
 
$
—

 
$
(143
)
Other comprehensive income before reclassifications
 
(1
)
 
—

 
(1
)
Amounts reclassified from accumulated other comprehensive income
 
10

 
—

 
10

Net other comprehensive income
 
9

 
—

 
9

Balance, March 31, 2015
 
$
(134
)
 
$
—

 
$
(134
)
 
 
 
 
 
 
 
Balance, December 31, 2013
 
$
(167
)
 
$
5

 
$
(162
)
Other comprehensive income before reclassifications
 
3

 
—

 
3

Amounts reclassified from accumulated other comprehensive income
 
11

 
(5
)
 
6

Net other comprehensive income
 
14

 
(5
)
 
9

Balance, March 31, 2014
 
$
(153
)
 
$
—

 
$
(153
)
For the Current Quarter and the Prior Quarter, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed consolidated statements of operations are detailed below.
Details About Accumulated
Other Comprehensive
Income (Loss) Components
 
Affected Line Item
in the Statement
Where Net Income is Presented
 
Amounts Reclassified
 
 
 
 
($ in millions)
Three Months Ended March 31, 2015
 
 
 
 
Net losses on cash flow hedges:
 
 
 
 
Commodity contracts
 
Oil, natural gas and NGL revenues
 
$
10

Total reclassifications for the period, net of tax
 
$
10

 
 
 
 
 
Three Months Ended March 31, 2014
 
 
 
 
Net losses on cash flow hedges:
 
 
 
 
Commodity contracts
 
Oil, natural gas and NGL revenues
 
$
11

Investments:
 
 
 
 
Sales of investments
 
Net gain on sales of investments
 
(5
)
Total reclassifications for the period, net of tax
 
$
6


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Noncontrolling Interests
Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our revolving credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheets. Pursuant to the CHK C-T LLC Agreement, CHK C-T is required to retain an amount of cash equal to the next two quarters of preferred dividend payments. The amount reserved, approximately $38 million as of March 31, 2015 and December 31, 2014, was reflected as restricted cash on our condensed consolidated balance sheets.
Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement and the development agreement, as amended. The optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares; provided, however, that in certain circumstances, as set forth in the CHK C-T LLC Agreement and the development agreement, as amended, the optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro rata basis in accordance with the then-applicable redemption valuation formula. As of both March 31, 2015 and December 31, 2014, the redemption price and liquidation preference were approximately $1,170 and $1,185, respectively, per preferred share.
We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in 2012, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. In April 2014, the drilling commitment was amended to require us to drill and complete a minimum cumulative total of (i) 162.5 net wells by June 30, 2014 and (ii) 175 net wells by December 31, 2014. The drilling commitment was suspended in January 2015 at which time we had drilled 187 net wells. We are not required or allowed to drill any wells with respect to the CHK C-T properties unless we receive written notice from the owners of a majority of the preferred shares electing to lift the drilling prohibition. If we receive written notice at least 45 days prior to June 30, 2015, we will be required to drill and complete a minimum cumulative total of 225 net wells by June 30, 2016, and thereafter the minimum cumulative total will be increased by 25 net wells in each of the subsequent six-month periods ending December 31, 2017. If notice is not received by that time, future drilling commitment dates will be extended, as provided in the January 2015 amendment to the drilling commitment. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions will be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will be increased by an additional 3% per annum. Any increase in the internal rate of return would be effective only until the end of the

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




first succeeding six-month period in which we have met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity.
The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in the contributed wells and up to 1,000 future net wells on our contributed leasehold is subject to an increase to 5% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through the first quarter of 2025. However, in no event are we required to deliver to investors more than a total ORRI of 3.75% in existing wells and 1,000 future net wells. If at any time CHK C-T holds fewer net acres than would enable us to drill all then-remaining net wells on 160-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. CHK C-T retains the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 867 net wells. As of March 31, 2015, we had drilled 190 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We did not meet the 2014 ORRI conveyance commitment as of December 31, 2014.
As of March 31, 2015 and December 31, 2014, $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK C-T. For the Current Quarter and the Prior Quarter, income of $19 million was attributable to the noncontrolling interests of CHK C-T.
Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold.
In July 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired was reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold.
The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. As of March 31, 2015, we had drilled 429 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest will be reduced accordingly. We met our ORRI conveyance commitments as of December 31, 2013 and 2014.
In the Prior Quarter, approximately $19 million of income was attributable to the noncontrolling interests of CHK Utica.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.
In connection with the initial public offering of the Trust, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres (29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill, or cause to be drilled, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount recoverable by the Trust under the lien was limited to $263 million initially and is proportionately reduced as we fulfill our drilling obligation over time. As of March 31, 2015 and 2014, we had drilled or caused to be drilled approximately 105 and 89 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $29 million and $65 million, respectively.
The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units is reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent 11 quarters of distributions paid. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold is to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through March 31, 2015, no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After this time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.
For the Current Quarter and the Prior Quarter, the Trust declared and paid the following distributions:
Production Period

Distribution Date

Cash Distribution
per
Common Unit

Cash Distribution
per
Subordinated Unit
September 2014 – November 2014
 
March 2, 2015
 
$
0.4496

 
$
—

September 2013 – November 2013
 
March 3, 2014
 
$
0.6624

 
$
—

We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is consolidated in our condensed consolidated financial statements. As of March 31, 2015 and December 31, 2014, $281 million and $287 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to the Trust. In the Current Quarter and the Prior Quarter, income of approximately $1 million and $5 million, respectively, was attributable to the Trust’s noncontrolling interests in our condensed consolidated statements of operations. See Note 11 for further discussion of VIEs.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




7.
Share-Based Compensation
Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards.
Equity-Classified Awards
Restricted Stock. We grant restricted stock to employees and non-employee directors. Restricted stock vests over a minimum of three years and the holder receives dividends, if paid, on unvested shares. A summary of the changes in unvested restricted stock during the Current Quarter is presented below.
 
 
Shares of
Unvested
Restricted Stock
 
Weighted Average
Grant Date
Fair Value
 
 
(in thousands)
 
 
Unvested restricted stock as of January 1, 2015
 
10,091

 
$
21.20

Granted
 
6,672

 
$
14.11

Vested
 
(2,490
)
 
$
17.01

Forfeited
 
(142
)
 
$
16.30

Unvested restricted stock as of March 31, 2015
 
14,131

 
$
18.64

The aggregate intrinsic value of restricted stock that vested during the Current Quarter was approximately $42 million based on the stock price at the time of vesting.
As of March 31, 2015, there was approximately $206 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.40 years.
The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, we recognized reductions in tax benefits related to restricted stock of $5 million, and during the Prior Quarter, we recognized excess tax benefits related to restricted stock of $3 million. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
Stock Options. In the Current Quarter and the Prior Quarter, we granted members of senior management stock options that vest ratably over a three-year period. In January 2013, we also granted retention awards to certain officers of stock options that vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.
We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter:
Expected option life – years
 
4.5

Volatility
 
39.91
%
Risk-free interest rate
 
1.33
%
Dividend yield
 
1.91
%

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




The following table provides information related to stock option activity for the Current Quarter: 
 
 
Number of
Shares
Underlying  
Options
 
Weighted
Average
Exercise
Price
Per Share
 
Weighted  
Average
Contract
Life in
Years
 
Aggregate  
Intrinsic
Value(a)
 
 
(in thousands)
 
 
 
 
 
($ in millions)
Outstanding at January 1, 2015
 
4,599

 
$
19.55

 
7.03
 
$
5

Granted
 
1,208

 
$
18.37

 
 
 
 
Exercised
 
(14
)
 
$
18.13

 
 
 
$
—

Expired
 
—

 
$
—

 
 
 
 
Forfeited
 
—

 
$
—

 
 
 
 
Outstanding at March 31, 2015
 
5,793

 
$
19.31

 
6.83
 
$
—

 
 
 
 
 
 
 
 
 
Exercisable at March 31, 2015
 
1,930

 
$
19.29

 
5.84
 
$
—

___________________________________________
(a)
The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
As of March 31, 2015, there was $15 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.18 years.
The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, we recognized a reduction in tax benefits related to stock options of a nominal amount, and during the Prior Quarter we recognized excess tax benefits related to stock options of a nominal amount. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter:
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
General and administrative expenses
 
$
12

 
$
12

Oil and natural gas properties
 
7

 
7

Oil, natural gas and NGL production expenses
 
4

 
4

Marketing, gathering and compression expenses
 
1

 
2

Oilfield services expenses
 
—

 
2

Total
 
$
24

 
$
27


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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Liability-Classified Awards
Performance Share Units. In 2013, 2014 and 2015, we granted PSUs to senior management that vest ratably over their respective terms and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals such as production and proved reserve growth.
For PSUs granted in 2013, the TSR component can range from 0% to 125%, and each of the two operational components can range from 0% to 62.5%; however, the maximum total payout is capped at 200%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. For PSUs granted in 2015, the TSR component can range from 0% to 100%, and each of the two operational components can range from 0% to 50% resulting in a maximum total payout of 200%. The payout percentage for these PSUs is capped at 100% if the Company’s absolute TSR is less than zero. Compensation expense associated with the PSU grants is recognized over the service period based on the graded-vesting method. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. For the Current Quarter awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:
Volatility
 
40.12
%
Risk-free interest rate
 
0.95
%
Dividend yield for value of awards
 
1.91
%
The following table presents a summary of our 2013, 2014 and 2015 PSU awards:
 
 
Units
 
Fair Value
as of
Grant Date
 
Fair Value(a)
 
Liability for
Vested
Amount(a)
 
 
 
 
($ in millions)
2013 Awards:
 
 
 
 
 
 
 
 
Payable 2016
 
1,701,941

 
$
35

 
$
21

 
$
21

 
 
 
 
 
 
 
 
 
2014 Awards:
 
 
 
 
 
 
 
 
Payable 2017
 
609,637

 
$
16

 
$
3

 
$
3

 
 
 
 
 
 
 
 
 
2015 Awards:
 
 
 
 
 
 
 
 
Payable 2018
 
696,683

 
$
13

 
$
8

 
$
2

___________________________________________
(a)
As of March 31, 2015.
PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the Current Quarter and the Prior Quarter:
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
General and administrative expenses
 
$
(10
)
 
$
(1
)
Restructuring and other termination costs
 
(10
)
 
(9
)
Oil and natural gas properties
 
(1
)
 
1

Total
 
$
(21
)
 
$
(9
)

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




8.
Derivative and Hedging Activities
Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on its share of expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.
Oil and Natural Gas Derivatives
As of March 31, 2015 and December 31, 2014, our oil and natural gas derivative instruments consisted of the following types of instruments:
•
Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.
•
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
•
Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
•
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of March 31, 2015 and December 31, 2014 are provided below. 
 
 
March 31, 2015
 
December 31, 2014
 
 
Volume
 
Fair Value
 
Volume
 
Fair Value
 
 
 
 
($ in millions)  
 
 
 
($ in millions)  
Oil (mmbbl):
 
 
 
 
 
 
 
 
Fixed-price swaps
 
8.4

 
$
363

 
12.5

 
$
471

Three-way collars
 
3.3

 
32

 
4.4

 
40

Call options
 
34.3

 
(30
)
 
35.8

 
(89
)
Total oil
 
46.0

 
$
365

 
52.7

 
$
422

 
 
 
 
 
 
 
 
 
Natural gas (tbtu):
 
 
 
 
 
 
 
 
Fixed-price swaps
 
195

 
$
212

 
275

 
$
281

Three-way collars
 
106

 
77

 
207

 
165

Call options
 
193

 
(148
)
 
193

 
(170
)
Basis protection swaps
 
56

 
(6
)
 
60

 
23

Total natural gas
 
550

 
$
135

 
735

 
$
299

Total estimated fair value
 
 
 
$
500

 
 
 
$
721

 We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss).
Interest Rate Derivatives
As of March 31, 2015 and December 31, 2014, our interest rate derivative instruments consisted of swaps. We enter into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings.
The notional amount of our interest rate derivatives, associated with our long-term debt, as of March 31, 2015 and December 31, 2014, was $400 million and $850 million, respectively. The estimated fair value of our interest rate derivative liabilities, as of March 31, 2015 and December 31, 2014, was $3 million and $17 million, respectively. 
We have terminated certain fair value hedges related to senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years, we will recognize $9 million in net gains related to these transactions.
Foreign Currency Derivatives
We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations that may result from the €344 million principal amount of our euro-denominated senior notes. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Under the terms of the cross currency swaps we currently hold, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million. The swaps are designated as cash flow hedges and, because they are entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value do not impact earnings. The fair values of the cross currency swaps are recorded on the condensed consolidated balance sheet as liabilities of $103 million and $53 million as of March 31, 2015 and December 31, 2014, respectively. The euro-denominated debt in long-term debt has been adjusted to $369 million as of March 31, 2015, using an exchange rate of $1.0731 to €1.00.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Effect of Derivative Instruments – Condensed Consolidated Balance Sheets
The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of March 31, 2015 and December 31, 2014 on a gross basis and after same-counterparty netting: 
Balance Sheet Classification
 
Gross
Fair Value
 
Amounts Netted
in Condensed Consolidated
Balance Sheet
 
Net Fair Value Presented
in Condensed Consolidated
Balance Sheet
 
 
($ in millions)
As of March 31, 2015
 
 
 
 
 
 
Commodity Contracts:
 
 
 
 
 
 
Short-term derivative asset
 
$
688

 
$
(76
)
 
$
612

Short-term derivative liability
 
(99
)
 
76

 
(23
)
Long-term derivative liability
 
(88
)
 
—

 
(88
)
Total commodity contracts
 
501

 
—

 
501

 
 
 
 
 
 
 
Interest Rate Contracts:
 
 
 
 
 
 
Short-term derivative liability
 
(3
)
 
—

 
(3
)
Total interest rate contracts
 
(3
)
 
—

 
(3
)
 
 
 
 
 
 
 
Foreign Currency Contracts:(a)
 
 
 
 
 
 
Long-term derivative liability
 
(103
)
 
—

 
(103
)
Total foreign currency contracts
 
(103
)
 
—

 
(103
)
 
 
 
 
 
 
 
Total derivatives
 
$
395

 
$
—

 
$
395

 
 
 
 
 
 
 
As of December 31, 2014
 
 
 
 
 
 
Commodity Contracts:
 
 
 
 
 
 
Short-term derivative asset
 
$
974

 
$
(95
)
 
$
879

Long-term derivative asset
 
16

 
(10
)
 
6

Short-term derivative liability
 
(105
)
 
95

 
(10
)
Long-term derivative liability
 
(163
)
 
10

 
(153
)
Total commodity contracts
 
722

 
—

 
722

 
 
 
 
 
 
 
Interest Rate Contracts:
 
 
 
 
 
 
Short-term derivative liability
 
(5
)
 
—

 
(5
)
Long-term derivative liability
 
(12
)
 
—

 
(12
)
Total interest rate contracts
 
(17
)
 
—

 
(17
)
 
 
 
 
 
 
 
Foreign Currency Contracts:(a)
 
 
 
 
 
 
Long-term derivative liability
 
(53
)
 
—

 
(53
)
Total foreign currency contracts
 
(53
)
 
—

 
(53
)
 
 
 
 
 
 
 
Total derivatives
 
$
652

 
$
—

 
$
652

____________________________________________
(a)
Designated as cash flow hedging instruments.
As of March 31, 2015 and December 31, 2014, we did not have any cash collateral balances for these derivatives.

27
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Effect of Derivative Instruments – Condensed Consolidated Statements of Operations
The components of oil, natural gas and NGL sales for the Current Quarter and the Prior Quarter are presented below. 
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
Oil, natural gas and NGL sales
 
$
924

 
$
2,148

Gains (losses) on undesignated oil and natural gas derivatives
 
178

 
(365
)
Losses on terminated cash flow hedges
 
(17
)
 
(17
)
Total oil, natural gas and NGL sales
 
$
1,085

 
$
1,766

The components of interest expense for the Current Quarter and the Prior Quarter are presented below. 
 
 
Three Months Ended
March 31,
 
 
2015
 
2014
 
 
($ in millions)
Interest expense on senior notes
 
$
171

 
$
180

Interest expense on term loans
 
—

 
29

Amortization of loan discount, issuance costs and other
 
11

 
19

Interest expense on credit facilities
 
3

 
8

Gains on terminated fair value hedges
 
(1
)
 
(1
)
Gains on undesignated interest rate derivatives
 
(10
)
 
(18
)
Capitalized interest
 
(123
)
 
(178
)
Total interest expense
 
$
51

 
$
39

Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below. 
 
 
Three Months Ended March 31,
 
 
2015
 
2014
 
 
Before 
Tax  
 
After 
Tax  
 
Before 
Tax  
 
After 
Tax  
 
 
($ in millions)
Balance, beginning of period
 
$
(231
)
 
$
(143
)
 
$
(269
)
 
$
(167
)
Net change in fair value
 
(2
)
 
(1
)
 
4

 
3

Losses reclassified to income
 
17

 
10

 
18

 
11

Balance, end of period
 
$
(216
)
 
$
(134
)
 
$
(247
)
 
$
(153
)
Approximately $126 million of the $134 million of accumulated other comprehensive loss as of March 31, 2015 represented the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. Deferred gain or loss amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of March 31, 2015, we expect to transfer approximately $19 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.

28
Table of Contents
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)




Credit Risk Considerations
Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of March 31, 2015, our oil, natural gas and interest rate derivative instruments were spread among 16 counterparties.
Hedging Facility
As of March 31, 2015, our secured commodity hedging facility with 17 counterparties provided approximately 1.031 bboe of hedging capacity for oil, natural gas and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 billion. The facility is secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. treasury instruments to the extent that any mark-to-market amounts they owe Chesapeake exceed defined thresholds. As of March 31, 2015, we had hedged under the facility 128 mmboe of our future production with price derivatives and 9 mmboe with basis derivatives.
In April 2015, we also began entering into bilateral hedging agreements with the intention of replacing and terminating the respective counterparties’ posi