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) |
Securities registered pursuant to Section 12(b) of the Act: | ||
Title of Each Class | Name of Each Exchange on Which Registered | |
Common Stock, par value $0.01 | New York Stock Exchange | |
3.25% Senior Notes due 2016 | New York Stock Exchange | |
6.25% Senior Notes due 2017 | New York Stock Exchange | |
6.5% Senior Notes due 2017 | New York Stock Exchange | |
7.25% Senior Notes due 2018 | New York Stock Exchange | |
Floating Rate Senior Notes due 2019 | New York Stock Exchange | |
6.625% Senior Notes due 2020 | New York Stock Exchange | |
6.875% Senior Notes due 2020 | New York Stock Exchange | |
6.125% Senior Notes due 2021 | New York Stock Exchange | |
5.375% Senior Notes due 2021 | New York Stock Exchange | |
4.875% Senior Notes due 2022 | New York Stock Exchange | |
5.75% Senior Notes due 2023 | New York Stock Exchange | |
2.75% Contingent Convertible Senior Notes due 2035 | New York Stock Exchange | |
2.5% Contingent Convertible Senior Notes due 2037 | New York Stock Exchange | |
2.25% Contingent Convertible Senior Notes due 2038 | New York Stock Exchange | |
4.5% Cumulative Convertible Preferred Stock | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: | ||
None |
PART I | Page | ||
Item 1. | Business | ||
Item 1A. | Risk Factors | ||
Item 1B. | Unresolved Staff Comments | ||
Item 2. | Properties | ||
Item 3. | Legal Proceedings | ||
Item 4. | Mine Safety Disclosures | ||
PART II | |||
Item 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | ||
Item 6. | Selected Financial Data | ||
Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations | ||
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | ||
Item 8. | Financial Statements and Supplementary Data | ||
Item 9. | Changes In and Disagreements With Accountants on Accounting and Financial Disclosure | ||
Item 9A. | Controls and Procedures | ||
Item 9B. | Other Information | ||
PART III | |||
Item 10. | Directors, Executive Officers and Corporate Governance | ||
Item 11. | Executive Compensation | ||
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | ||
Item 13. | Certain Relationships and Related Transactions and Director Independence | ||
Item 14. | Principal Accountant Fees and Services | ||
PART IV | |||
Item 15. | Exhibits and Financial Statement Schedules |
Item 1. | Business |
• | selling noncore assets in the southern Marcellus and Utica Shale plays in December 2014, which provided approximately 7% of our total 2014 production, for net proceeds of approximately $5.0 billion; |
• | completing additional dispositions of other noncore assets for aggregate net proceeds of approximately $1.8 billion; |
• | acquiring approximately 203,000 net acres and 186 gross wells in the southern Powder River Basin of Wyoming; |
• | completing the spin-off of our oilfield services business into Seventy Seven Energy Inc. (NYSE:SSE), a stand-alone publicly traded company; |
• | reducing financial complexity through a variety of transactions; |
• | entering into a new unsecured $4.0 billion credit facility with investment grade-like terms; |
• | ending the year with approximately $4.0 billion in cash and no borrowings under our revolving credit facility; and |
• | achieving record production of approximately 770,000 boe per day in mid-December 2014 with fewer than half the rigs used in 2012. |
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Gross | % | Net | % | Gross | % | Net | % | Gross | % | Net | % | |||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||||||||||||||
Productive | 1,784 | 99 | 629 | 99 | 1,704 | 99 | 847 | 99 | 2,075 | 99 | 956 | 99 | ||||||||||||||||||||||||
Dry | 3 | 1 | 1 | 1 | 21 | 1 | 9 | 1 | 21 | 1 | 5 | 1 | ||||||||||||||||||||||||
Total | 1,787 | 100 | 630 | 100 | 1,725 | 100 | 856 | 100 | 2,096 | 100 | 961 | 100 | ||||||||||||||||||||||||
Exploratory: | ||||||||||||||||||||||||||||||||||||
Productive | 145 | 95 | 46 | 88 | 209 | 97 | 124 | 96 | 495 | 98 | 305 | 98 | ||||||||||||||||||||||||
Dry | 8 | 5 | 6 | 12 | 6 | 3 | 5 | 4 | 10 | 2 | 6 | 2 | ||||||||||||||||||||||||
Total | 153 | 100 | 52 | 100 | 215 | 100 | 129 | 100 | 505 | 100 | 311 | 100 |
2014 | 2013 | 2012 | ||||||||||||||||
Gross Wells | Net Wells | Gross Wells | Net Wells | Gross Wells | Net Wells | |||||||||||||
Southern | 1,448 | 473 | 1,352 | 698 | 1,933 | 982 | ||||||||||||
Northern | 492 | 209 | 588 | 287 | 668 | 290 | ||||||||||||
Total | 1,940 | 682 | 1,940 | 985 | 2,601 | 1,272 |
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net Production: | ||||||||||||
Oil (mmbbl) | 42 | 41 | 31 | |||||||||
Natural gas (bcf) | 1,095 | 1,095 | 1,129 | |||||||||
NGL (mmbbl) | 33 | 21 | 18 | |||||||||
Oil equivalent (mmboe)(a) | 258 | 244 | 237 | |||||||||
Oil, Natural Gas and NGL Sales ($ in millions): | ||||||||||||
Oil sales | $ | 3,682 | $ | 3,911 | $ | 2,829 | ||||||
Oil derivatives - realized gains (losses)(b) | (185 | ) | (108 | ) | 39 | |||||||
Oil derivatives - unrealized gains (losses)(b) | 859 | 280 | 857 | |||||||||
Total oil sales | 4,356 | 4,083 | 3,725 | |||||||||
Natural gas sales | 2,777 | 2,430 | 2,004 | |||||||||
Natural gas derivatives - realized gains (losses)(b) | (191 | ) | 9 | 328 | ||||||||
Natural gas derivatives - unrealized gains (losses)(b) | 535 | (52 | ) | (331 | ) | |||||||
Total natural gas sales | 3,121 | 2,387 | 2,001 | |||||||||
NGL sales | 703 | 582 | 526 | |||||||||
NGL derivatives - realized gains (losses)(b) | — | — | (9 | ) | ||||||||
NGL derivatives - unrealized gains (losses)(b) | — | — | 35 | |||||||||
Total NGL sales | 703 | 582 | 552 | |||||||||
Total oil, natural gas and NGL sales | $ | 8,180 | $ | 7,052 | $ | 6,278 | ||||||
Average Sales Price (excluding gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 87.13 | $ | 95.17 | $ | 90.49 | ||||||
Natural gas ($ per mcf) | $ | 2.54 | $ | 2.22 | $ | 1.77 | ||||||
NGL ($ per bbl) | $ | 21.27 | $ | 27.87 | $ | 29.89 | ||||||
Oil equivalent ($ per boe) | $ | 27.78 | $ | 28.33 | $ | 22.61 | ||||||
Average Sales Price (including realized gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 82.76 | $ | 92.53 | $ | 91.74 | ||||||
Natural gas ($ per mcf) | $ | 2.36 | $ | 2.23 | $ | 2.07 | ||||||
NGL ($ per bbl) | $ | 21.27 | $ | 27.87 | $ | 29.37 | ||||||
Oil equivalent ($ per boe) | $ | 26.32 | $ | 27.92 | $ | 24.12 | ||||||
Other Operating Income(c) ($ in millions): | ||||||||||||
Marketing, gathering and compression net margin | $ | (11 | ) | $ | 98 | $ | 119 | |||||
Oilfield services net margin | $ | 115 | $ | 159 | $ | 142 | ||||||
Expenses ($ per boe): | ||||||||||||
Oil, natural gas and NGL production | $ | 4.69 | $ | 4.74 | $ | 5.50 | ||||||
Production taxes | $ | 0.90 | $ | 0.94 | $ | 0.79 | ||||||
General and administrative expenses(d) | $ | 1.25 | $ | 1.86 | $ | 2.26 | ||||||
Oil, natural gas and NGL depreciation, depletion and amortization | $ | 10.41 | $ | 10.59 | $ | 10.58 | ||||||
Depreciation and amortization of other assets | $ | 0.90 | $ | 1.28 | $ | 1.28 | ||||||
Interest expense(e) | $ | 0.63 | $ | 0.65 | $ | 0.35 |
(a) | Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. |
(b) | Realized gains and losses include the following items: (i) settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. |
(c) | Includes revenue and operating costs. See Results of Operations - Depreciation and Amortization of Other Assets in Item 7 of Part II of this report for details of the depreciation and amortization associated with our marketing, gathering and compression and former oilfield services operating segments. |
(d) | Includes stock-based compensation and excludes restructuring and other termination costs. |
(e) | Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives, and is shown net of amounts capitalized. |
December 31, 2014 | |||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | ||||||||||||
Proved developed | 229 | 8,615 | 198 | 1,864 | |||||||||||
Proved undeveloped | 192 | 2,077 | 68 | 605 | |||||||||||
Total proved(a) | 421 | 10,692 | 266 | 2,469 | |||||||||||
Proved Developed | Proved Undeveloped | Total Proved | |||||||||||||
($ in millions) | |||||||||||||||
Estimated future net revenue(b) | $ | 33,591 | $ | 13,534 | $ | 47,125 | |||||||||
Present value of estimated future net revenue(b) | $ | 17,024 | $ | 4,988 | $ | 22,012 | |||||||||
Standardized measure(b)(c) | $ | 17,133 |
Operating Division | Oil | Natural Gas | NGL | Oil Equivalent | Percent of Proved Reserves | Present Value | ||||||||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | ($ millions) | ||||||||||||||||
Southern | 372 | 6,882 | 182 | 1,701 | 69 | % | $ | 15,372 | ||||||||||||
Northern | 49 | 3,810 | 84 | 768 | 31 | % | 6,640 | |||||||||||||
Total | 421 | 10,692 | 266 | 2,469 | 100 | % | $ | 22,012 | (b) |
(a) | Includes 2 mmbbl of oil, 46 bcf of natural gas and 5 mmbbl of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbl of oil, 22 bcf of natural gas and 2 mmbbl of NGL of which are attributable to the noncontrolling interest holders. |
(b) | Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2014. For the purpose of determining "prices", we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended |
(c) | Additional information on the standardized measure is presented in Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities included in Item 8 of Part II of this report. |
Total | |||
(mmboe) | |||
Proved undeveloped reserves, beginning of period | 869 | ||
Extensions, discoveries and other additions | 227 | ||
Revisions of previous estimates | (162 | ) | |
Developed | (225 | ) | |
Sale of reserves-in-place | (105 | ) | |
Purchase of reserves-in-place | 1 | ||
Proved undeveloped reserves, end of period | 605 |
• | 24 years of practical experience working for major oil companies, including 16 years in reservoir engineering responsible for estimation and evaluation of reserves; |
• | Bachelor of Science degree in Petroleum Engineering; |
• | registered professional engineer in the state of Texas; and |
• | member in good standing of the Society of Petroleum Engineers. |
• | We follow comprehensive SEC-compliant internal policies to determine and report proved reserves. Reserves estimates are made by experienced reservoir engineers or under their direct supervision. |
• | The Corporate Reserves Department reviews all of the Company's proved reserves at the close of each quarter. |
• | Each quarter, Corporate Reserves Department managers, the Director - Corporate Reserves, the Vice Presidents of our business units, the Vice President of Corporate and Strategic Planning and the Executive Vice Presidents of our operating divisions review all significant reserves changes and all new proved undeveloped reserves additions. |
• | The Corporate Reserves Department reports independently of our operating divisions. |
% Prepared (by Volume) | Operating Division | ||||
Ryder Scott Company, L.P. | 54% | Southern | |||
PetroTechnical Services, Division of Schlumberger Technology Corporation | 25% | Northern |
• | over 30 years of practical experience in the estimation and evaluation of reserves |
• | registered professional engineer in the state of Texas |
• | member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers |
• | Bachelor of Science degree in Electrical Engineering |
• | over 30 years of practical experience in the estimation and evaluation of reserves |
• | registered professional geologist license in the Commonwealth of Pennsylvania |
• | member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers |
• | Bachelor of Science degree in Geological Sciences |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Acquisition of Properties: | ||||||||||||
Proved properties | $ | 214 | $ | 22 | $ | 332 | ||||||
Unproved properties | 1,224 | 997 | 2,981 | |||||||||
Exploratory costs | 421 | 699 | 2,353 | |||||||||
Development costs | 4,204 | 4,888 | 6,733 | |||||||||
Costs incurred(a)(b) | $ | 6,063 | $ | 6,606 | $ | 12,399 |
(a) | Exploratory and development costs are net of joint venture drilling and completion cost carries of $679 million, $884 million and $784 million in 2014, 2013 and 2012, respectively. |
(b) | Includes capitalized interest and asset retirement obligations as follows: |
Capitalized interest | $ | 604 | $ | 815 | $ | 976 | ||||||
Asset retirement obligations | $ | 39 | $ | 7 | $ | 32 |
Gross Wells Drilled | Net Wells Drilled | Exploration and Development | Acquisition of Unproved Properties | Acquisition of Proved Properties | Sales of Unproved Properties | Sales of Proved Properties | Total(a) | |||||||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||||||||
Southern | 1,448 | 473 | $ | 3,180 | $ | 182 | $ | — | $ | (199 | ) | $ | (289 | ) | $ | 2,874 | ||||||||||||||
Northern | 492 | 209 | 1,445 | 1,042 | 214 | (902 | ) | (4,461 | ) | (2,662 | ) | |||||||||||||||||||
Total | 1,940 | 682 | $ | 4,625 | $ | 1,224 | $ | 214 | $ | (1,101 | ) | $ | (4,750 | ) | $ | 212 |
(a) | Includes capitalized internal costs of $230 million and related capitalized interest of $604 million. |
Developed Leasehold | Undeveloped Leasehold | Fee Minerals | Total | |||||||||||||||||||||
Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | |||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Southern | 6,095 | 2,996 | 2,103 | 1,068 | 154 | 28 | 8,352 | 4,092 | ||||||||||||||||
Northern | 1,840 | 1,381 | 5,844 | 3,646 | 687 | 437 | 8,371 | 5,464 | ||||||||||||||||
Total | 7,935 | 4,377 | 7,947 | 4,714 | 841 | 465 | 16,723 | 9,556 |
Acres Expiring | ||||||
Gross Acres | Net Acres | |||||
(in thousands) | ||||||
Years Ending December 31: | ||||||
2015 | 1,820 | 1,058 | ||||
2016 | 1,703 | 1,105 | ||||
2017 | 1,083 | 722 | ||||
After 2017 | 3,341 | 1,829 | ||||
Total(a) | 7,947 | 4,714 |
(a) | Includes 1.873 million gross (976,000 net) held-by-production acres that will remain in force as our production continues on the subject leases, and other leasehold acreage where management anticipates the lease to remain in effect past the primary term of the agreement due to our contractual option to extend the lease term. |
• | seismic operations; |
• | the location of wells; |
• | construction and operations activities, including in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species or their habitats; |
• | the method of drilling and completing wells; |
• | production operations, including the installation of flowlines and gathering systems; |
• | air emissions and hydraulic fracturing; |
• | the surface use and restoration of properties upon which oil and natural gas facilities are located, including the construction of well pads, pipelines, impoundments and associated access roads; |
• | water withdrawal; |
• | the plugging and abandoning of wells; |
• | the generation, storage, transportation treatment, recycling or disposal of hazardous waste, fluids or other substances in connection with operations; |
• | the construction and operation of underground injection wells to dispose of produced water and other liquid oilfield wastes; |
• | the construction and operation of surface pits to contain drilling muds and other fluids associated with drilling operations; |
• | the marketing, transportation and reporting of production; and |
• | the valuation and payment of royalties. |
• | requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of wastes and other substances associated with operations; |
• | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species and/or species of special statewide concern or their habitats; |
• | requiring investigatory and remedial actions to address pollution caused by our operations or attributable to former operations; |
• | requiring noise, lighting, visual impact, odor and/or dust mitigation, setbacks, landscaping, fencing, and other measures; |
• | restricting access to certain equipment or areas to a limited set of employees or contractors who have proper certification or permits to conduct work (e.g., confined space entry and process safety maintenance requirements); and |
• | restricting or even prohibiting water use based upon availability, impacts or other factors. |
ITEM 1A. | Risk Factors |
• | domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves; |
• | weather conditions; |
• | changes in the level of consumer and industrial demand; |
• | the price and availability of alternative fuels; |
• | the effectiveness of worldwide conservation measures; |
• | the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities; |
• | the level and effect of trading in commodity futures markets, including by commodity price speculators and others; |
• | potential U.S. exports of oil and/or liquefied natural gas; |
• | the price and level of foreign imports; |
• | the nature and extent of domestic and foreign governmental regulations and taxes; |
• | the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
• | political instability or armed conflict in oil and natural gas producing regions; and |
• | domestic and global economic conditions. |
• | a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes; |
• | we may be at a competitive disadvantage as compared to similar companies that have less debt; |
• | the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; |
• | additional financing we may need in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and |
• | a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate we pay on our revolving credit facility and may subject us to additional covenants under that facility. |
• | injury or loss of life; |
• | severe damage to or destruction of property, natural resources or equipment; |
• | pollution or other environmental damage; |
• | clean-up responsibilities; |
• | regulatory investigations and administrative, civil and criminal penalties; and |
• | injunctions resulting in limitation or suspension of operations. |
• | damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism; |
• | maintenance, repairs, mechanical or structural failures; |
• | damages to, loss of availability of and delays in gaining access to interconnecting third-party pipeline; |
• | disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and |
• | leaks of oil or natural gas as a result of the malfunction of equipment or facilities. |
• | conduct of our exploration, drilling, completion, production and midstream activities; |
• | amounts and types of emissions and discharges; |
• | generation, management, and disposition of hazardous substances and waste materials; |
• | reclamation and abandonment of wells and facility sites; and |
• | remediation of contaminated sites. |
ITEM 1B. | Unresolved Staff Comments |
ITEM 2. | Properties |
ITEM 3. | Legal Proceedings |
ITEM 4. | Mine Safety Disclosures |
ITEM 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Common Stock | Dividend | |||||||||||
High | Low | Declared | ||||||||||
Year Ended December 31, 2014: | ||||||||||||
Fourth Quarter | $ | 24.43 | $ | 16.41 | $ | 0.0875 | ||||||
Third Quarter | $ | 29.92 | $ | 22.77 | $ | 0.0875 | ||||||
Second Quarter | $ | 31.49 | $ | 25.66 | $ | 0.0875 | ||||||
First Quarter | $ | 27.54 | $ | 23.92 | $ | 0.0875 | ||||||
Year Ended December 31, 2013: | ||||||||||||
Fourth Quarter | $ | 29.06 | $ | 25.06 | $ | 0.0875 | ||||||
Third Quarter | $ | 27.46 | $ | 20.30 | $ | 0.0875 | ||||||
Second Quarter | $ | 22.86 | $ | 18.21 | $ | 0.0875 | ||||||
First Quarter | $ | 22.97 | $ | 16.32 | $ | 0.0875 |
Period | Total Number of Shares Purchased(a) | Average Price Paid Per Share(a) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs | |||||||||||
($ in millions) | |||||||||||||||
October 1, 2014 through October 31, 2014 | 9,294 | $ | 22.13 | — | $ | — | |||||||||
November 1, 2014 through November 30, 2014 | 9,453 | $ | 22.00 | — | — | ||||||||||
December 1, 2014 through December 31, 2014 | 39,626 | $ | 18.53 | — | 1,000 | (b) | |||||||||
Total | 58,373 | $ | 19.67 | — | $ | 1,000 |
(a) | Reflects the surrender to the Company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock. Also includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions. |
(b) | On December 22, 2014, the Company issued a press release announcing that its Board of Directors has authorized the repurchase of up to $1 billion in value of its common stock from time to time. The repurchase program does not have an expiration date, and no repurchases had been made under the program as of December 31, 2014. |
ITEM 6. | Selected Financial Data |
Years Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||
($ in millions, except per share data) | ||||||||||||||||||||
REVENUES: | ||||||||||||||||||||
Oil, natural gas and NGL | $ | 8,180 | $ | 7,052 | $ | 6,278 | $ | 6,024 | $ | 5,647 | ||||||||||
Marketing, gathering and compression | 12,225 | 9,559 | 5,431 | 5,090 | 3,479 | |||||||||||||||
Oilfield services | 546 | 895 | 607 | 521 | 240 | |||||||||||||||
Total Revenues | 20,951 | 17,506 | 12,316 | 11,635 | 9,366 | |||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||
Oil, natural gas and NGL production | 1,208 | 1,159 | 1,304 | 1,073 | 893 | |||||||||||||||
Production taxes | 232 | 229 | 188 | 192 | 157 | |||||||||||||||
Marketing, gathering and compression | 12,236 | 9,461 | 5,312 | 4,967 | 3,352 | |||||||||||||||
Oilfield services | 431 | 736 | 465 | 402 | 208 | |||||||||||||||
General and administrative | 322 | 457 | 535 | 548 | 453 | |||||||||||||||
Restructuring and other termination costs | 7 | 248 | 7 | — | — | |||||||||||||||
Provision for legal contingencies | 234 | — | — | — | — | |||||||||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | 2,683 | 2,589 | 2,507 | 1,632 | 1,394 | |||||||||||||||
Depreciation and amortization of other assets | 232 | 314 | 304 | 291 | 220 | |||||||||||||||
Impairment of oil and natural gas properties | — | — | 3,315 | — | — | |||||||||||||||
Impairments of fixed assets and other | 88 | 546 | 340 | 46 | 21 | |||||||||||||||
Net gains on sales of fixed assets | (199 | ) | (302 | ) | (267 | ) | (437 | ) | (137 | ) | ||||||||||
Total Operating Expenses | 17,474 | 15,437 | 14,010 | 8,714 | 6,561 | |||||||||||||||
INCOME (LOSS) FROM OPERATIONS | 3,477 | 2,069 | (1,694 | ) | 2,921 | 2,805 | ||||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
Interest expense | (89 | ) | (227 | ) | (77 | ) | (44 | ) | (19 | ) | ||||||||||
Earnings (losses) on investments | (80 | ) | (226 | ) | (103 | ) | 156 | 227 | ||||||||||||
Net gain (loss) on sales of investments | 67 | (7 | ) | 1,092 | — | (129 | ) | |||||||||||||
Losses on purchases of debt | (197 | ) | (193 | ) | (200 | ) | (176 | ) | (16 | ) | ||||||||||
Other income | 22 | 26 | 8 | 23 | 16 | |||||||||||||||
Total Other Income (Expense) | (277 | ) | (627 | ) | 720 | (41 | ) | 79 | ||||||||||||
INCOME (LOSS) BEFORE INCOME TAXES | 3,200 | 1,442 | (974 | ) | 2,880 | 2,884 | ||||||||||||||
INCOME TAX EXPENSE (BENEFIT): | ||||||||||||||||||||
Current income taxes | 47 | 22 | 47 | 13 | — | |||||||||||||||
Deferred income taxes | 1,097 | 526 | (427 | ) | 1,110 | 1,110 | ||||||||||||||
Total Income Tax Expense (Benefit) | 1,144 | 548 | (380 | ) | 1,123 | 1,110 | ||||||||||||||
NET INCOME (LOSS) | 2,056 | 894 | (594 | ) | 1,757 | 1,774 | ||||||||||||||
Net income attributable to noncontrolling interests | (139 | ) | (170 | ) | (175 | ) | (15 | ) | — | |||||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | 1,917 | 724 | (769 | ) | 1,742 | 1,774 | ||||||||||||||
Preferred stock dividends | (171 | ) | (171 | ) | (171 | ) | (172 | ) | (111 | ) | ||||||||||
Premium on purchase of preferred shares of a subsidiary | (447 | ) | (69 | ) | — | — | — | |||||||||||||
Earnings allocated to participating securities | (26 | ) | (10 | ) | — | — | — | |||||||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | $ | 1,273 | $ | 474 | $ | (940 | ) | $ | 1,570 | $ | 1,663 | |||||||||
Years Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||
($ in millions, except per share data) | ||||||||||||||||||||
STATEMENT OF OPERATIONS DATA (continued): | ||||||||||||||||||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||||||||||
Basic | $ | 1.93 | $ | 0.73 | $ | (1.46 | ) | $ | 2.47 | $ | 2.63 | |||||||||
Diluted | $ | 1.87 | $ | 0.73 | $ | (1.46 | ) | $ | 2.32 | $ | 2.51 | |||||||||
CASH DIVIDEND DECLARED PER COMMON SHARE | $ | 0.35 | $ | 0.35 | $ | 0.35 | $ | 0.3375 | $ | 0.30 | ||||||||||
CASH FLOW DATA: | ||||||||||||||||||||
Cash provided by operating activities | $ | 4,634 | $ | 4,614 | $ | 2,837 | $ | 5,903 | $ | 5,117 | ||||||||||
Cash provided by (used in) investing activities | $ | 454 | $ | (2,967 | ) | $ | (4,984 | ) | $ | (5,812 | ) | $ | (8,503 | ) | ||||||
Cash provided by (used in) financing activities | $ | (1,817 | ) | $ | (1,097 | ) | $ | 2,083 | $ | 158 | $ | 3,181 | ||||||||
BALANCE SHEET DATA (AT END OF PERIOD): | ||||||||||||||||||||
Total assets | $ | 40,751 | $ | 41,782 | $ | 41,611 | $ | 41,835 | $ | 37,179 | ||||||||||
Long-term debt, net of current maturities | $ | 11,154 | $ | 12,886 | $ | 12,157 | $ | 10,626 | $ | 12,640 | ||||||||||
Total equity | $ | 18,205 | $ | 18,140 | $ | 17,896 | $ | 17,961 | $ | 15,264 |
ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net Production: | ||||||||||||
Oil (mmbbl) | 42.3 | 41.1 | 31.3 | |||||||||
Natural gas (bcf) | 1,095.0 | 1,094.6 | 1,128.8 | |||||||||
NGL (mmbbl) | 33.1 | 20.9 | 17.6 | |||||||||
Oil equivalent (mmboe)(a) | 257.8 | 244.4 | 237.0 | |||||||||
Oil, Natural Gas and NGL Sales ($ in millions): | ||||||||||||
Oil sales | $ | 3,682 | $ | 3,911 | $ | 2,829 | ||||||
Oil derivatives - realized gains (losses)(b) | (185 | ) | (108 | ) | 39 | |||||||
Oil derivatives - unrealized gains (losses)(b) | 859 | 280 | 857 | |||||||||
Total oil sales | 4,356 | 4,083 | 3,725 | |||||||||
Natural gas sales | 2,777 | 2,430 | 2,004 | |||||||||
Natural gas derivatives - realized gains (losses)(b) | (191 | ) | 9 | 328 | ||||||||
Natural gas derivatives - unrealized gains (losses)(b) | 535 | (52 | ) | (331 | ) | |||||||
Total natural gas sales | 3,121 | 2,387 | 2,001 | |||||||||
NGL sales | 703 | 582 | 526 | |||||||||
NGL derivatives - realized gains (losses)(b) | — | — | (9 | ) | ||||||||
NGL derivatives - unrealized gains (losses)(b) | — | — | 35 | |||||||||
Total NGL sales | 703 | 582 | 552 | |||||||||
Total oil, natural gas and NGL sales | $ | 8,180 | $ | 7,052 | $ | 6,278 | ||||||
Average Sales Price (excluding gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 87.13 | $ | 95.17 | $ | 90.49 | ||||||
Natural gas ($ per mcf) | $ | 2.54 | $ | 2.22 | $ | 1.77 | ||||||
NGL ($ per bbl) | $ | 21.27 | $ | 27.87 | $ | 29.89 | ||||||
Oil equivalent ($ per boe) | $ | 27.78 | $ | 28.33 | $ | 22.61 | ||||||
Average Sales Price (including realized gains (losses) on derivatives): | ||||||||||||
Oil ($ per bbl) | $ | 82.76 | $ | 92.53 | $ | 91.74 | ||||||
Natural gas ($ per mcf) | $ | 2.36 | $ | 2.23 | $ | 2.07 | ||||||
NGL ($ per bbl) | $ | 21.27 | $ | 27.87 | $ | 29.37 | ||||||
Oil equivalent ($ per boe) | $ | 26.32 | $ | 27.92 | $ | 24.12 | ||||||
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Other Operating Income(c) ($ in millions): | ||||||||||||
Marketing, gathering and compression net margin | $ | (11 | ) | $ | 98 | $ | 119 | |||||
Oilfield services net margin | $ | 115 | $ | 159 | $ | 142 | ||||||
Expenses ($ per boe): | ||||||||||||
Oil, natural gas and NGL production | $ | 4.69 | $ | 4.74 | $ | 5.50 | ||||||
Production taxes | $ | 0.90 | $ | 0.94 | $ | 0.79 | ||||||
General and administrative(d) | $ | 1.25 | $ | 1.86 | $ | 2.26 | ||||||
Oil, natural gas and NGL depreciation, depletion and amortization | $ | 10.41 | $ | 10.59 | $ | 10.58 | ||||||
Depreciation and amortization of other assets | $ | 0.90 | $ | 1.28 | $ | 1.28 | ||||||
Interest expense(e) | $ | 0.63 | $ | 0.65 | $ | 0.35 | ||||||
Interest Expense ($ in millions): | ||||||||||||
Interest expense | $ | 173 | $ | 169 | $ | 84 | ||||||
Interest rate derivatives – realized (gains) losses(f) | (12 | ) | (9 | ) | (1 | ) | ||||||
Interest rate derivatives – unrealized (gains) losses(f) | (72 | ) | 67 | (6 | ) | |||||||
Total interest expense | $ | 89 | $ | 227 | $ | 77 |
(a) | Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency. |
(b) | Realized gains and losses include the following items: (i) settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains and losses related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains and losses include the change in fair value of open derivatives scheduled to settle against future period production revenues offset by amounts reclassified as realized gains and losses during the period. |
(c) | Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression and former oilfield services operating segments. |
(d) | Includes share-based compensation but excludes restructuring and other termination costs. |
(e) | Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives, and is shown net of amounts capitalized. |
(f) | Realized (gains) losses include settlements related to the current period interest accrual and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period. |
• | enhancing the flexibility of the management team of Chesapeake and SSE to make strategic and operational decisions that are in the best interests of their respective businesses; |
• | optimizing the allocation of capital and corporate resources in a manner that focuses on achieving the strategic priorities of each company; |
• | enhancing SSE’s ability to attract E&P customers other than Chesapeake; |
• | enhancing SSE’s reputation as an independent provider of diversified oilfield services; |
• | enhancing the ability of each company to more efficiently attract and deploy capital; and |
• | enhancing the ability of Chesapeake and SSE to attract employees with appropriate skill sets, to incentivize their key employees with equity-based compensation that is aligned with the performance of their respective operations, and to retain key employees for the long term. |
• | a reduction of approximately 5,100 employees; |
• | a reduction of $1.572 billion in aggregate principal amount of long-term debt as of June 30, 2014, consisting of $650 million of 6.625% Senior Notes due 2019, $500 million of 6.5% Senior Notes due 2022, a $400 million secured term loan and $22 million outstanding under SSE’s new revolving credit facility; and |
• | the elimination of our oilfield services segment. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Cash Provided by Operating Activities | $ | 4,634 | $ | 4,614 | $ | 2,837 | ||||||
Sales of Oil and Natural Gas Assets: | ||||||||||||
Southern Marcellus and Utica | 4,970 | — | — | |||||||||
South Texas | 110 | — | — | |||||||||
East Texas and Louisiana | 58 | — | — | |||||||||
Marcellus | 231 | 490 | — | |||||||||
Eagle Ford | — | 636 | — | |||||||||
Haynesville | — | 304 | — | |||||||||
SIPC (Mississippian Lime joint venture) | — | 1,025 | — | |||||||||
Permian Basin | — | — | 3,130 | |||||||||
Texoma | — | — | 572 | |||||||||
Chitwood Knox | — | — | 540 | |||||||||
Volumetric production payments | — | — | 744 | |||||||||
Joint venture leasehold | 33 | 58 | 272 | |||||||||
Other oil and natural gas properties | 411 | 954 | 626 | |||||||||
Total Sales of Oil and Natural Gas Assets | 5,813 | 3,467 | 5,884 | |||||||||
Sales of Other Assets: | ||||||||||||
Sale of compressors to Exterran | 495 | — | — | |||||||||
Sale of compressors to ACMP | 159 | — | — | |||||||||
Sale of Chesapeake Midstream Operating, L.L.C. | — | — | 2,160 | |||||||||
Sale of Mid-America Midstream Gas Services, L.L.C. | — | 306 | — | |||||||||
Sale of Granite Wash Midstream Gas Services, L.L.C. | — | 252 | — | |||||||||
Sales of other property and equipment | 349 | 364 | 332 | |||||||||
Total Sales of Other Assets | 1,003 | 922 | 2,492 | |||||||||
Other Sources of Cash and Cash Equivalents: | ||||||||||||
Proceeds from sales of investments | 239 | 115 | 2,000 | |||||||||
Proceeds from long-term debt, net | 2,966 | 2,274 | 6,985 | |||||||||
Proceeds from oilfield services long-term debt, net | 888 | — | — | |||||||||
Sale of preferred interest and ORRI in CHK C-T | — | — | 1,250 | |||||||||
Other | 37 | 187 | 84 | |||||||||
Total Other Sources of Cash and Cash Equivalents | 4,130 | 2,576 | 10,319 | |||||||||
Total Sources of Cash and Cash Equivalents | $ | 15,580 | $ | 11,579 | $ | 21,532 |
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | Principal Amount of Debt Issued | Net Proceeds | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Senior notes(a) | $ | 3,500 | $ | 3,460 | $ | 2,300 | $ | 2,274 | $ | 1,300 | $ | 1,263 | ||||||||||||
Term loans(a) | 400 | 394 | — | — | 6,000 | 5,722 | ||||||||||||||||||
Total | $ | 3,900 | $ | 3,854 | $ | 2,300 | $ | 2,274 | $ | 7,300 | $ | 6,985 |
(a) | 2014 amounts include debt issued in connection with the spin-off of our oilfield services business. All deferred charges and debt balances related to the spin-off were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the spin-off. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Oil and Natural Gas Expenditures: | ||||||||||||
Drilling and completion costs(a) | $ | 4,495 | $ | 5,490 | $ | 8,707 | ||||||
Acquisitions of proved and unproved properties | 758 | 302 | 2,385 | |||||||||
Geological and geophysical costs | 35 | 33 | 170 | |||||||||
Interest capitalized on unproved properties | 604 | 811 | 829 | |||||||||
Total Oil and Natural Gas Expenditures | 5,892 | 6,636 | 12,091 | |||||||||
Other Uses of Cash and Cash Equivalents: | ||||||||||||
Cash paid to repurchase debt | 3,362 | 2,141 | 4,000 | |||||||||
Additions to other property and equipment | 227 | 732 | 2,615 | |||||||||
Payments on credit facility borrowings, net | 382 | 13 | 1,332 | |||||||||
Cash paid to purchase leased rigs and compressors | 499 | 240 | 36 | |||||||||
Cash paid for prepayment of mortgage | — | 55 | — | |||||||||
Cash paid to purchase preferred shares of subsidiary | 1,254 | 212 | — | |||||||||
Dividends paid | 405 | 404 | 398 | |||||||||
Distributions to noncontrolling interest owners | 173 | 215 | 218 | |||||||||
Cash paid to extinguish other financing | — | 141 | — | |||||||||
Cash paid for financing derivatives(b) | 53 | 91 | 37 | |||||||||
Additions to investments | 17 | 44 | 395 | |||||||||
Other | 45 | 105 | 474 | |||||||||
Total Other Uses of Cash and Cash Equivalents | 6,417 | 4,393 | 9,505 | |||||||||
Total Uses of Cash and Cash Equivalents | $ | 12,309 | $ | 11,029 | $ | 21,596 |
(a) | Net of $679 million, $884 million and $784 million in drilling and completion carries received from our joint venture partners during 2014, 2013 and 2012, respectively. |
(b) | Reflects derivatives deemed to contain, for accounting purposes, a significant financing element at contract inception. |
December 31, 2014 | ||||
($ in millions) | ||||
3.25% senior notes due 2016 | $ | 500 | ||
6.25% euro-denominated senior notes due 2017(a) | 416 | |||
6.5% senior notes due 2017 | 660 | |||
7.25% senior notes due 2018 | 669 | |||
Floating rate senior notes due 2019 | 1,500 | |||
6.625% senior notes due 2020 | 1,300 | |||
6.875% senior notes due 2020 | 500 | |||
6.125% senior notes due 2021 | 1,000 | |||
5.375% senior notes due 2021 | 700 | |||
4.875% senior notes due 2022 | 1,500 | |||
5.75% senior notes due 2023 | 1,100 | |||
2.75% contingent convertible senior notes due 2035(b) | 396 | |||
2.5% contingent convertible senior notes due 2037(b) | 1,168 | |||
2.25% contingent convertible senior notes due 2038(b) | 347 | |||
Discount on senior notes(c) | (231 | ) | ||
Interest rate derivatives(d) | 10 | |||
Total senior notes, net | 11,535 | |||
Less current maturities of long-term debt(e) | (381 | ) | ||
Total long-term senior notes, net | $ | 11,154 |
(a) | The principal amount shown is based on the exchange rate of $1.2098 to €1.00 as of December 31, 2014. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for information on our related foreign currency derivatives. |
(b) | 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. The first put date, for the 2.75% Contingent Convertible Senior Notes due 2035, is November 15, 2015. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. |
(c) | Included in this discount as of December 31, 2014 was $224 million associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. |
(d) | See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for discussion related to these instruments. |
(e) | As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. |
Payments Due By Period | ||||||||||||||||||||
Total | Less Than 1 Year | 1-3 Years | 3-5 Years | More Than 5 Years | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
Long-term debt: | ||||||||||||||||||||
Principal(a) | $ | 11,756 | $ | 396 | $ | 2,744 | $ | 2,516 | $ | 6,100 | ||||||||||
Interest | 4,028 | 590 | 1,109 | 921 | 1,408 | |||||||||||||||
Operating lease obligations(b) | 11 | 5 | 5 | 1 | — | |||||||||||||||
Operating commitments(c) | 17,012 | 2,332 | 4,481 | 3,319 | 6,880 | |||||||||||||||
Unrecognized tax benefits(d) | 45 | — | — | 45 | — | |||||||||||||||
Standby letters of credit | 15 | 15 | — | — | — | |||||||||||||||
Deferred premium on call options | 181 | 95 | 86 | — | — | |||||||||||||||
Other | 49 | 12 | 13 | 8 | 16 | |||||||||||||||
Total contractual cash obligations(e) | $ | 33,097 | $ | 3,445 | $ | 8,438 | $ | 6,810 | $ | 14,404 |
(a) | Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes. |
(b) | See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease obligations. |
(c) | See Note 4 of the notes to our consolidated financial statements included in Item 8 of this report for a description of gathering, processing and transportation agreements and drilling contracts. |
(d) | See Note 6 of the notes to our consolidated financial statements included in Item 8 of this report for a description of unrecognized tax benefits. |
(e) | This table does not include derivative liabilities or the estimated discounted liability for future dismantlement, abandonment and restoration costs of oil and natural gas properties. See Notes 11 and 20, respectively, of the notes to our consolidated financial statements included in Item 8 of this report for more information on our derivatives and asset retirement obligations. This table also does not include our costs to produce reserves attributable to non-expense-bearing royalty and other interests in our properties, including VPPs, which are discussed below. |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Derivative assets (liabilities): | ||||||||
Oil fixed-price swaps | $ | 471 | $ | (50 | ) | |||
Oil three-way collars | 40 | — | ||||||
Oil call options | (89 | ) | (265 | ) | ||||
Oil basis protection swaps | — | 1 | ||||||
Natural gas fixed-price swaps | 281 | (23 | ) | |||||
Natural gas three-way collars | 165 | (7 | ) | |||||
Natural gas call options | (170 | ) | (210 | ) | ||||
Natural gas basis protection swaps | 23 | 3 | ||||||
Estimated fair value | $ | 721 | $ | (551 | ) |
2014 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 35.3 | 89.04 | 580.7 | 2.38 | 16.9 | 23.93 | 148.9 | 58 | 33.08 | ||||||||||||||||||
Northern(c) | 7.0 | 77.52 | 514.3 | 2.71 | 16.2 | 18.49 | 108.9 | 42 | 20.54 | ||||||||||||||||||
Total(d) | 42.3 | 87.13 | 1,095.0 | 2.54 | 33.1 | 21.27 | 257.8 | 100 | % | 27.78 | |||||||||||||||||
2013 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 37.6 | 95.57 | 692.9 | 2.09 | 16.7 | 26.32 | 169.7 | 69 | 32.30 | ||||||||||||||||||
Northern(c) | 3.5 | 90.82 | 401.7 | 2.44 | 4.2 | 33.95 | 74.7 | 31 | 19.28 | ||||||||||||||||||
Total(d) | 41.1 | 95.17 | 1,094.6 | 2.22 | 20.9 | 27.87 | 244.4 | 100 | % | 28.33 | |||||||||||||||||
2012 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
(mmbbl) | ($/bbl)(a) | (bcf) | ($/mcf)(a) | (mmbbl) | ($/bbl)(a) | (mmboe) | % | ($/boe)(a) | |||||||||||||||||||
Southern(b) | 30.3 | 90.78 | 868.0 | 1.68 | 15.8 | 28.78 | 190.8 | 81 | 24.43 | ||||||||||||||||||
Northern(c) | 1.0 | 81.60 | 260.8 | 2.10 | 1.8 | 39.73 | 46.2 | 19 | 15.11 | ||||||||||||||||||
Total(d) | 31.3 | 90.49 | 1,128.8 | 1.77 | 17.6 | 29.89 | 237.0 | 100 | % | 22.61 |
(a) | Average sales prices exclude gains (losses) on derivatives. Decreases in the average sales prices for our oil and NGL sold in 2014 as compared to 2013 and 2012 were primarily driven by a decrease in the West Texas Intermediate (WTI) crude oil price. The increase in the average sales price for our natural gas sold in 2014 as compared to 2013 and 2012 was primarily driven by an increase in the Henry Hub natural gas price partially offset by higher basis differentials in certain of our areas relative to the Henry Hub benchmark natural gas price and increased gathering and transportation costs in certain of our areas. |
(b) | Our Southern Division includes the Eagle Ford, Granite Wash, Cleveland, Tonkawa and Mississippian Lime unconventional liquids plays and the Haynesville/Bossier and Barnett unconventional natural gas shale plays. The Eagle Ford Shale accounted for approximately 19% of our estimated proved reserves by volume as of December 31, 2014. Production for the Eagle Ford Shale for 2014, 2013 and 2012 was 35.4 mmboe, 31.7 mmboe and 17.8 mmboe, respectively. The Barnett Shale accounted for approximately 17% of our estimated proved reserves by volume as of December 31, 2014. Production for the Barnett Shale for 2014, 2013 and 2012 was 24.0 mmboe, 28.9 mmboe and 30.3 mmboe, respectively. Our gathering agreements for Barnett and Haynesville production require us to pay the service provider a fee for any production shortfall below certain annual minimum gathering volume commitments. These fees amounted to $0.11 per mcf in 2014 and $0.03 per mcf in 2013, and we anticipate incurring shortfall fees in 2015 based on current production estimates. |
(c) | Our Northern Division includes the Utica and Niobrara unconventional liquids plays and the Marcellus unconventional natural gas play. |
(d) | 2014, 2013 and 2012 production levels reflect the impact of various asset sales and joint ventures. The decrease in production in the Southern Division in 2014 as compared to 2013 and 2012 is primarily the result of our 2013 asset sale in the Haynesville Shale, along with various asset sales and joint ventures in both 2013 and 2012. The increase in production in the Northern Division in 2014 as compared to 2013 and 2012 is primarily the result of increased processing capacity in the Utica Shale. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for information on our oil and natural gas property divestitures and joint ventures. |
Years Ended December 31, | ||||||
2014 | 2013 | 2012 | ||||
Oil | 52% | 56% | 53% | |||
Natural gas | 39% | 36% | 37% | |||
NGL | 9% | 8% | 10% | |||
Total | 100% | 100% | 100% |
2014 | 2013 | 2012 | ||||||||||||||||||||
Production Expenses | $/boe | Production Expenses | $/boe | Production Expenses | $/boe | |||||||||||||||||
($ in millions, except per unit) | ||||||||||||||||||||||
Southern(a) | $ | 882 | 5.92 | $ | 925 | 5.46 | $ | 1,087 | 5.70 | |||||||||||||
Northern | 229 | 2.10 | 164 | 2.19 | 143 | 3.10 | ||||||||||||||||
1,111 | 4.31 | 1,089 | 4.46 | 1,230 | 5.19 | |||||||||||||||||
Ad valorem tax | 97 | 0.38 | 70 | 0.28 | 74 | 0.31 | ||||||||||||||||
Total | $ | 1,208 | 4.69 | $ | 1,159 | 4.74 | $ | 1,304 | 5.50 |
(a) | The per unit increase in the Southern Division from 2013 to 2014 is primarily the result of increased artificial lift, repairs and maintenance and a higher percentage of oil produced which has higher lifting costs. |
Years Ended December 31, | Estimated Useful Life | |||||||||||||
2014 | 2013 | 2012 | ||||||||||||
($ in millions) | (in years) | |||||||||||||
Oilfield services equipment(a) | $ | 74 | $ | 122 | $ | 61 | 3 - 15 | |||||||
Buildings and improvements | 42 | 47 | 42 | 10 - 39 | ||||||||||
Natural gas compressors(b) | 37 | 35 | 26 | 3 - 20 | ||||||||||
Computers and office equipment | 32 | 44 | 45 | 3 - 7 | ||||||||||
Vehicles | 24 | 38 | 52 | 0 - 7 | ||||||||||
Natural gas gathering systems and treating plants(b) | 12 | 13 | 46 | 20 | ||||||||||
Other | 11 | 15 | 32 | 2 - 20 | ||||||||||
Total depreciation and amortization of other assets | $ | 232 | $ | 314 | $ | 304 |
(a) | Included in our former oilfield services operating segment. |
(b) | Included in our marketing, gathering and compression operating segment. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Interest expense on senior notes | $ | 704 | $ | 740 | $ | 732 | ||||||
Interest expense on term loans | 36 | 116 | 173 | |||||||||
Amortization of loan discount, issuance costs and other | 42 | 91 | 89 | |||||||||
Interest expense on credit facilities | 28 | 38 | 70 | |||||||||
Realized gains on interest rate derivatives(a) | (12 | ) | (9 | ) | (1 | ) | ||||||
Unrealized (gains) losses on interest rate derivatives(b) | (72 | ) | 67 | (6 | ) | |||||||
Capitalized interest | (637 | ) | (816 | ) | (980 | ) | ||||||
Total interest expense | $ | 89 | $ | 227 | $ | 77 | ||||||
Average senior notes borrowings | $ | 11,653 | $ | 10,991 | $ | 10,487 | ||||||
Average term loan borrowings | $ | 625 | $ | 2,000 | $ | 2,096 | ||||||
Average credit facilities borrowings | $ | 306 | $ | 678 | $ | 2,517 |
(a) | Includes settlements related to the current period interest accrual and the effect of gains (losses) on early- terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. |
(b) | Includes changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the current period. |
• | taxable income projections in future years; |
• | whether the carryforward period is so brief that it would limit realization of the tax benefit; |
• | future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures; and |
• | our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition. |
• | the volatility of oil, natural gas and NGL prices; |
• | write-downs of our oil and natural gas asset carrying values due to declines in prices; |
• | the availability of operating cash flow and other funds to finance reserve replacement costs; |
• | our ability to replace reserves and sustain production; |
• | uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; |
• | our ability to generate profits or achieve targeted results in drilling and well operations; |
• | leasehold terms expiring before production can be established; |
• | commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; |
• | the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; |
• | adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; |
• | the limitations our level of indebtedness may have on our financial flexibility; |
• | charges incurred in response to market conditions and in connection with actions to reduce financial leverage and complexity; |
• | drilling and operating risks and resulting liabilities; |
• | effects of environmental protection laws and regulation on our business; |
• | legislative and regulatory initiatives further regulating hydraulic fracturing; |
• | our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; |
• | federal and state tax proposals affecting our industry; |
• | potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; |
• | impacts of potential legislative and regulatory actions addressing climate change; |
• | competition in the oil and gas exploration and production industry; |
• | a deterioration in general economic, business or industry conditions; |
• | negative public perceptions of our industry; |
• | limited control over properties we do not operate; |
• | pipeline and gathering system capacity constraints and transportation interruptions; |
• | cyber attacks adversely impacting our operations; and |
• | an interruption in operations at our headquarters due to a catastrophic event. |
ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk |
• | 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 options, 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. |
Weighted Average Price | Fair Value | |||||||||||||||||||||
Volume | Fixed | Call | Put | Differential | Asset (Liability) | |||||||||||||||||
(mmbbl) | ($ per bbl) | ($ in millions) | ||||||||||||||||||||
Oil: | ||||||||||||||||||||||
Swaps: | ||||||||||||||||||||||
Short-term | 12.5 | $ | 94.58 | $ | — | $ | — | $ | — | $ | 471 | |||||||||||
3-Way Collars: | ||||||||||||||||||||||
Short-term | 4.4 | — | 98.94 | 80.00 / 90.00 | — | 40 | ||||||||||||||||
Call Options (sold): | ||||||||||||||||||||||
Short-term | 20.5 | — | 101.85 | — | — | (9 | ) | |||||||||||||||
Long-term | 24.2 | — | 100.07 | — | — | (69 | ) | |||||||||||||||
Call Options (bought)(a): | ||||||||||||||||||||||
Short-term | (8.9 | ) | — | 113.54 | — | — | (11 | ) | ||||||||||||||
Total Oil | $ | 422 |
Weighted Average Price | Fair Value | |||||||||||||||||||||
Volume | Fixed | Call | Put | Differential | Asset (Liability) | |||||||||||||||||
(tbtu) | ($ per mmbtu) | ($ in millions) | ||||||||||||||||||||
Natural Gas: | ||||||||||||||||||||||
Swaps: | ||||||||||||||||||||||
Short-term | 238 | $ | 4.14 | $ | — | $ | — | $ | — | $ | 265 | |||||||||||
Long-term | 37 | 3.95 | — | — | — | 16 | ||||||||||||||||
3-Way Collars: | ||||||||||||||||||||||
Short-term | 207 | — | 4.51 | 3.37 / 4.29 | — | 165 | ||||||||||||||||
Call Options (sold): | ||||||||||||||||||||||
Short-term | 226 | — | 6.31 | — | — | (1 | ) | |||||||||||||||
Long-term | 393 | — | 7.93 | — | — | (10 | ) | |||||||||||||||
Call Options (bought)(b): | ||||||||||||||||||||||
Short-term | (226 | ) | — | 6.31 | — | — | (81 | ) | ||||||||||||||
Long-term | (200 | ) | — | 6.02 | — | — | (78 | ) | ||||||||||||||
Basis Protection Swaps: | ||||||||||||||||||||||
Short-term | 52 | — | — | — | 0.55 | 29 | ||||||||||||||||
Long-term | 8 | — | — | — | (1.02 | ) | (6 | ) | ||||||||||||||
Total Natural Gas | $ | 299 | ||||||||||||||||||||
Total Oil and Natural Gas | $ | 721 |
(a) | Included in the fair value are deferred premiums of $13 million which will be included in oil, natural gas and NGL sales as realized gains (losses) in 2015. |
(b) | Included in the fair value are deferred premiums of $82 million and $85 million which will be included in oil, natural gas and NGL sales as realized gains (losses) in 2015 and 2016, respectively. |
December 31, 2014 | ||||
($ in millions) | ||||
Short-term | $ | 200 | ||
Long-term | 16 | |||
Total | $ | 216 |
2014 | ||||
($ in millions) | ||||
Fair value of contracts outstanding, as of January 1 | $ | (551 | ) | |
Change in fair value of contracts | 1,054 | |||
Fair value of new contracts when entered into | — | |||
Contracts realized or otherwise settled | 202 | |||
Fair value of contracts when closed | 16 | |||
Fair value of contracts outstanding, as of December 31 | $ | 721 |
Years of Maturity | |||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | |||||||||||||||||||||
($ in millions) | |||||||||||||||||||||||||||
Liabilities: | |||||||||||||||||||||||||||
Debt – fixed rate(a) | $ | 396 | $ | 500 | $ | 2,244 | $ | 1,016 | $ | — | $ | 6,100 | $ | 10,256 | |||||||||||||
Average interest rate | 2.75 | % | 3.25 | % | 4.37 | % | 5.54 | % | — | % | 5.83 | % | 5.24 | % | |||||||||||||
Debt – variable rate | $ | — | $ | — | $ | — | $ | — | $ | 1,500 | $ | — | $ | 1,500 | |||||||||||||
Average interest rate | — | % | — | % | — | % | — | % | 3.48 | % | — | % | 3.48 | % |
(a) | This amount does not include the discount included in debt of $231 million and interest rate derivatives of $10 million. |
Weighted Average Rate | Fair Value | ||||||||||||||
Notional Amount | Fixed | Floating(a) | Fair Value Hedge | Asset (Liability) | |||||||||||
($ in millions) | ($ in millions) | ||||||||||||||
Fixed to Floating: | |||||||||||||||
Swaps | |||||||||||||||
Mature 2021 | $ | 450 | 6.13 | % | 1 – 3 mL 470 bp | No | $ | (12 | ) | ||||||
Floating to Fixed: | |||||||||||||||
Swaps | |||||||||||||||
Mature 2015 | $ | 400 | 2.59 | % | 6 mL | No | (5 | ) | |||||||
$ | (17 | ) |
(a) | Month LIBOR has been abbreviated “mL” and basis points has been abbreviated “bp”. |
ITEM 8. | Financial Statements and Supplementary Data |
INDEX TO FINANCIAL STATEMENTS CHESAPEAKE ENERGY CORPORATION | |||
Page | |||
Consolidated Financial Statements: | |||
Consolidated Balance Sheets as of December 31, 2014 and 2013 | |||
December 31, 2014, 2013 and 2012 | |||
December 31, 2014, 2013 and 2012 | |||
December 31, 2014, 2013 and 2012 | |||
December 31, 2014, 2013 and 2012 | |||
Supplementary Information | |||
Quarterly Financial Data (unaudited) | |||
Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities (unaudited) |
/s/ ROBERT D. LAWLER | ||||
Robert D. Lawler | ||||
President and Chief Executive Officer | ||||
/s/ DOMENIC J. DELL'OSSO, JR. | ||||
Domenic J. Dell'Osso, Jr. | ||||
Executive Vice President and Chief Financial Officer | ||||
February 27, 2015 | ||||
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents ($1 and $1 attributable to our VIE) | $ | 4,108 | $ | 837 | ||||
Restricted cash | 38 | 75 | ||||||
Accounts receivable, net | 2,236 | 2,222 | ||||||
Short-term derivative assets ($16 and $0 attributable to our VIE) | 879 | — | ||||||
Deferred income tax asset | — | 223 | ||||||
Other current assets | 207 | 299 | ||||||
Total Current Assets | 7,468 | 3,656 | ||||||
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) | 58,594 | 56,157 | ||||||
Unproved properties | 9,788 | 12,013 | ||||||
Oilfield services equipment | — | 2,192 | ||||||
Other property and equipment | 3,083 | 3,203 | ||||||
Total Property and Equipment, at Cost | 71,465 | 73,565 | ||||||
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE) | (39,043 | ) | (37,161 | ) | ||||
Property and equipment held for sale, net | 93 | 730 | ||||||
Total Property and Equipment, Net | 32,515 | 37,134 | ||||||
LONG-TERM ASSETS: | ||||||||
Investments | 265 | 477 | ||||||
Long-term derivative assets | 6 | 4 | ||||||
Other long-term assets | 497 | 511 | ||||||
TOTAL ASSETS | $ | 40,751 | $ | 41,782 | ||||
December 31, | ||||||||
2014 | 2013 | |||||||
CURRENT LIABILITIES: | ||||||||
Accounts payable | $ | 2,049 | $ | 1,596 | ||||
Current maturities of long-term debt, net | 381 | — | ||||||
Accrued interest | 150 | 200 | ||||||
Deferred income tax liabilities | 207 | — | ||||||
Short-term derivative liabilities ($0 and $5 attributable to our VIE) | 15 | 208 | ||||||
Other current liabilities ($15 and $22 attributable to our VIE) | 3,061 | 3,511 | ||||||
Total Current Liabilities | 5,863 | 5,515 | ||||||
LONG-TERM LIABILITIES: | ||||||||
Long-term debt, net | 11,154 | 12,886 | ||||||
Deferred income tax liabilities | 4,185 | 3,407 | ||||||
Long-term derivative liabilities | 218 | 445 | ||||||
Asset retirement obligations, net of current portion | 447 | 405 | ||||||
Other long-term liabilities | 679 | 984 | ||||||
Total Long-Term Liabilities | 16,683 | 18,127 | ||||||
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: 664,944,232 and 666,192,371 shares issued | 7 | 7 | ||||||
Paid-in capital | 12,531 | 12,446 | ||||||
Retained earnings | 1,483 | 688 | ||||||
Accumulated other comprehensive loss | (143 | ) | (162 | ) | ||||
Less: treasury stock, at cost; 1,614,312 and 2,002,029 common shares | (37 | ) | (46 | ) | ||||
Total Chesapeake Stockholders’ Equity | 16,903 | 15,995 | ||||||
Noncontrolling interests | 1,302 | 2,145 | ||||||
Total Equity | 18,205 | 18,140 | ||||||
TOTAL LIABILITIES AND EQUITY | $ | 40,751 | $ | 41,782 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions except per share data) | ||||||||||||
REVENUES: | ||||||||||||
Oil, natural gas and NGL | $ | 8,180 | $ | 7,052 | $ | 6,278 | ||||||
Marketing, gathering and compression | 12,225 | 9,559 | 5,431 | |||||||||
Oilfield services | 546 | 895 | 607 | |||||||||
Total Revenues | 20,951 | 17,506 | 12,316 | |||||||||
OPERATING EXPENSES: | ||||||||||||
Oil, natural gas and NGL production | 1,208 | 1,159 | 1,304 | |||||||||
Production taxes | 232 | 229 | 188 | |||||||||
Marketing, gathering and compression | 12,236 | 9,461 | 5,312 | |||||||||
Oilfield services | 431 | 736 | 465 | |||||||||
General and administrative | 322 | 457 | 535 | |||||||||
Restructuring and other termination costs | 7 | 248 | 7 | |||||||||
Provision for legal contingencies | 234 | — | — | |||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | 2,683 | 2,589 | 2,507 | |||||||||
Depreciation and amortization of other assets | 232 | 314 | 304 | |||||||||
Impairment of oil and natural gas properties | — | — | 3,315 | |||||||||
Impairments of fixed assets and other | 88 | 546 | 340 | |||||||||
Net gains on sales of fixed assets | (199 | ) | (302 | ) | (267 | ) | ||||||
Total Operating Expenses | 17,474 | 15,437 | 14,010 | |||||||||
INCOME (LOSS) FROM OPERATIONS | 3,477 | 2,069 | (1,694 | ) | ||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
Interest expense | (89 | ) | (227 | ) | (77 | ) | ||||||
Losses on investments | (80 | ) | (226 | ) | (103 | ) | ||||||
Net gain (loss) on sales of investments | 67 | (7 | ) | 1,092 | ||||||||
Losses on purchases of debt | (197 | ) | (193 | ) | (200 | ) | ||||||
Other income | 22 | 26 | 8 | |||||||||
Total Other Income (Expense) | (277 | ) | (627 | ) | 720 | |||||||
INCOME (LOSS) BEFORE INCOME TAXES | 3,200 | 1,442 | (974 | ) | ||||||||
INCOME TAX EXPENSE (BENEFIT): | ||||||||||||
Current income taxes | 47 | 22 | 47 | |||||||||
Deferred income taxes | 1,097 | 526 | (427 | ) | ||||||||
Total Income Tax Expense (Benefit) | 1,144 | 548 | (380 | ) | ||||||||
NET INCOME (LOSS) | 2,056 | 894 | (594 | ) | ||||||||
Net income attributable to noncontrolling interests | (139 | ) | (170 | ) | (175 | ) | ||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | 1,917 | 724 | (769 | ) | ||||||||
Preferred stock dividends | (171 | ) | (171 | ) | (171 | ) | ||||||
Redemption of preferred shares of a subsidiary | (447 | ) | (69 | ) | — | |||||||
Earnings allocated to participating securities | (26 | ) | (10 | ) | — | |||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | $ | 1,273 | $ | 474 | $ | (940 | ) | |||||
EARNINGS (LOSS) PER COMMON SHARE: | ||||||||||||
Basic | $ | 1.93 | $ | 0.73 | $ | (1.46 | ) | |||||
Diluted | $ | 1.87 | $ | 0.73 | $ | (1.46 | ) | |||||
CASH DIVIDEND DECLARED PER COMMON SHARE | $ | 0.35 | $ | 0.35 | $ | 0.35 | ||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | ||||||||||||
Basic | 659 | 653 | 643 | |||||||||
Diluted | 772 | 653 | 643 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
NET INCOME (LOSS) | $ | 2,056 | $ | 894 | $ | (594 | ) | |||||
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX: | ||||||||||||
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4 | 1 | 2 | 6 | |||||||||
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $14, $12 and ($10) | 23 | 20 | (17 | ) | ||||||||
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4) | — | (6 | ) | (5 | ) | |||||||
Reclassification of (gain) loss on investment, net of income tax expense of ($3), $3 and $0 | (5 | ) | 4 | — | ||||||||
Other Comprehensive Income (Loss) | 19 | 20 | (16 | ) | ||||||||
COMPREHENSIVE INCOME (LOSS) | 2,075 | 914 | (610 | ) | ||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS | (139 | ) | (170 | ) | (175 | ) | ||||||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | $ | 1,936 | $ | 744 | $ | (785 | ) |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
NET INCOME (LOSS) | $ | 2,056 | $ | 894 | $ | (594 | ) | |||||
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES: | ||||||||||||
Depreciation, depletion and amortization | 2,915 | 2,903 | 2,811 | |||||||||
Deferred income tax expense (benefit) | 1,097 | 526 | (427 | ) | ||||||||
Derivative gains, net | (1,102 | ) | (71 | ) | (926 | ) | ||||||
Cash (payments) receipts on derivative settlements, net | (253 | ) | (104 | ) | 226 | |||||||
Stock-based compensation | 59 | 98 | 120 | |||||||||
Impairment of oil and natural gas properties | — | — | 3,315 | |||||||||
Net gains on sales of fixed assets | (199 | ) | (302 | ) | (267 | ) | ||||||
Impairment of fixed assets and other | 58 | 483 | 316 | |||||||||
Losses on investments | 80 | 229 | 164 | |||||||||
Net (gains) losses on sales of investments | (67 | ) | 7 | (1,092 | ) | |||||||
Restructuring and other termination costs | (15 | ) | 175 | 2 | ||||||||
Provision for legal contingencies | 234 | — | — | |||||||||
Losses on purchases of debt | 63 | 40 | 200 | |||||||||
Other | 100 | 80 | 72 | |||||||||
(Increase) decrease in accounts receivable and other assets | (21 | ) | 5 | (68 | ) | |||||||
Decrease in accounts payable, accrued liabilities and other | (371 | ) | (349 | ) | (1,015 | ) | ||||||
Net Cash Provided By Operating Activities | 4,634 | 4,614 | 2,837 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Drilling and completion costs | (4,581 | ) | (5,604 | ) | (8,930 | ) | ||||||
Acquisitions of proved and unproved properties | (1,311 | ) | (1,032 | ) | (3,161 | ) | ||||||
Proceeds from divestitures of proved and unproved properties | 5,813 | 3,467 | 5,884 | |||||||||
Additions to other property and equipment | (726 | ) | (972 | ) | (2,651 | ) | ||||||
Proceeds from sales of other property and equipment | 1,003 | 922 | 2,492 | |||||||||
Additions to investments | (17 | ) | (44 | ) | (395 | ) | ||||||
Proceeds from sales of investments | 239 | 115 | 2,000 | |||||||||
Decrease (increase) in restricted cash | 37 | 177 | (222 | ) | ||||||||
Other | (3 | ) | 4 | (1 | ) | |||||||
Net Cash Provided By (Used In) Investing Activities | 454 | (2,967 | ) | (4,984 | ) | |||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Proceeds from credit facilities borrowings | 7,406 | 7,669 | 20,318 | |||||||||
Payments on credit facilities borrowings | (7,788 | ) | (7,682 | ) | (21,650 | ) | ||||||
Proceeds from issuance of senior notes, net of discount and offering costs | 2,966 | 2,274 | 1,263 | |||||||||
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs | 494 | — | — | |||||||||
Proceeds from issuance of oilfield services term loan, net of discount and offering costs | 394 | — | — | |||||||||
Proceeds from issuance of term loan, net of issuance costs | — | — | 5,722 | |||||||||
Cash paid to purchase debt | (3,362 | ) | (2,141 | ) | (4,000 | ) | ||||||
Cash paid for common stock dividends | (234 | ) | (233 | ) | (227 | ) | ||||||
Cash paid for preferred stock dividends | (171 | ) | (171 | ) | (171 | ) | ||||||
Cash paid to extinguish other financing | — | (141 | ) | — | ||||||||
Cash paid on financing derivatives | (53 | ) | (91 | ) | (37 | ) | ||||||
Cash paid for prepayment of mortgage | — | (55 | ) | — | ||||||||
Proceeds from sales of noncontrolling interests | — | 6 | 1,077 | |||||||||
Proceeds from other financings | — | — | 257 | |||||||||
Cash paid to purchase preferred shares of a subsidiary | (1,254 | ) | (212 | ) | — | |||||||
Cash held and retained by SSE at spin-off | (8 | ) | — | — | ||||||||
Distributions to noncontrolling interest owners | (173 | ) | (215 | ) | (218 | ) | ||||||
Other | (34 | ) | (105 | ) | (251 | ) | ||||||
Net Cash Provided By (Used In) Financing Activities | (1,817 | ) | (1,097 | ) | 2,083 | |||||||
Net increase (decrease) in cash and cash equivalents | 3,271 | 550 | (64 | ) | ||||||||
Cash and cash equivalents, beginning of period | 837 | 287 | 351 | |||||||||
Cash and cash equivalents, end of period | $ | 4,108 | $ | 837 | $ | 287 | ||||||
Supplemental disclosures to the consolidated statements of cash flows are presented below: | ||||||||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
Interest paid, net of capitalized interest | $ | 96 | $ | 43 | $ | — | ||||||
Income taxes paid, net of refunds received | $ | 10 | $ | 26 | $ | 44 | ||||||
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||||||||||
Change in accrued drilling and completion costs | $ | (84 | ) | $ | (63 | ) | $ | (75 | ) | |||
Change in accrued acquisitions of proved and unproved properties | $ | (74 | ) | $ | (1 | ) | $ | 242 | ||||
Change in accrued additions to other property and equipment | $ | (11 | ) | $ | (81 | ) | $ | (25 | ) |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
PREFERRED STOCK: | ||||||||||||
Balance, beginning and end of period | $ | 3,062 | $ | 3,062 | $ | 3,062 | ||||||
COMMON STOCK: | ||||||||||||
Balance, beginning and end of period | 7 | 7 | 7 | |||||||||
PAID-IN CAPITAL: | ||||||||||||
Balance, beginning of period | 12,446 | 12,293 | 12,146 | |||||||||
Stock-based compensation | 47 | 162 | 174 | |||||||||
Exercise of stock options | 23 | 4 | 3 | |||||||||
Increase (decrease) in tax benefit from stock-based compensation | 15 | (13 | ) | (30 | ) | |||||||
Balance, end of period | 12,531 | 12,446 | 12,293 | |||||||||
RETAINED EARNINGS: | ||||||||||||
Balance, beginning of period | 688 | 437 | 1,608 | |||||||||
Net income (loss) attributable to Chesapeake | 1,917 | 724 | (769 | ) | ||||||||
Dividends on common stock | (234 | ) | (233 | ) | (231 | ) | ||||||
Dividends on preferred stock | (171 | ) | (171 | ) | (171 | ) | ||||||
Spin-off of oilfield services business (Note 13) | (270 | ) | — | — | ||||||||
Redemption of preferred shares of a subsidiary | (447 | ) | (69 | ) | — | |||||||
Balance, end of period | 1,483 | 688 | 437 | |||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): | ||||||||||||
Balance, beginning of period | (162 | ) | (182 | ) | (166 | ) | ||||||
Hedging activity | 24 | 22 | (11 | ) | ||||||||
Investment activity | (5 | ) | (2 | ) | (5 | ) | ||||||
Balance, end of period | (143 | ) | (162 | ) | (182 | ) | ||||||
TREASURY STOCK – COMMON: | ||||||||||||
Balance, beginning of period | (46 | ) | (48 | ) | (33 | ) | ||||||
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans | (1 | ) | (6 | ) | (16 | ) | ||||||
Release of 422,395, 397,098 and 57,252 shares from company benefit plans | 10 | 8 | 1 | |||||||||
Balance, end of period | (37 | ) | (46 | ) | (48 | ) | ||||||
TOTAL CHESAPEAKE STOCKHOLDERS’ EQUITY | 16,903 | 15,995 | 15,569 | |||||||||
NONCONTROLLING INTERESTS: | ||||||||||||
Balance, beginning of period | 2,145 | 2,327 | 1,337 | |||||||||
Sales of noncontrolling interests | — | 6 | 1,077 | |||||||||
Net income attributable to noncontrolling interests | 139 | 170 | 175 | |||||||||
Distributions to noncontrolling interest owners | (169 | ) | (215 | ) | (218 | ) | ||||||
Redemption of preferred shares of a subsidiary | (807 | ) | (143 | ) | — | |||||||
Deconsolidation of investments, net | (6 | ) | — | (44 | ) | |||||||
Balance, end of period | 1,302 | 2,145 | 2,327 | |||||||||
TOTAL EQUITY | $ | 18,205 | $ | 18,140 | $ | 17,896 |
1. | Basis of Presentation and Summary of Significant Accounting Policies |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Oil, natural gas and NGL sales | $ | 1,340 | $ | 1,548 | ||||
Joint interest | 691 | 417 | ||||||
Oilfield services(a) | — | 63 | ||||||
Related parties(b) | — | 62 | ||||||
Other | 226 | 150 | ||||||
Allowance for doubtful accounts | (21 | ) | (18 | ) | ||||
Total accounts receivable, net | $ | 2,236 | $ | 2,222 |
(a) | In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet. |
(b) | See Note 7 for discussion of related party transactions. |
Year of Acquisition | ||||||||||||||||||||
2014 | 2013 | 2012 | Prior | Total | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
Leasehold acquisition cost | $ | 577 | $ | 199 | $ | 1,462 | $ | 5,149 | $ | 7,387 | ||||||||||
Exploration cost | 340 | 90 | 244 | 42 | 716 | |||||||||||||||
Capitalized interest | 492 | 421 | 325 | 447 | 1,685 | |||||||||||||||
Total | $ | 1,409 | $ | 710 | $ | 2,031 | $ | 5,638 | $ | 9,788 |
• | Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization. |
• | Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services. |
• | Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental. |
• | Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed. |
• | Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit. |
2. | Earnings Per Share |
Net Income Adjustments | Shares | ||||||
($ in millions) | (in millions) | ||||||
Year Ended December 31, 2014 | |||||||
Participating securities | $ | 22 | 3 | ||||
Year Ended December 31, 2013 | |||||||
Common stock equivalent of our preferred stock outstanding: | |||||||
5.75% cumulative convertible preferred stock | $ | 86 | 56 | ||||
5.75% cumulative convertible preferred stock (series A) | $ | 63 | 40 | ||||
5.00% cumulative convertible preferred stock (series 2005B) | $ | 10 | 5 | ||||
4.50% cumulative convertible preferred stock | $ | 12 | 6 | ||||
Participating securities | $ | 10 | 5 | ||||
Year Ended December 31, 2012 | |||||||
Common stock equivalent of our preferred stock outstanding: | |||||||
5.75% cumulative convertible preferred stock | $ | 86 | 56 | ||||
5.75% cumulative convertible preferred stock (series A) | $ | 63 | 39 | ||||
5.00% cumulative convertible preferred stock (series 2005B) | $ | 10 | 5 | ||||
4.50% cumulative convertible preferred stock | $ | 12 | 6 | ||||
Participating securities | $ | — | 5 |
Income (Numerator) | Weighted Average Shares (Denominator) | Per Share Amount | |||||||||
(in millions, except per share data) | |||||||||||
For the Year Ended December 31, 2014: | |||||||||||
Basic EPS | $ | 1,273 | 659 | $ | 1.93 | ||||||
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 | 86 | 59 | |||||||||
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) | 63 | 42 | |||||||||
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B) | 10 | 6 | |||||||||
Common shares assumed issued for 4.50% cumulative convertible preferred stock | 12 | 6 | |||||||||
Diluted EPS | $ | 1,444 | 772 | $ | 1.87 |
3. | Debt |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Term loan due 2017(a) | $ | — | $ | 2,000 | ||||
9.5% senior notes due 2015(b) | — | 1,265 | ||||||
3.25% senior notes due 2016 | 500 | 500 | ||||||
6.25% euro-denominated senior notes due 2017(c) | 416 | 473 | ||||||
6.5% senior notes due 2017 | 660 | 660 | ||||||
6.875% senior notes due 2018(d) | — | 97 | ||||||
7.25% senior notes due 2018 | 669 | 669 | ||||||
Floating rate senior notes due 2019 | 1,500 | — | ||||||
6.625% senior notes due 2019(e) | — | 650 | ||||||
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 | — | ||||||
5.75% senior notes due 2023 | 1,100 | 1,100 | ||||||
2.75% contingent convertible senior notes due 2035(f) | 396 | 396 | ||||||
2.5% contingent convertible senior notes due 2037(f) | 1,168 | 1,168 | ||||||
2.25% contingent convertible senior notes due 2038(f) | 347 | 347 | ||||||
Revolving credit facility | — | — | ||||||
Oilfield services revolving credit facility(g) | — | 405 | ||||||
Discount on senior notes and term loan(h) | (231 | ) | (357 | ) | ||||
Interest rate derivatives(i) | 10 | 13 | ||||||
Total debt, net | 11,535 | 12,886 | ||||||
Less current maturities of long-term debt, net(j) | (381 | ) | — | |||||
Total long-term debt, net | $ | 11,154 | $ | 12,886 |
(a) | In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017. |
(b) | In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes. |
(c) | The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives. |
(d) | In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018. |
(e) | Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off. |
(f) | The repurchase, conversion, contingent interest and redemption provisions of our 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 |
(g) | In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off. |
(h) | Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below. |
(i) | See Note 11 for further discussion related to these instruments. |
(j) | As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes. |
Principal Amount of Debt Securities | ||||
($ in millions) | ||||
2015 | $ | 396 | ||
2016 | 500 | |||
2017 | 2,244 | |||
2018 | 1,016 | |||
2019 | 1,500 | |||
2020 and thereafter | 6,100 | |||
Total | $ | 11,756 |
• | Entered into a five-year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility. |
• | Entered into a $400 million seven-year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s existing credit facility. |
• | Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes. |
December 31, 2014 | December 31, 2013 | |||||||||||||||
Carrying Amount | Estimated Fair Value | Carrying Amount | Estimated Fair Value | |||||||||||||
($ in millions) | ||||||||||||||||
Long-term debt (Level 1) | $ | 11,525 | $ | 12,052 | $ | 10,501 | $ | 11,557 | ||||||||
Long-term debt (Level 2) | $ | — | $ | — | $ | 2,372 | $ | 2,369 |
4. | Contingencies and Commitments |
December 31, 2014 | ||||
($ in millions) | ||||
2015 | $ | 5 | ||
2016 | 4 | |||
2017 | 1 | |||
2018 | 1 | |||
Total | $ | 11 |
December 31, 2014 | ||||
($ in millions) | ||||
2015 | $ | 1,855 | ||
2016 | 1,987 | |||
2017 | 2,003 | |||
2018 | 1,802 | |||
2019 | 1,516 | |||
2020 - 2099 | 6,880 | |||
Total | $ | 16,043 |
December 31, 2014 | ||||
($ in millions) | ||||
2015 | $ | 232 | ||
2016 | 179 | |||
2017 | 91 | |||
Total | $ | 502 |
December 31, 2014 | ||||
($ in millions) | ||||
2015 | $ | 245 | ||
2016 | 162 | |||
2017 | 59 | |||
Total | $ | 466 |
5. | Other Liabilities |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Revenues and royalties due others | $ | 1,176 | $ | 1,409 | ||||
Accrued oil, natural gas and NGL drilling and production costs | 385 | 457 | ||||||
Joint interest prepayments received | 189 | 464 | ||||||
Accrued compensation and benefits | 344 | 320 | ||||||
Other accrued taxes | 55 | 161 | ||||||
Accrued dividends | 101 | 101 | ||||||
Other | 811 | 599 | ||||||
Total other current liabilities | $ | 3,061 | $ | 3,511 |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
CHK Utica ORRI conveyance obligation(a) | $ | 220 | $ | 250 | ||||
CHK C-T ORRI conveyance obligation(b) | 135 | 149 | ||||||
Financing obligations | 30 | 31 | ||||||
Unrecognized tax benefits | 45 | 317 | ||||||
Other | 249 | 237 | ||||||
Total other long-term liabilities | $ | 679 | $ | 984 |
(a) | $14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction. |
(b) | $23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction. |
6. | Income Taxes |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Current | ||||||||||||
Federal | $ | — | $ | — | $ | — | ||||||
State | 47 | 22 | 47 | |||||||||
Current Income Taxes | 47 | 22 | 47 | |||||||||
Deferred | ||||||||||||
Federal | 1,115 | 502 | (358 | ) | ||||||||
State | (18 | ) | 24 | (69 | ) | |||||||
Deferred Income Taxes | 1,097 | 526 | (427 | ) | ||||||||
Total | $ | 1,144 | $ | 548 | $ | (380 | ) |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ | 1,120 | $ | 505 | $ | (341 | ) | |||||
State income taxes (net of federal income tax benefit) | 68 | 88 | (38 | ) | ||||||||
Remeasurement of state deferred tax liabilities | (114 | ) | (38 | ) | (19 | ) | ||||||
Change in valuation allowance | 74 | (12 | ) | — | ||||||||
Other | (4 | ) | 5 | 18 | ||||||||
Total | $ | 1,144 | $ | 548 | $ | (380 | ) |
Years Ended December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Deferred tax liabilities: | ||||||||
Oil and natural gas properties | $ | (3,950 | ) | $ | (2,631 | ) | ||
Other property and equipment | (14 | ) | (371 | ) | ||||
Volumetric production payments | (920 | ) | (1,216 | ) | ||||
Contingent convertible debt | (443 | ) | (439 | ) | ||||
Deferred revenue | (102 | ) | — | |||||
Derivative instruments | (428 | ) | — | |||||
Deferred tax liabilities | (5,857 | ) | (4,657 | ) | ||||
Deferred tax assets: | ||||||||
Net operating loss carryforwards (carrybacks) | 945 | 535 | ||||||
Derivative instruments | — | 108 | ||||||
Asset retirement obligations | 165 | 153 | ||||||
Investments | 88 | 130 | ||||||
Deferred stock compensation | 50 | 66 | ||||||
Accrued liabilities | 214 | 120 | ||||||
Noncontrolling interest liabilities | 135 | 152 | ||||||
Alternative minimum tax credits | 34 | 317 | ||||||
Other | 56 | 40 | ||||||
Deferred tax assets | 1,687 | 1,621 | ||||||
Valuation allowance | (222 | ) | (148 | ) | ||||
Net deferred tax assets | 1,465 | 1,473 | ||||||
Net deferred tax assets (liabilities) | $ | (4,392 | ) | $ | (3,184 | ) | ||
Reflected in accompanying balance sheets as: | ||||||||
Current deferred income tax asset | — | 223 | ||||||
Current deferred income tax liability | (207 | ) | — | |||||
Non-current deferred income tax liability | (4,185 | ) | (3,407 | ) | ||||
Total | $ | (4,392 | ) | $ | (3,184 | ) |
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Unrecognized tax benefits at beginning of period | $ | 644 | $ | 599 | $ | 369 | ||||||
Additions based on tax positions related to the current year | 13 | 15 | 134 | |||||||||
Additions to tax positions of prior years | — | 30 | 96 | |||||||||
Reductions to tax positions of prior years | (354 | ) | — | — | ||||||||
Unrecognized tax benefits at end of period | $ | 303 | $ | 644 | $ | 599 |
7. | Related Party Transactions |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Purchases(a) | $ | — | $ | — | $ | 73 | ||||||
Sales(b) | $ | — | $ | 666 | $ | 392 | ||||||
Services(c) | $ | 220 | $ | 397 | $ | 480 |
(a) | Purchase of equipment from FTS International, Inc. (FTS). |
(b) | In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014. |
(c) | Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs. |
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Amounts due from equity method investees | $ | — | $ | 47 | $ | 67 | ||||||
Amounts due to equity method investees | $ | — | $ | 1 | $ | 42 |
8. | Equity |
Years Ended December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
(in thousands) | |||||||||
Shares issued as of January 1 | 666,192 | 666,468 | 660,888 | ||||||
Restricted stock issuances (net of forfeitures and cancellations)(a) | (2,529 | ) | (599 | ) | 5,038 | ||||
Stock option exercises | 1,281 | 323 | 542 | ||||||
Shares issued as of December 31 | 664,944 | 666,192 | 666,468 |
(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 Series | Issue Date | Liquidation Preference per Share | Holder's Conversion Right | Conversion Rate | Conversion Price | Company's Conversion Right From | Company's Market Conversion Trigger(a) | |||||||||||||
5.75% cumulative convertible non-voting | May and June 2010 | $ | 1,000 | Any time | 39.5856 | $ | 25.2617 | May 17, 2015 | $ | 32.8402 | ||||||||||
5.75% (series A) cumulative convertible non-voting | May 2010 | $ | 1,000 | Any time | 38.2538 | $ | 26.1412 | May 17, 2015 | $ | 33.9836 | ||||||||||
4.50% cumulative convertible | September 2005 | $ | 100 | Any time | 2.4468 | $ | 40.8693 | September 15, 2010 | $ | 53.1301 | ||||||||||
5.00% cumulative convertible (series 2005B) | November 2005 | $ | 100 | Any time | 2.7669 | $ | 36.1415 | November 15, 2010 | $ | 46.9840 |
(a) | Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding. |
5.75% | 5.75% (A) | 4.50% | 5.00% (2005B) | |||||||||
(in thousands) | ||||||||||||
Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012 | 1,497 | 1,100 | 2,559 | 2,096 |
Net Gains (Losses) on Cash Flow Hedges | Net Gains (Losses) on Investments | Total | ||||||||||
($ in millions) | ||||||||||||
Balance, December 31, 2013 | $ | (167 | ) | $ | 5 | $ | (162 | ) | ||||
Other comprehensive income before reclassifications | 1 | — | 1 | |||||||||
Amounts reclassified from accumulated other comprehensive income | 23 | (5 | ) | 18 | ||||||||
Net other comprehensive income | 24 | (5 | ) | 19 | ||||||||
Balance, December 31, 2014 | $ | (143 | ) | $ | — | $ | (143 | ) | ||||
Balance, December 31, 2012 | $ | (189 | ) | $ | 7 | $ | (182 | ) | ||||
Other comprehensive income before reclassifications | 2 | (6 | ) | (4 | ) | |||||||
Amounts reclassified from accumulated other comprehensive income | 20 | 4 | 24 | |||||||||
Net other comprehensive income | 22 | (2 | ) | 20 | ||||||||
Balance, December 31, 2013 | $ | (167 | ) | $ | 5 | $ | (162 | ) |
Details About Accumulated Other Comprehensive Income (Loss) Components | Affected Line Item in the Statement Where Net Income is Presented | Year Ended December 31, 2014 | ||||
($ in millions) | ||||||
Year Ended December 31, 2014: | ||||||
Net losses on cash flow hedges: | ||||||
Commodity contracts | Oil, natural gas and NGL revenues | $ | 23 | |||
Investments: | ||||||
Sale of investment | Net gain on sale of investment | (5 | ) | |||
Total reclassifications for the period, net of tax | $ | 18 | ||||
Year Ended December 31, 2013: | ||||||
Net losses on cash flow hedges: | ||||||
Commodity contracts | Oil, natural gas and NGL revenues | $ | 20 | |||
Investments: | ||||||
Impairment of investment | Losses on investments | 6 | ||||
Sale of investment | Net gain on sale of investment | (2 | ) | |||
Total reclassifications for the period, net of tax | $ | 24 |
Production Period | Distribution Date | Cash Distribution per Common Unit | Cash Distribution per Subordinated Unit | |||||||
June 2014 - August 2014 | December 1, 2014 | $ | 0.5079 | $ | — | |||||
March 2014 - May 2014 | August 29, 2014 | $ | 0.5796 | $ | — | |||||
December 2013 - February 2014 | May 30, 2014 | $ | 0.6454 | $ | — | |||||
September 2013 - November 2013 | March 3, 2014 | $ | 0.6624 | $ | — | |||||
June 2013 - August 2013 | November 29, 2013 | $ | 0.6671 | $ | — | |||||
March 2013 - May 2013 | August 29, 2013 | $ | 0.6900 | $ | 0.1432 | |||||
December 2012 - February 2013 | May 31, 2013 | $ | 0.6900 | $ | 0.3010 | |||||
September 2012 - November 2012 | March 1, 2013 | $ | 0.6700 | $ | 0.3772 | |||||
June 2012 - August 2012 | November 29, 2012 | $ | 0.6300 | $ | 0.2208 | |||||
March 2012 - May 2012 | August 30, 2012 | $ | 0.6100 | $ | 0.4819 | |||||
December 2011 - February 2012 | May 31, 2012 | $ | 0.6588 | $ | 0.6588 | |||||
September 2011 - November 2011 | March 1, 2012 | $ | 0.7277 | $ | 0.7277 |
9. | Share-Based Compensation |
Shares of Unvested Restricted Stock | Weighted Average Grant Date Fair Value | ||||||
(in thousands) | |||||||
Unvested restricted stock as of January 1, 2014 | 13,400 | $ | 23.38 | ||||
Granted | 5,049 | $ | 25.92 | ||||
Vested | (4,803 | ) | $ | 27.17 | |||
Forfeited | (3,555 | ) | $ | 28.09 | |||
Unvested restricted stock as of December 31, 2014 | 10,091 | $ | 21.20 | ||||
Unvested restricted stock as of January 1, 2013 | 18,899 | $ | 23.72 | ||||
Granted | 9,189 | $ | 19.68 | ||||
Vested | (12,897 | ) | $ | 21.32 | |||
Forfeited | (1,791 | ) | $ | 22.86 | |||
Unvested restricted stock as of December 31, 2013 | 13,400 | $ | 23.38 | ||||
Unvested restricted stock as of January 1, 2012 | 19,544 | $ | 26.97 | ||||
Granted | 9,480 | $ | 21.13 | ||||
Vested | (8,620 | ) | $ | 28.08 | |||
Forfeited | (1,505 | ) | $ | 24.57 | |||
Unvested restricted stock as of December 31, 2012 | 18,899 | $ | 23.72 |
Expected option life - years | 5.9 | ||
Volatility | 48.63 | % | |
Risk-free interest rate | 1.93 | % | |
Dividend yield | 1.33 | % |
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, 2014 | 5,268 | $ | 19.28 | 6.66 | $ | 41 | |||||||
Granted | 994 | $ | 24.43 | ||||||||||
Exercised | (1,322 | ) | $ | 18.71 | $ | 11 | |||||||
Expired | (28 | ) | $ | 18.97 | |||||||||
Forfeited | (313 | ) | $ | 21.05 | |||||||||
Outstanding at December 31, 2014 | 4,599 | $ | 19.55 | 7.03 | $ | 5 | |||||||
Exercisable at December 31, 2014 | 1,304 | $ | 18.71 | 5.70 | $ | 1 | |||||||
Outstanding at January 1, 2013 | 481 | $ | 12.69 | 0.96 | $ | 2 | |||||||
Granted | 5,264 | $ | 19.32 | ||||||||||
Exercised | (346 | ) | $ | 10.82 | $ | 3 | |||||||
Expired | (131 | ) | $ | 19.31 | |||||||||
Outstanding at December 31, 2013 | 5,268 | $ | 19.28 | 6.66 | $ | 41 | |||||||
Exercisable at December 31, 2013 | 1,552 | $ | 18.82 | 1.97 | $ | 13 | |||||||
Outstanding at January 1, 2012 | 1,051 | $ | 9.84 | 1.41 | $ | 13 | |||||||
Exercised | (570 | ) | $ | 7.45 | $ | 7 | |||||||
Outstanding and exercisable at December 31, 2012 | 481 | $ | 12.69 | 0.96 | $ | 2 |
(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. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
General and administrative expenses | $ | 46 | $ | 60 | $ | 71 | ||||||
Oil and natural gas properties | 29 | 52 | 71 | |||||||||
Oil, natural gas and NGL production expenses | 18 | 21 | 24 | |||||||||
Marketing, gathering and compression expenses | 6 | 7 | 15 | |||||||||
Oilfield services expenses | 5 | 10 | 10 | |||||||||
Total | $ | 104 | $ | 150 | $ | 191 |
Volatility | 41.37 | % | |
Risk-free interest rate | 0.76 | % | |
Dividend yield for value of awards | 1.36 | % |
Units | Fair Value as of Grant Date | Fair Value(a) | Liability for Vested Amount | ||||||||||||
($ in millions) | |||||||||||||||
2012 Awards (b) | |||||||||||||||
Payable 2015 | 884,507 | $ | 23 | $ | 12 | $ | 12 | ||||||||
2013 Awards | |||||||||||||||
Payable 2016 | 1,701,941 | $ | 35 | $ | 42 | $ | 39 | ||||||||
2014 Awards | |||||||||||||||
Payable 2017 | 609,637 | $ | 16 | $ | 10 | $ | 7 |
(a) | As of December 31, 2014. |
(b) | In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
General and administrative expenses | $ | (4 | ) | $ | 34 | $ | 8 | |||||
Oil and natural gas properties | 3 | 9 | 4 | |||||||||
Oil, natural gas and NGL production expenses | — | 2 | 1 | |||||||||
Marketing, gathering and compression expenses | — | 2 | 1 | |||||||||
Oilfield services expenses | — | 1 | — | |||||||||
Total | $ | (1 | ) | $ | 48 | $ | 14 |
11. | Derivative and Hedging Activities |
• | 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. |
• | Call Swaptions: Chesapeake sells call swaptions in exchange for a premium that allows a counterparty, on a specific date, to enter into a fixed-price swap for a certain period of time. |
• | 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. |
December 31, 2014 | December 31, 2013 | |||||||||||||
Volume | Fair Value | Volume | Fair Value | |||||||||||
($ in millions) | ($ in millions) | |||||||||||||
Oil (mmbbl): | ||||||||||||||
Fixed-price swaps | 12.5 | 471 | 25.3 | (50 | ) | |||||||||
Three-way collars | 4.4 | 40 | — | — | ||||||||||
Call options | 35.8 | (89 | ) | 42.5 | (265 | ) | ||||||||
Basis protection swaps | — | — | 0.4 | 1 | ||||||||||
Total oil | 52.7 | 422 | 68.2 | (314 | ) | |||||||||
Natural gas (tbtu): | ||||||||||||||
Fixed-price swaps | 275 | $ | 281 | 448 | $ | (23 | ) | |||||||
Three-way collars | 207 | 165 | 288 | (7 | ) | |||||||||
Call options | 193 | (170 | ) | 193 | (210 | ) | ||||||||
Call swaptions | — | — | 12 | — | ||||||||||
Basis protection swaps | 60 | 23 | 68 | 3 | ||||||||||
Total natural gas | 735 | 299 | 1,009 | (237 | ) | |||||||||
Total estimated fair value | $ | 721 | $ | (551 | ) |
Balance Sheet Classification | Gross Fair Value | Amounts Netted in Consolidated Balance Sheet | Net Fair Value Presented in Consolidated Balance Sheet | |||||||||
($ in millions) | ||||||||||||
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 | ||||||
As of December 31, 2013 | ||||||||||||
Commodity Contracts | ||||||||||||
Short-term derivative asset | $ | 29 | $ | (29 | ) | $ | — | |||||
Long-term derivative asset | 11 | (9 | ) | 2 | ||||||||
Short-term derivative liability | (231 | ) | 29 | (202 | ) | |||||||
Long-term derivative liability | (362 | ) | 9 | (353 | ) | |||||||
Total commodity contracts | (553 | ) | — | (553 | ) | |||||||
Interest Rate Contracts | ||||||||||||
Short-term derivative liability | (6 | ) | — | (6 | ) | |||||||
Long-term derivative liability | (92 | ) | — | (92 | ) | |||||||
Total interest rate contracts | (98 | ) | — | (98 | ) | |||||||
Foreign Currency Contracts(a) | ||||||||||||
Long-term derivative asset | 2 | — | 2 | |||||||||
Total foreign currency contracts | 2 | — | 2 | |||||||||
Total Derivatives | $ | (649 | ) | $ | — | $ | (649 | ) |
(a) | Designated as cash flow hedging instruments. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Oil, natural gas and NGL sales | $ | 7,162 | $ | 6,923 | $ | 5,359 | ||||||
Gains on undesignated oil and natural gas derivatives | 1,055 | 443 | 857 | |||||||||
Gains (losses) on terminated cash flow hedges | (37 | ) | (314 | ) | 62 | |||||||
Total oil, natural gas and NGL sales | $ | 8,180 | $ | 7,052 | $ | 6,278 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Interest expense on senior notes | $ | 704 | $ | 740 | $ | 732 | ||||||
Interest expense on term loans | 36 | 116 | 173 | |||||||||
Amortization of loan discount, issuance costs and other | 42 | 91 | 89 | |||||||||
Interest expense on credit facilities | 28 | 38 | 70 | |||||||||
Gains on terminated fair value hedges | (3 | ) | (5 | ) | (8 | ) | ||||||
(Gains) losses on undesignated interest rate derivatives | (81 | ) | 63 | 1 | ||||||||
Capitalized interest | (637 | ) | (816 | ) | (980 | ) | ||||||
Total interest expense | $ | 89 | $ | 227 | $ | 77 |
Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Before Tax | After Tax | Before Tax | After Tax | Before Tax | After Tax | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Balance, beginning of period | $ | (269 | ) | $ | (167 | ) | $ | (304 | ) | $ | (189 | ) | $ | (287 | ) | $ | (178 | ) | ||||||
Net change in fair value | 1 | 1 | 3 | 2 | 10 | 6 | ||||||||||||||||||
Gains (losses) reclassified to income | 37 | 23 | 32 | 20 | (27 | ) | (17 | ) | ||||||||||||||||
Balance, end of period | $ | (231 | ) | $ | (143 | ) | $ | (269 | ) | $ | (167 | ) | $ | (304 | ) | $ | (189 | ) |
Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Fair Value | |||||||||||||
($ in millions) | ||||||||||||||||
As of December 31, 2014 | ||||||||||||||||
Derivative Assets (Liabilities): | ||||||||||||||||
Commodity assets | $ | — | $ | 785 | $ | 205 | $ | 990 | ||||||||
Commodity liabilities | — | (9 | ) | (259 | ) | (268 | ) | |||||||||
Interest rate liabilities | — | (17 | ) | — | (17 | ) | ||||||||||
Foreign currency liabilities | — | (53 | ) | — | (53 | ) | ||||||||||
Total derivatives | $ | — | $ | 706 | $ | (54 | ) | $ | 652 | |||||||
As of December 31, 2013 | ||||||||||||||||
Derivative Assets (Liabilities): | ||||||||||||||||
Commodity assets | $ | — | $ | 25 | $ | 15 | $ | 40 | ||||||||
Commodity liabilities | — | (100 | ) | (493 | ) | (593 | ) | |||||||||
Interest rate liabilities | — | (98 | ) | — | (98 | ) | ||||||||||
Foreign currency assets | — | 2 | — | 2 | ||||||||||||
Total derivatives | $ | — | $ | (171 | ) | $ | (478 | ) | $ | (649 | ) |
Derivatives | ||||||||
Commodity | Interest Rate | |||||||
($ in millions) | ||||||||
Beginning Balance as of January 1, 2014 | $ | (478 | ) | $ | — | |||
Total gains (losses) (realized/unrealized): | ||||||||
Included in earnings(a) | 292 | — | ||||||
Total purchases, issuances, sales and settlements: | ||||||||
Settlements | 136 | — | ||||||
Transfers(b) | (4 | ) | — | |||||
Ending Balance as of December 31, 2014 | $ | (54 | ) | $ | — | |||
Beginning Balance as of January 1, 2013 | $ | (1,016 | ) | $ | — | |||
Total gains (losses) (realized/unrealized): | ||||||||
Included in earnings(a) | 410 | (1 | ) | |||||
Total purchases, issuances, sales and settlements: | ||||||||
Sales | — | 1 | ||||||
Settlements | 128 | — | ||||||
Ending Balance as of December 31, 2013 | $ | (478 | ) | $ | — |
(a) | Oil, Natural Gas and NGL Sales | Interest Expense | ||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ in millions) | ||||||||||||||||
Total gains (losses) included in earnings for the period | $ | 292 | $ | 410 | $ | — | $ | (1 | ) | |||||||
Change in unrealized gains (losses) related to assets still held at reporting date | $ | 262 | $ | 382 | $ | — | $ | — |
(b) | The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values. |
Instrument Type | Unobservable Input | Range | Weighted Average | Fair Value December 31, 2014(a) | ||||||
($ in millions) | ||||||||||
Oil trades | Oil price volatility curves | 27.33% - 43.56% | 34.09% | $ | (49 | ) | ||||
Natural gas trades | Natural gas price volatility curves | 18.71% - 63.70% | 34.38% | $ | (5 | ) |
(a) | Fair value is based on an estimate derived from option models. |
12. | Oil and Natural Gas Property Transactions |
Volume Sold | ||||||||||||||||||||
VPP # | Date of VPP | Location | Proceeds | Oil | Natural Gas | NGL | Total | |||||||||||||
($ in millions) | (mmbbl) | (bcf) | (mmbbl) | (bcfe) | ||||||||||||||||
10 | March 2012 | Anadarko Basin Granite Wash | $ | 744 | 3.0 | 87 | 9.2 | 160 | ||||||||||||
9 | May 2011 | Mid-Continent | 853 | 1.7 | 138 | 4.8 | 177 | |||||||||||||
8 | September 2010 | Barnett Shale | 1,150 | — | 390 | — | 390 | |||||||||||||
4 | December 2008 | Anadarko and Arkoma Basins | 412 | 0.5 | 95 | — | 98 | |||||||||||||
3 | August 2008 | Anadarko Basin | 600 | — | 93 | — | 93 | |||||||||||||
2 | May 2008 | Texas, Oklahoma and Kansas | 622 | — | 94 | — | 94 | |||||||||||||
1 | December 2007 | Kentucky and West Virginia | 1,100 | — | 208 | — | 208 | |||||||||||||
$ | 5,481 | 5.2 | 1,105 | 14.0 | 1,220 |
Year Ended December 31, 2014 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10 | 403.0 | 10.6 | 1,296.5 | 20.7 | ||||||||
9 | 187.5 | 15.4 | 411.0 | 19.0 | ||||||||
8 | — | 60.1 | — | 60.1 | ||||||||
6(a) | 23.1 | 4.2 | — | 4.3 | ||||||||
5(a) | 16.5 | 4.6 | — | 4.7 | ||||||||
4 | 48.1 | 9.0 | — | 9.2 | ||||||||
3 | — | 7.2 | — | 7.2 | ||||||||
2 | — | 6.2 | — | 6.2 | ||||||||
1 | — | 13.8 | — | 13.8 | ||||||||
678.2 | 131.1 | 1,707.5 | 145.2 | |||||||||
Year Ended December 31, 2013 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10 | 547.0 | 13.5 | 1,509.0 | 25.8 | ||||||||
9 | 213.2 | 17.0 | 455.7 | 21.0 | ||||||||
8 | — | 68.1 | — | 68.1 | ||||||||
6 | 24.0 | 4.8 | — | 4.9 | ||||||||
5 | 25.4 | 7.5 | — | 7.7 | ||||||||
4 | 54.7 | 10.2 | — | 10.5 | ||||||||
3 | — | 8.1 | — | 8.1 | ||||||||
2 | — | 10.3 | — | 10.3 | ||||||||
1 | — | 14.5 | — | 14.5 | ||||||||
864.3 | 154.0 | 1,964.7 | 170.9 | |||||||||
Year Ended December 31, 2012 | ||||||||||||
VPP # | Oil | Natural Gas | NGL | Total | ||||||||
(mbbl) | (bcf) | (mbbl) | (bcfe) | |||||||||
10 | 727.0 | 18.1 | 1,729.1 | 32.8 | ||||||||
9 | 249.3 | 18.4 | 643.6 | 23.7 | ||||||||
8 | — | 79.7 | — | 79.7 | ||||||||
7(b) | 490.3 | 0.4 | — | 3.4 | ||||||||
6 | 24.0 | 5.3 | — | 5.5 | ||||||||
5 | 27.4 | 8.8 | — | 9.0 | ||||||||
4 | 62.8 | 11.7 | — | 12.2 | ||||||||
3 | — | 9.3 | — | 9.3 | ||||||||
2 | — | 11.4 | — | 11.3 | ||||||||
1 | — | 15.3 | — | 15.3 | ||||||||
1,580.8 | 178.4 | 2,372.7 | 202.2 |
(a) | In 2014, we divested the properties associated with VPP #5 and VPP #6. |
(b) | In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets. |
Volume Remaining as of December 31, 2014 | ||||||||||||||
VPP # | Term Remaining | Oil | Natural Gas | NGL | Total | |||||||||
(in months) | (mmbbl) | (bcf) | (mmbbl) | (bcfe) | ||||||||||
10 | 86 | 1.3 | 38.0 | 4.7 | 74.0 | |||||||||
9 | 74 | 0.8 | 73.2 | 1.9 | 89.9 | |||||||||
8 | 8 | — | 36.6 | — | 36.6 | |||||||||
4 | 24 | 0.1 | 15.3 | — | 15.8 | |||||||||
3 | 55 | — | 23.9 | — | 23.9 | |||||||||
2 | 52 | — | 13.8 | — | 13.8 | |||||||||
1 | 96 | — | 91.5 | — | 91.5 | |||||||||
2.2 | 292.3 | 6.6 | 345.5 |
13. | Spin-Off of Oilfield Services Business |
• | COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s existing credit facility. |
• | COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 16 for further discussion of the sale. |
• | We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off. |
• | COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes. |
• | COO converted from a limited liability company into a corporation named Seventy Seven Energy Inc. |
• | We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company. |
• | The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off. |
• | The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes. |
• | The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 9 for additional information regarding the effect of the spin-off on outstanding equity compensation. |
• | The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services. |
• | The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 4 for a summary of the terms of the services agreement. |
• | We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $410 million. |
14. | Investments |
Approximate Ownership % | Carrying Value | |||||||||||||
Accounting | December 31, | December 31, | ||||||||||||
Method | 2014 | 2013 | 2014 | 2013 | ||||||||||
($ in millions) | ||||||||||||||
FTS International, Inc. | Equity | 30% | 30% | $ | 116 | $ | 138 | |||||||
Sundrop Fuels, Inc. | Equity | 56% | 56% | 130 | 135 | |||||||||
Chaparral Energy, Inc. | Equity | —% | 20% | — | 143 | |||||||||
Other | — | —% | —% | 19 | 61 | |||||||||
Total investments | $ | 265 | $ | 477 |
15. | Variable Interest Entities |
16. | Other Property and Equipment |
December 31, | Estimated Useful Life | |||||||||
2014 | 2013 | |||||||||
($ in millions) | (in years) | |||||||||
Buildings and improvements | $ | 1,242 | $ | 1,433 | 10 - 39 | |||||
Natural gas compressors | 551 | 368 | 3 - 20 | |||||||
Land | 296 | 212 | — | |||||||
Gathering systems and treating plants | 218 | 292 | 20 | |||||||
Oilfield services equipment | — | 2,192 | 3 - 15 | |||||||
Other | 776 | 898 | 2 - 20 | |||||||
Total other property and equipment, at cost | 3,083 | 5,395 | ||||||||
Less: accumulated depreciation | (804 | ) | (1,584 | ) | ||||||
Total other property and equipment, net | $ | 2,279 | $ | 3,811 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Natural gas compressors | $ | (195 | ) | $ | — | $ | — | |||||
Gathering systems and treating plants | 8 | (326 | ) | (286 | ) | |||||||
Oilfield services equipment | (7 | ) | 2 | 10 | ||||||||
Buildings and land | (2 | ) | 27 | 7 | ||||||||
Other | (3 | ) | (5 | ) | 2 | |||||||
Total net gains on sales of fixed assets | $ | (199 | ) | $ | (302 | ) | $ | (267 | ) |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Buildings and land, net of accumulated depreciation | $ | 93 | $ | 405 | ||||
Compressors, net of accumulated depreciation | — | 285 | ||||||
Oilfield services equipment, net of accumulated depreciation | — | 29 | ||||||
Gathering systems and treating plants, net of accumulated depreciation | — | 11 | ||||||
Property and equipment held for sale, net | $ | 93 | $ | 730 |
17. | Impairments |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Natural gas compressors | $ | 11 | $ | — | $ | — | ||||||
Gathering systems and treating plants | 13 | 22 | 6 | |||||||||
Oilfield services equipment | 23 | 71 | 60 | |||||||||
Buildings and land | 18 | 366 | 248 | |||||||||
Other | 23 | 87 | 26 | |||||||||
Total impairments of fixed assets and other | $ | 88 | $ | 546 | $ | 340 |
18. | Restructuring and Other Termination Costs |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Oilfield services spin-off costs: | ||||||||||||
Transaction costs | $ | 17 | $ | — | $ | — | ||||||
Stock-based compensation adjustments for Chesapeake employees | 5 | — | — | |||||||||
Stock-based compensation forfeitures for SSE employees | (10 | ) | — | — | ||||||||
Debt extinguishment costs | 3 | — | — | |||||||||
Total oilfield services spin-off costs | 15 | — | — | |||||||||
Restructuring charges under workforce reduction plan: | ||||||||||||
Salary expense | — | 20 | — | |||||||||
Acceleration of stock-based compensation | — | 45 | — | |||||||||
Other termination benefits | — | 1 | — | |||||||||
Total restructuring changes under workforce reduction plan | — | 66 | — | |||||||||
Termination benefits provided to Mr. McClendon: | ||||||||||||
Salary and bonus expense | — | 11 | — | |||||||||
Acceleration of 2008 performance bonus clawback | — | 11 | — | |||||||||
Acceleration of stock-based compensation | — | 22 | — | |||||||||
Acceleration of performance share unit awards(a) | (8 | ) | 18 | — | ||||||||
Estimated aircraft usage benefits | — | 7 | — | |||||||||
Total termination benefits provided to Mr. McClendon | (8 | ) | 69 | — | ||||||||
Termination benefits provided to VSP participants: | ||||||||||||
Salary and bonus expense | — | 33 | 1 | |||||||||
Acceleration of stock-based compensation | — | 29 | 1 | |||||||||
Other termination benefits | — | 1 | — | |||||||||
Total termination benefits provided to VSP participants | — | 63 | 2 | |||||||||
Other termination benefits(a) | — | 50 | 5 | |||||||||
Total restructuring and other termination costs | $ | 7 | $ | 248 | $ | 7 |
(a) | Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9. |
19. | Fair Value Measurements |
Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total Fair Value | |||||||||||||
($ in millions) | ||||||||||||||||
As of December 31, 2014 | ||||||||||||||||
Financial Assets (Liabilities): | ||||||||||||||||
Other current assets | $ | 57 | $ | — | $ | — | $ | 57 | ||||||||
Other current liabilities | (58 | ) | — | — | (58 | ) | ||||||||||
Total | $ | (1 | ) | $ | — | $ | — | $ | (1 | ) | ||||||
As of December 31, 2013 | ||||||||||||||||
Financial Assets (Liabilities): | ||||||||||||||||
Other current assets | $ | 80 | $ | — | $ | — | $ | 80 | ||||||||
Other current liabilities | (82 | ) | — | — | (82 | ) | ||||||||||
Total | $ | (2 | ) | $ | — | $ | — | $ | (2 | ) |
20. | Asset Retirement Obligations |
Years Ended December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Asset retirement obligations, beginning of period | $ | 405 | $ | 375 | ||||
Additions | 29 | 20 | ||||||
Revisions(a) | 101 | 8 | ||||||
Settlements and disposals | (92 | ) | (20 | ) | ||||
Accretion expense | 22 | 22 | ||||||
Asset retirement obligations, end of period | 465 | 405 | ||||||
Less current portion (b) | 18 | — | ||||||
Asset retirement obligation, long-term | $ | 447 | $ | 405 |
(a) | Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement. |
(b) | Balance is included in other current liabilities on the consolidated balance sheet. |
21. | Major Customers and Segment Information |
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2014: | ||||||||||||||||||||||||
Revenues | $ | 8,180 | $ | 20,790 | $ | 1,060 | $ | 30 | $ | (9,109 | ) | $ | 20,951 | |||||||||||
Intersegment revenues | — | (8,565 | ) | (544 | ) | — | 9,109 | — | ||||||||||||||||
Total revenues | $ | 8,180 | $ | 12,225 | $ | 516 | $ | 30 | $ | — | $ | 20,951 | ||||||||||||
Unrealized gains on commodity derivatives | $ | (1,394 | ) | $ | — | $ | — | $ | — | $ | — | $ | (1,394 | ) | ||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 2,756 | $ | 38 | $ | 145 | $ | 42 | $ | (66 | ) | $ | 2,915 | |||||||||||
Impairments of fixed assets and other | $ | 22 | $ | 24 | $ | 23 | $ | 19 | $ | — | $ | 88 | ||||||||||||
Net gains on sales of fixed assets | $ | (2 | ) | $ | (187 | ) | $ | (8 | ) | $ | (2 | ) | $ | — | $ | (199 | ) | |||||||
Interest expense | $ | (709 | ) | $ | (21 | ) | $ | (42 | ) | $ | 3 | $ | 680 | $ | (89 | ) | ||||||||
Earnings (losses) on investments | $ | 2 | $ | — | $ | (6 | ) | $ | (76 | ) | $ | — | $ | (80 | ) | |||||||||
Net gain (loss) on sales of investments | $ | (6 | ) | $ | — | $ | — | $ | 73 | $ | — | $ | 67 | |||||||||||
Losses on purchases of debt | $ | (197 | ) | $ | — | $ | — | $ | — | $ | — | $ | (197 | ) | ||||||||||
Income (Loss) Before Income Taxes | $ | 2,874 | $ | 326 | $ | (16 | ) | $ | (30 | ) | $ | 46 | $ | 3,200 | ||||||||||
Total Assets | $ | 35,381 | $ | 1,978 | $ | — | $ | 4,283 | $ | (891 | ) | $ | 40,751 | |||||||||||
Capital Expenditures | $ | 6,173 | $ | 298 | $ | 158 | $ | 38 | $ | — | $ | 6,667 | ||||||||||||
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2013: | ||||||||||||||||||||||||
Revenues | $ | 7,052 | $ | 17,129 | $ | 2,188 | $ | 29 | $ | (8,892 | ) | $ | 17,506 | |||||||||||
Intersegment revenues | — | (7,570 | ) | (1,309 | ) | (13 | ) | 8,892 | — | |||||||||||||||
Total revenues | $ | 7,052 | $ | 9,559 | $ | 879 | $ | 16 | $ | — | $ | 17,506 | ||||||||||||
Unrealized gains on commodity derivatives | $ | (228 | ) | $ | — | $ | — | $ | — | $ | — | $ | (228 | ) | ||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 2,674 | $ | 46 | $ | 289 | $ | 49 | $ | (155 | ) | $ | 2,903 | |||||||||||
Impairments of fixed assets and other | $ | 27 | $ | 50 | $ | 75 | $ | 394 | $ | — | $ | 546 | ||||||||||||
Net (gains) losses on sales of fixed assets | $ | 2 | $ | (329 | ) | $ | (1 | ) | $ | 26 | $ | — | $ | (302 | ) | |||||||||
Interest expense | $ | (918 | ) | $ | (24 | ) | $ | (82 | ) | $ | (74 | ) | $ | 871 | $ | (227 | ) | |||||||
Earnings (losses) on investments | $ | 3 | $ | — | $ | (1 | ) | $ | (229 | ) | $ | 1 | $ | (226 | ) | |||||||||
Net gain (loss) on sales of investments | $ | — | $ | — | $ | — | $ | (7 | ) | $ | — | $ | (7 | ) | ||||||||||
Losses on purchases of debt | $ | (193 | ) | $ | — | $ | — | $ | — | $ | — | $ | (193 | ) | ||||||||||
Income (Loss) Before Income Taxes | $ | 2,997 | $ | 511 | $ | (51 | ) | $ | (727 | ) | $ | (1,288 | ) | $ | 1,442 | |||||||||
Total Assets | $ | 35,341 | $ | 2,430 | $ | 2,018 | $ | 5,750 | $ | (3,757 | ) | $ | 41,782 | |||||||||||
Capital Expenditures | $ | 6,198 | $ | 299 | $ | 272 | $ | 421 | $ | — | $ | 7,190 | ||||||||||||
Exploration and Production | Marketing, Gathering and Compression | Former Oilfield Services | Other | Intercompany Eliminations | Consolidated Total | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Year Ended December 31, 2012: | ||||||||||||||||||||||||
Revenues | $ | 6,278 | $ | 10,895 | $ | 1,917 | $ | 21 | $ | (6,795 | ) | $ | 12,316 | |||||||||||
Intersegment revenues | — | (5,464 | ) | (1,315 | ) | (16 | ) | 6,795 | — | |||||||||||||||
Total revenues | $ | 6,278 | $ | 5,431 | $ | 602 | $ | 5 | $ | — | $ | 12,316 | ||||||||||||
Unrealized losses on commodity derivatives | $ | (561 | ) | $ | — | $ | — | $ | — | $ | — | $ | (561 | ) | ||||||||||
Oil, natural gas, NGL and other depreciation, depletion and amortization | $ | 2,624 | $ | 54 | $ | 232 | $ | 46 | $ | (145 | ) | $ | 2,811 | |||||||||||
Impairment of oil and natural gas properties | $ | 3,315 | $ | — | $ | — | $ | — | $ | — | $ | 3,315 | ||||||||||||
Impairments of fixed assets and other | $ | 28 | $ | 6 | $ | 60 | $ | 246 | $ | — | $ | 340 | ||||||||||||
Net (gains) losses on sales of fixed assets | $ | 14 | $ | (298 | ) | $ | 10 | $ | 7 | $ | — | $ | (267 | ) | ||||||||||
Interest expense | $ | (47 | ) | $ | (20 | ) | $ | (76 | ) | $ | (364 | ) | $ | 430 | $ | (77 | ) | |||||||
Earnings (losses) on investments | $ | — | $ | 49 | $ | — | $ | (152 | ) | $ | — | $ | (103 | ) | ||||||||||
Net gain (loss) on sales of investments | $ | (2 | ) | $ | 1,094 | $ | — | $ | — | $ | — | $ | 1,092 | |||||||||||
Losses on purchases of debt | $ | (200 | ) | $ | — | $ | — | $ | — | $ | — | $ | (200 | ) | ||||||||||
Income (Loss) Before Income Taxes | $ | (1,798 | ) | $ | 1,665 | $ | 112 | $ | (478 | ) | $ | (475 | ) | $ | (974 | ) | ||||||||
Total Assets | $ | 37,004 | $ | 2,291 | $ | 2,115 | $ | 2,529 | $ | (2,328 | ) | $ | 41,611 | |||||||||||
Capital Expenditures | $ | 12,044 | $ | 852 | $ | 658 | $ | 554 | $ | — | $ | 14,108 |
22. | Condensed Consolidating Financial Information |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
CURRENT ASSETS: | ||||||||||||||||||||
Cash and cash equivalents | $ | 4,100 | $ | 2 | $ | 84 | $ | (78 | ) | $ | 4,108 | |||||||||
Restricted cash | — | — | 38 | — | 38 | |||||||||||||||
Other | 55 | 3,174 | 93 | — | 3,322 | |||||||||||||||
Intercompany receivable, net | 24,527 | — | 341 | (24,868 | ) | — | ||||||||||||||
Total Current Assets | 28,682 | 3,176 | 556 | (24,946 | ) | 7,468 | ||||||||||||||
PROPERTY AND EQUIPMENT: | ||||||||||||||||||||
Oil and natural gas properties, at cost based on full cost accounting, net | — | 28,358 | 1,112 | 673 | 30,143 | |||||||||||||||
Other property and equipment, net | — | 2,276 | 3 | — | 2,279 | |||||||||||||||
Property and equipment held for sale, net | — | 93 | — | — | 93 | |||||||||||||||
Total Property and Equipment, Net | — | 30,727 | 1,115 | 673 | 32,515 | |||||||||||||||
LONG-TERM ASSETS: | ||||||||||||||||||||
Other assets | 153 | 618 | 26 | (29 | ) | 768 | ||||||||||||||
Investments in subsidiaries and intercompany advances | 126 | 467 | — | (593 | ) | — | ||||||||||||||
TOTAL ASSETS | $ | 28,961 | $ | 34,988 | $ | 1,697 | $ | (24,895 | ) | $ | 40,751 | |||||||||
CURRENT LIABILITIES: | ||||||||||||||||||||
Current liabilities | $ | 792 | $ | 5,084 | $ | 68 | $ | (81 | ) | $ | 5,863 | |||||||||
Intercompany payable, net | — | 24,937 | — | (24,937 | ) | — | ||||||||||||||
Total Current Liabilities | 792 | 30,021 | 68 | (25,018 | ) | 5,863 | ||||||||||||||
LONG-TERM LIABILITIES: | ||||||||||||||||||||
Long-term debt, net | 11,154 | — | — | — | 11,154 | |||||||||||||||
Deferred income tax liabilities | — | 3,751 | 234 | 200 | 4,185 | |||||||||||||||
Other long-term liabilities | 112 | 1,090 | 142 | — | 1,344 | |||||||||||||||
Total Long-Term Liabilities | 11,266 | 4,841 | 376 | 200 | 16,683 | |||||||||||||||
EQUITY: | ||||||||||||||||||||
Chesapeake stockholders’ equity | 16,903 | 126 | 1,253 | (1,379 | ) | 16,903 | ||||||||||||||
Noncontrolling interests | — | — | — | 1,302 | 1,302 | |||||||||||||||
Total Equity | 16,903 | 126 | 1,253 | (77 | ) | 18,205 | ||||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 28,961 | $ | 34,988 | $ | 1,697 | $ | (24,895 | ) | $ | 40,751 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
CURRENT ASSETS: | ||||||||||||||||||||
Cash and cash equivalents | $ | 799 | $ | 8 | $ | 38 | $ | (8 | ) | $ | 837 | |||||||||
Restricted cash | — | 37 | 38 | — | 75 | |||||||||||||||
Other | 103 | 2,465 | 524 | (348 | ) | 2,744 | ||||||||||||||
Intercompany receivable, net | 25,549 | — | 860 | (26,409 | ) | — | ||||||||||||||
Total Current Assets | 26,451 | 2,510 | 1,460 | (26,765 | ) | 3,656 | ||||||||||||||
PROPERTY AND EQUIPMENT: | ||||||||||||||||||||
Oil and natural gas properties, at cost based on full cost accounting, net | — | 30,933 | 1,471 | 189 | 32,593 | |||||||||||||||
Other property and equipment, net | — | 2,360 | 1,452 | (1 | ) | 3,811 | ||||||||||||||
Property and equipment held for sale, net | — | 701 | 29 | — | 730 | |||||||||||||||
Total Property and Equipment, Net | — | 33,994 | 2,952 | 188 | 37,134 | |||||||||||||||
LONG-TERM ASSETS: | ||||||||||||||||||||
Other assets | 111 | 1,161 | 96 | (376 | ) | 992 | ||||||||||||||
Investments in subsidiaries and intercompany advances | 2,169 | (209 | ) | — | (1,960 | ) | — | |||||||||||||
TOTAL ASSETS | $ | 28,731 | $ | 37,456 | $ | 4,508 | $ | (28,913 | ) | $ | 41,782 | |||||||||
CURRENT LIABILITIES: | ||||||||||||||||||||
Current liabilities | $ | 300 | $ | 5,262 | $ | 309 | $ | (356 | ) | $ | 5,515 | |||||||||
Intercompany payable, net | — | 26,409 | — | (26,409 | ) | — | ||||||||||||||
Total Current Liabilities | 300 | 31,671 | 309 | (26,765 | ) | 5,515 | ||||||||||||||
LONG-TERM LIABILITIES: | ||||||||||||||||||||
Long-term debt, net | 11,831 | — | 1,055 | — | 12,886 | |||||||||||||||
Deferred income tax liabilities | 209 | 2,338 | 773 | 87 | 3,407 | |||||||||||||||
Other long-term liabilities | 396 | 1,278 | 504 | (344 | ) | 1,834 | ||||||||||||||
Total Long-Term Liabilities | 12,436 | 3,616 | 2,332 | (257 | ) | 18,127 | ||||||||||||||
EQUITY: | ||||||||||||||||||||
Chesapeake stockholders’ equity | 15,995 | 2,169 | 1,867 | (4,036 | ) | 15,995 | ||||||||||||||
Noncontrolling interests | — | — | — | 2,145 | 2,145 | |||||||||||||||
Total Equity | 15,995 | 2,169 | 1,867 | (1,891 | ) | 18,140 | ||||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 28,731 | $ | 37,456 | $ | 4,508 | $ | (28,913 | ) | $ | 41,782 |
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
REVENUES: | ||||||||||||||||||||
Oil, natural gas and NGL | $ | — | $ | 7,765 | $ | 418 | $ | (3 | ) | $ | 8,180 | |||||||||
Marketing, gathering and compression | — | 12,220 | 5 | — | 12,225 | |||||||||||||||
Oilfield services | — | 41 | 983 | (478 | ) | 546 | ||||||||||||||
Total Revenues | — | 20,026 | 1,406 | (481 | ) | 20,951 | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||
Oil, natural gas and NGL production | — | 1,166 | 42 | — | 1,208 | |||||||||||||||
Production taxes | — | 227 | 5 | — | 232 | |||||||||||||||
Marketing, gathering and compression | — | 12,232 | 4 | — | 12,236 | |||||||||||||||
Oilfield services | — | 53 | 769 | (391 | ) | 431 | ||||||||||||||
General and administrative | — | 273 | 49 | — | 322 | |||||||||||||||
Restructuring and other termination costs | — | 4 | 3 | — | 7 | |||||||||||||||
Provision for legal contingencies | 100 | 134 | — | — | 234 | |||||||||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | — | 2,523 | 162 | (2 | ) | 2,683 | ||||||||||||||
Depreciation and amortization of other assets | — | 153 | 143 | (64 | ) | 232 | ||||||||||||||
Impairment of oil and natural gas properties | — | — | 349 | (349 | ) | — | ||||||||||||||
Impairments of fixed assets and other | — | 65 | 23 | — | 88 | |||||||||||||||
Net gains on sales of fixed assets | — | (192 | ) | (7 | ) | — | (199 | ) | ||||||||||||
Total Operating Expenses | 100 | 16,638 | 1,542 | (806 | ) | 17,474 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS | (100 | ) | 3,388 | (136 | ) | 325 | 3,477 | |||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
Interest expense | (657 | ) | (37 | ) | (42 | ) | 647 | (89 | ) | |||||||||||
Losses on investments | — | (77 | ) | (5 | ) | 2 | (80 | ) | ||||||||||||
Net gain on sales of investments | — | 67 | — | — | 67 | |||||||||||||||
Losses on purchases of debt | (195 | ) | (2 | ) | — | — | (197 | ) | ||||||||||||
Other income (expense) | 502 | 198 | (2 | ) | (676 | ) | 22 | |||||||||||||
Equity in net earnings (losses) of subsidiary | 2,206 | (258 | ) | — | (1,948 | ) | — | |||||||||||||
Total Other Income (Expense) | 1,856 | (109 | ) | (49 | ) | (1,975 | ) | (277 | ) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES | 1,756 | 3,279 | (185 | ) | (1,650 | ) | 3,200 | |||||||||||||
INCOME TAX EXPENSE (BENEFIT) | (161 | ) | 1,264 | (66 | ) | 107 | 1,144 | |||||||||||||
NET INCOME (LOSS) | 1,917 | 2,015 | (119 | ) | (1,757 | ) | 2,056 | |||||||||||||
Net income attributable to noncontrolling interests | — | — | — | (139 | ) | (139 | ) | |||||||||||||
NET INCOME ATTRIBUTABLE TO CHESAPEAKE | 1,917 | 2,015 | (119 | ) | (1,896 | ) | 1,917 | |||||||||||||
Other comprehensive income | 1 | 18 | — | — | 19 | |||||||||||||||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | $ | 1,918 | $ | 2,033 | $ | (119 | ) | $ | (1,896 | ) | $ | 1,936 |
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
REVENUES: | ||||||||||||||||||||
Oil, natural gas and NGL | $ | — | $ | 6,439 | $ | 553 | $ | 60 | $ | 7,052 | ||||||||||
Marketing, gathering and compression | — | 9,547 | 12 | — | 9,559 | |||||||||||||||
Oilfield services | — | 221 | 1,836 | (1,162 | ) | 895 | ||||||||||||||
Total Revenues | — | 16,207 | 2,401 | (1,102 | ) | 17,506 | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||
Oil, natural gas and NGL production | — | 1,112 | 47 | — | 1,159 | |||||||||||||||
Production taxes | — | 222 | 7 | — | 229 | |||||||||||||||
Marketing, gathering and compression | — | 9,455 | 6 | — | 9,461 | |||||||||||||||
Oilfield services | — | 239 | 1,434 | (937 | ) | 736 | ||||||||||||||
General and administrative | — | 375 | 83 | (1 | ) | 457 | ||||||||||||||
Restructuring and other termination costs | — | 244 | 4 | — | 248 | |||||||||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | — | 2,336 | 253 | — | 2,589 | |||||||||||||||
Depreciation and amortization of other assets | — | 180 | 281 | (147 | ) | 314 | ||||||||||||||
Impairment of oil and natural gas properties | — | (2 | ) | 313 | (311 | ) | — | |||||||||||||
Impairments of fixed assets and other | — | 417 | 129 | — | 546 | |||||||||||||||
Net gains on sales of fixed assets | — | (301 | ) | (1 | ) | — | (302 | ) | ||||||||||||
Total Operating Expenses | — | 14,277 | 2,556 | (1,396 | ) | 15,437 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS | — | 1,930 | (155 | ) | 294 | 2,069 | ||||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
Interest expense | (921 | ) | (4 | ) | (85 | ) | 783 | (227 | ) | |||||||||||
Losses on investments | — | (225 | ) | (1 | ) | — | (226 | ) | ||||||||||||
Net loss on sales of investments | — | (7 | ) | — | — | (7 | ) | |||||||||||||
Losses on purchases of debt | (70 | ) | (123 | ) | — | — | (193 | ) | ||||||||||||
Other income | 3,979 | (603 | ) | 13 | (3,363 | ) | 26 | |||||||||||||
Equity in net earnings (losses) of subsidiary | (1,129 | ) | (383 | ) | — | 1,512 | — | |||||||||||||
Total Other Income (Expense) | 1,859 | (1,345 | ) | (73 | ) | (1,068 | ) | (627 | ) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES | 1,859 | 585 | (228 | ) | (774 | ) | 1,442 | |||||||||||||
INCOME TAX EXPENSE (BENEFIT) | 1,135 | 370 | (87 | ) | (870 | ) | 548 | |||||||||||||
NET INCOME (LOSS) | 724 | 215 | (141 | ) | 96 | 894 | ||||||||||||||
Net income attributable to noncontrolling interests | — | — | — | (170 | ) | (170 | ) | |||||||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | 724 | 215 | (141 | ) | (74 | ) | 724 | |||||||||||||
Other comprehensive income (loss) | 3 | 19 | (2 | ) | — | 20 | ||||||||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE | $ | 727 | $ | 234 | $ | (143 | ) | $ | (74 | ) | $ | 744 |
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
REVENUES: | ||||||||||||||||||||
Oil, natural gas and NGL | $ | — | $ | 5,920 | $ | 351 | $ | 7 | $ | 6,278 | ||||||||||
Marketing, gathering and compression | — | 5,218 | 212 | 1 | 5,431 | |||||||||||||||
Oilfield services | — | 154 | 1,553 | (1,100 | ) | 607 | ||||||||||||||
Total Revenues | — | 11,292 | 2,116 | (1,092 | ) | 12,316 | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||||||||
Oil, natural gas and NGL production | — | 1,278 | 26 | — | 1,304 | |||||||||||||||
Production taxes | — | 182 | 6 | — | 188 | |||||||||||||||
Marketing, gathering and compression | — | 5,197 | 115 | — | 5,312 | |||||||||||||||
Oilfield services | — | 301 | 1,096 | (932 | ) | 465 | ||||||||||||||
General and administrative | — | 431 | 105 | (1 | ) | 535 | ||||||||||||||
Restructuring and other termination costs | — | 5 | 2 | — | 7 | |||||||||||||||
Oil, natural gas and NGL depreciation, depletion and amortization | — | 2,353 | 154 | — | 2,507 | |||||||||||||||
Depreciation and amortization of other assets | — | 187 | 266 | (149 | ) | 304 | ||||||||||||||
Impairment of oil and natural gas properties | — | 3,192 | 123 | — | 3,315 | |||||||||||||||
Impairments of fixed assets and other | — | 275 | 65 | — | 340 | |||||||||||||||
Net gains (losses) on sales of fixed assets | — | (269 | ) | 2 | — | (267 | ) | |||||||||||||
Total Operating Expenses | — | 13,132 | 1,960 | (1,082 | ) | 14,010 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS | — | (1,840 | ) | 156 | (10 | ) | (1,694 | ) | ||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
Interest expense | (879 | ) | 45 | (84 | ) | 841 | (77 | ) | ||||||||||||
Losses on investments | — | (167 | ) | 55 | 9 | (103 | ) | |||||||||||||
Net gain on sales of investments | — | 29 | 1,063 | — | 1,092 | |||||||||||||||
Losses on purchases of debt | (200 | ) | — | — | — | (200 | ) | |||||||||||||
Other income (loss) | 819 | 203 | 14 | (1,028 | ) | 8 | ||||||||||||||
Equity in net earnings (losses) of subsidiary | (610 | ) | 436 | — | 174 | — | ||||||||||||||
Total Other Income (Expense) | (870 | ) | 546 | 1,048 | (4 | ) | 720 | |||||||||||||
INCOME (LOSS) BEFORE INCOME TAXES | (870 | ) | (1,294 | ) | 1,204 | (14 | ) | (974 | ) | |||||||||||
INCOME TAX EXPENSE (BENEFIT) | (101 | ) | (675 | ) | 470 | (74 | ) | (380 | ) | |||||||||||
NET INCOME (LOSS) | (769 | ) | (619 | ) | 734 | 60 | (594 | ) | ||||||||||||
Net income attributable to noncontrolling interests | — | — | — | (175 | ) | (175 | ) | |||||||||||||
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE | (769 | ) | (619 | ) | 734 | (115 | ) | (769 | ) | |||||||||||
Other comprehensive income (loss) | 6 | (22 | ) | — | — | (16 | ) | |||||||||||||
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE | $ | (763 | ) | $ | (641 | ) | $ | 734 | $ | (115 | ) | $ | (785 | ) |
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | $ | — | $ | 4,201 | $ | 462 | $ | (29 | ) | $ | 4,634 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
Drilling and completion costs | — | (4,445 | ) | (136 | ) | — | (4,581 | ) | ||||||||||||
Acquisitions of proved and unproved properties | — | (1,306 | ) | (5 | ) | — | (1,311 | ) | ||||||||||||
Proceeds from divestitures of proved and unproved properties | — | 5,812 | 1 | — | 5,813 | |||||||||||||||
Additions to other property and equipment | — | (480 | ) | (246 | ) | — | (726 | ) | ||||||||||||
Other investing activities | — | 1,199 | 60 | — | 1,259 | |||||||||||||||
Net Cash Provided By (Used In) Investing Activities | — | 780 | (326 | ) | — | 454 | ||||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
Proceeds from credit facilities borrowings | — | 6,689 | 717 | — | 7,406 | |||||||||||||||
Payments on credit facilities borrowings | — | (6,689 | ) | (1,099 | ) | — | (7,788 | ) | ||||||||||||
Proceeds from issuance of senior notes, net of discount and offering costs | 2,966 | — | 494 | — | 3,460 | |||||||||||||||
Proceeds from issuance of term loans, net of discount and offering costs | — | — | 394 | — | 394 | |||||||||||||||
Cash paid to purchase debt | (3,362 | ) | — | — | — | (3,362 | ) | |||||||||||||
Other financing activities | (439 | ) | (1,278 | ) | (169 | ) | (41 | ) | (1,927 | ) | ||||||||||
Intercompany advances, net | 4,136 | (3,709 | ) | (427 | ) | — | — | |||||||||||||
Net Cash Provided By (Used In) Financing Activities | 3,301 | (4,987 | ) | (90 | ) | (41 | ) | (1,817 | ) | |||||||||||
Net increase (decrease) in cash and cash equivalents | 3,301 | (6 | ) | 46 | (70 | ) | 3,271 | |||||||||||||
Cash and cash equivalents, beginning of period | 799 | 8 | 38 | (8 | ) | 837 | ||||||||||||||
Cash and cash equivalents, end of period | $ | 4,100 | $ | 2 | $ | 84 | $ | (78 | ) | $ | 4,108 |
Parent | Guarantor Subsidiaries | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | $ | — | $ | 4,218 | $ | 439 | $ | (43 | ) | $ | 4,614 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
Drilling and completion costs | — | (4,838 | ) | (766 | ) | — | (5,604 | ) | ||||||||||||
Acquisitions of proved and unproved properties | — | (1,378 | ) | 346 | — | (1,032 | ) | |||||||||||||
Proceeds from divestitures of proved and unproved properties | — | 3,466 | 1 | — | 3,467 | |||||||||||||||
Additions to other property and equipment | — | (271 | ) | (701 | ) | — | (972 | ) | ||||||||||||
Other investing activities | — | 246 | 765 | 163 | 1,174 | |||||||||||||||
Net Cash Provided By (Used In) Investing Activities | — | (2,775 | ) | (355 | ) | 163 | (2,967 | ) | ||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
Proceeds from credit facilities borrowings | — | 6,452 | 1,217 | — | 7,669 | |||||||||||||||
Payments on credit facilities borrowings | — | (6,452 | ) | (1,230 | ) | — | (7,682 | ) | ||||||||||||
Proceeds from issuance of senior notes, net of discount and offering costs | 2,274 | — | — | — | 2,274 | |||||||||||||||
Cash paid to purchase debt | (2,141 | ) | — | — | — | (2,141 | ) | |||||||||||||
Proceeds from sales of noncontrolling interests | — | — | 6 | — | 6 | |||||||||||||||
Other financing activities | 1,819 | (2,897 | ) | (17 | ) | (128 | ) | (1,223 | ) | |||||||||||
Intercompany advances, net | (1,381 | ) | 1,462 | (81 | ) | — | — | |||||||||||||
Net Cash Provided By (Used In) Financing Activities | 571 | (1,435 | ) | (105 | ) | (128 | ) | (1,097 | ) | |||||||||||
Net increase (decrease) in cash and cash equivalents | 571 | 8 | (21 | ) | (8 | ) | 550 | |||||||||||||
Cash and cash equivalents, beginning of period | 228 | — | 59 | — | 287 | |||||||||||||||
Cash and cash equivalents, end of period | $ | 799 | $ | 8 | $ | 38 | $ | (8 | ) | $ | 837 |
Parent(a) | Guarantor Subsidiaries(a) | Non- Guarantor Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | $ | — | $ | 1,711 | $ | 1,182 | $ | (56 | ) | $ | 2,837 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
Drilling and completion costs | — | (8,605 | ) | (325 | ) | — | (8,930 | ) | ||||||||||||
Acquisitions of proved and unproved properties | — | (3,622 | ) | 461 | — | (3,161 | ) | |||||||||||||
Proceeds from divestitures of proved and unproved properties | — | 5,884 | — | — | 5,884 | |||||||||||||||
Additions to other property and equipment | — | (1,736 | ) | (915 | ) | — | (2,651 | ) | ||||||||||||
Other investing activities | — | 5,083 | (316 | ) | (893 | ) | 3,874 | |||||||||||||
Net Cash Used In Investing Activities | — | (2,996 | ) | (1,095 | ) | (893 | ) | (4,984 | ) | |||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
Proceeds from credit facilities borrowings | — | 18,930 | 1,388 | — | 20,318 | |||||||||||||||
Payments on credit facilities borrowings | — | (20,651 | ) | (999 | ) | — | (21,650 | ) | ||||||||||||
Proceeds from issuance of senior notes, net of discount and offering costs | 1,263 | — | — | — | 1,263 | |||||||||||||||
Proceeds from issuance of term loans, net of discount and offering costs | 5,722 | — | — | — | 5,722 | |||||||||||||||
Cash paid to purchase debt | (4,000 | ) | — | — | — | (4,000 | ) | |||||||||||||
Proceeds from sales of noncontrolling interests | — | 63 | 1,014 | — | 1,077 | |||||||||||||||
Other financing activities | (477 | ) | (299 | ) | (820 | ) | 949 | (647 | ) | |||||||||||
Intercompany advances, net | (2,282 | ) | 3,242 | (960 | ) | — | — | |||||||||||||
Net Cash Provided By (Used In) Financing Activities | 226 | 1,285 | (377 | ) | 949 | 2,083 | ||||||||||||||
Net increase (decrease) in cash and cash equivalents | 226 | — | (290 | ) | — | (64 | ) | |||||||||||||
Cash and cash equivalents, beginning of period | 2 | — | 349 | — | 351 | |||||||||||||||
Cash and cash equivalents, end of period | $ | 228 | $ | — | $ | 59 | $ | — | $ | 287 |
(a) | We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012, $228 million was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements. |
23. | Recently Issued Accounting Standards |
Quarters Ended | ||||||||||||||||
March 31, 2014 | June 30, 2014 | September 30, 2014 | December 31, 2014 | |||||||||||||
($ in millions except per share data) | ||||||||||||||||
Total revenues | $ | 5,046 | $ | 5,152 | $ | 5,703 | $ | 5,050 | ||||||||
Gross profit(a) | $ | 733 | $ | 610 | $ | 1,174 | $ | 960 | ||||||||
Net income attributable to Chesapeake | $ | 425 | $ | 191 | $ | 662 | $ | 639 | ||||||||
Net income available to common stockholders | $ | 375 | $ | 145 | $ | 169 | $ | 586 | ||||||||
Net earnings per common share: | ||||||||||||||||
Basic | $ | 0.57 | $ | 0.22 | $ | 0.26 | $ | 0.89 | ||||||||
Diluted | $ | 0.54 | $ | 0.22 | $ | 0.26 | $ | 0.81 |
Quarters Ended | ||||||||||||||||
March 31, 2013 | June 30, 2013 | September 30, 2013 | December 31, 2013 | |||||||||||||
($ in millions except per share data) | ||||||||||||||||
Total revenues | $ | 3,424 | $ | 4,675 | $ | 4,867 | $ | 4,541 | ||||||||
Gross profit(a) | $ | 217 | $ | 1,167 | $ | 436 | $ | 249 | ||||||||
Net income (loss) attributable to Chesapeake(b) | $ | 58 | $ | 580 | $ | 202 | $ | (116 | ) | |||||||
Net income (loss) available to common stockholders(b) | $ | 15 | $ | 458 | $ | 156 | $ | (159 | ) | |||||||
Net earnings (loss) per common share: | ||||||||||||||||
Basic | $ | 0.02 | $ | 0.70 | $ | 0.24 | $ | (0.24 | ) | |||||||
Diluted | $ | 0.02 | $ | 0.66 | $ | 0.24 | $ | (0.24 | ) |
(a) | Total revenue less operating expenses. |
(b) | Includes $123 million of losses on the extinguishment of other financing and $203 million of impairments of fixed assets and other for the quarter ended December 31, 2013. See Note 5 and Note 17 for further discussion. |
December 31, | ||||||||
2014 | 2013 | |||||||
($ in millions) | ||||||||
Oil and oil and natural gas properties: | ||||||||
Proved | $ | 58,594 | $ | 56,157 | ||||
Unproved | 9,788 | 12,013 | ||||||
Total | 68,382 | 68,170 | ||||||
Less accumulated depreciation, depletion and amortization | (38,238 | ) | (35,577 | ) | ||||
Net capitalized costs | $ | 30,144 | $ | 32,593 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Acquisition of Properties: | ||||||||||||
Proved properties | $ | 214 | $ | 22 | $ | 332 | ||||||
Unproved properties | 1,224 | 997 | 2,981 | |||||||||
Exploratory costs | 421 | 699 | 2,353 | |||||||||
Development costs | 4,204 | 4,888 | 6,733 | |||||||||
Costs incurred(a)(b) | $ | 6,063 | $ | 6,606 | $ | 12,399 |
(a) | Exploratory and development costs are net of $679 million, $884 million and $784 million in drilling and completion carries received from our joint venture partners during 2014, 2013 and 2012, respectively. |
(b) | Includes capitalized interest and asset retirement obligations as follows: |
Capitalized interest | $ | 604 | $ | 815 | $ | 976 | ||||||
Asset retirement obligations | $ | 39 | $ | 7 | $ | 32 |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Oil, natural gas and NGL sales | $ | 8,180 | $ | 7,052 | $ | 6,278 | ||||||
Oil, natural gas and NGL production expenses | (1,208 | ) | (1,159 | ) | (1,304 | ) | ||||||
Production taxes | (232 | ) | (229 | ) | (188 | ) | ||||||
Impairment of oil and natural gas properties | — | — | (3,315 | ) | ||||||||
Depletion and depreciation | (2,683 | ) | (2,589 | ) | (2,507 | ) | ||||||
Imputed income tax provision(a) | (1,485 | ) | (1,169 | ) | 404 | |||||||
Results of operations from oil, natural gas and NGL producing activities | $ | 2,572 | $ | 1,906 | $ | (632 | ) |
(a) | The imputed income tax provision is hypothetical (at the effective income tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable). |
December 31, | |||||||||
2014 | 2013 | 2012 | |||||||
Ryder Scott Company, L.P. | 54 | % | 51 | % | 44 | % | |||
PetroTechnical Services, Division of Schlumberger Technology Corporation | 25 | % | 30 | % | 24 | % | |||
Netherland, Sewell & Associates, Inc. | — | % | — | % | 21 | % |
Oil | Gas | NGL | Total | |||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | |||||||||
December 31, 2014 | ||||||||||||
Proved reserves, beginning of period | 423.8 | 11,734 | 299.0 | 2,678 | ||||||||
Extensions, discoveries and other additions | 108.6 | 1,567 | 78.2 | 448 | ||||||||
Revisions of previous estimates | (51.1 | ) | (129 | ) | 21.3 | (51 | ) | |||||
Production | (42.3 | ) | (1,095 | ) | (33.1 | ) | (258 | ) | ||||
Sale of reserves-in-place | (23.3 | ) | (1,421 | ) | (101.7 | ) | (362 | ) | ||||
Purchase of reserves-in-place | 5.1 | 36 | 2.6 | 14 | ||||||||
Proved reserves, end of period(a) | 420.8 | 10,692 | 266.3 | 2,469 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 201.3 | 8,584 | 177.1 | 1,809 | ||||||||
End of period | 229.3 | 8,615 | 198.5 | 1,864 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 222.5 | 3,150 | 121.9 | 869 | ||||||||
End of period(b) | 191.5 | 2,077 | 67.8 | 605 | ||||||||
Oil | Gas | NGL | Total | |||||||||
(mmbbl) | (bcf) | (mmbbl) | (mmboe) | |||||||||
December 31, 2013 | ||||||||||||
Proved reserves, beginning of period | 495.5 | 10,933 | 297.3 | 2,615 | ||||||||
Extensions, discoveries and other additions | 96.3 | 2,160 | 68.0 | 524 | ||||||||
Revisions of previous estimates | (61.1 | ) | 388 | (32.9 | ) | (30 | ) | |||||
Production | (41.1 | ) | (1,095 | ) | (20.9 | ) | (244 | ) | ||||
Sale of reserves-in-place | (66.4 | ) | (657 | ) | (13.1 | ) | (189 | ) | ||||
Purchase of reserves-in-place | 0.6 | 5 | 0.6 | 2 | ||||||||
Proved reserves, end of period(c) | 423.8 | 11,734 | 299.0 | 2,678 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 162.9 | 7,174 | 132.1 | 1,491 | ||||||||
End of period | 201.3 | 8,584 | 177.1 | 1,809 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 332.6 | 3,759 | 165.2 | 1,124 | ||||||||
End of period(b) | 222.5 | 3,150 | 121.9 | 869 | ||||||||
December 31, 2012 | ||||||||||||
Proved reserves, beginning of period | 291.6 | 15,515 | 253.9 | 3,132 | ||||||||
Extensions, discoveries and other additions | 374.0 | 3,317 | 139.4 | 1,065 | ||||||||
Revisions of previous estimates | (67.5 | ) | (6,080 | ) | (47.3 | ) | (1,127 | ) | ||||
Production | (31.3 | ) | (1,129 | ) | (17.6 | ) | (237 | ) | ||||
Sale of reserves-in-place | (75.5 | ) | (704 | ) | (31.7 | ) | (225 | ) | ||||
Purchase of reserves-in-place | 4.2 | 14 | 0.6 | 7 | ||||||||
Proved reserves, end of period(d) | 495.5 | 10,933 | 297.3 | 2,615 | ||||||||
Proved developed reserves: | ||||||||||||
Beginning of period | 124.0 | 8,578 | 130.6 | 1,684 | ||||||||
End of period | 162.9 | 7,174 | 132.1 | 1,491 | ||||||||
Proved undeveloped reserves: | ||||||||||||
Beginning of period | 167.6 | 6,937 | 123.3 | 1,447 | ||||||||
End of period(b) | 332.6 | 3,759 | 165.2 | 1,124 |
(a) | Includes 2 mmbbls of oil, 46 bcf of natural gas and 5 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbls of oil, 22 bcf of natural gas and 2 mmbbls of NGL of which are attributable to the noncontrolling interest holders. |
(b) | As of December 31, 2014, 2013 and 2012, there were no PUDs that had remained undeveloped for five years or more. |
(c) | Includes 2 mmbbls of oil, 61 bcf of natural gas and 6 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 1 mmbbls of oil, 30 bcf of natural gas and 3 mmbbls of NGL of which are attributable to the noncontrolling interest holders. |
(d) | Includes 4 mmbbls of oil, 91 bcf of natural gas and 9 mmbbls of NGL reserves owned by the Chesapeake Granite Wash Trust, 2 mmbbls of oil, 45 bcf of natural gas and 4 mmbbls of NGL of which are attributable to the noncontrolling interest holders. |
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
($ in millions) | |||||||||||||
Future cash inflows | $ | 72,557 | (a) | $ | 76,094 | (b) | $ | 73,754 | (c) | ||||
Future production costs | (17,036 | ) | (18,196 | ) | (18,809 | ) | |||||||
Future development costs | (7,556 | ) | (9,563 | ) | (12,656 | ) | |||||||
Future income tax provisions | (12,494 | ) | (12,196 | ) | (9,824 | ) | |||||||
Future net cash flows | 35,471 | 36,139 | 32,465 | ||||||||||
Less effect of a 10% discount factor | (18,338 | ) | (18,749 | ) | (17,799 | ) | |||||||
Standardized measure of discounted future net cash flows(d) | $ | 17,133 | $ | 17,390 | $ | 14,666 |
(a) | Calculated using prices of $94.98 per bbl of oil and $4.35 per mcf of natural gas, before field differentials. |
(b) | Calculated using prices of $96.82 per bbl of oil and $3.67 per mcf of natural gas, before field differentials. |
(c) | Calculated using prices of $94.84 per bbl of oil and $2.76 per mcf of natural gas, before field differentials. |
(d) | Excludes future cash inflows attributable to production volumes sold to VPP buyers and includes future cash outflows attributable to the costs of production. See Note 12. |
Years Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
($ in millions) | ||||||||||||
Standardized measure, beginning of period(a) | $ | 17,390 | $ | 14,666 | $ | 15,630 | ||||||
Sales of oil and natural gas produced, net of production costs(b) | (5,722 | ) | (5,535 | ) | (3,867 | ) | ||||||
Net changes in prices and production costs | (634 | ) | 2,021 | (2,720 | ) | |||||||
Extensions and discoveries, net of production and development costs | 5,156 | 6,008 | 11,115 | |||||||||
Changes in future development costs | 1,946 | 1,287 | 3,687 | |||||||||
Development costs incurred during the period that reduced future development costs | 1,178 | 1,582 | 1,046 | |||||||||
Revisions of previous quantity estimates | (715 | ) | (805 | ) | (8,699 | ) | ||||||
Purchase of reserves-in-place | 215 | 26 | 285 | |||||||||
Sales of reserves-in-place | (1,788 | ) | (1,976 | ) | (3,246 | ) | ||||||
Accretion of discount | 2,168 | 1,777 | 1,988 | |||||||||
Net change in income taxes | (593 | ) | (1,180 | ) | 1,142 | |||||||
Changes in production rates and other | (1,468 | ) | (481 | ) | (1,695 | ) | ||||||
Standardized measure, end of period(a)(c)(d) | $ | 17,133 | $ | 17,390 | $ | 14,666 |
(a) | The impact of cash flow hedges has not been included in any of the periods presented. |
(b) | Excluding gains (losses) on derivatives. |
(c) | Effect of noncontrolling interest of the Chesapeake Granite Wash Trust is immaterial. |
(d) | The standardized measure of discounted future net cash flows does not include estimated future cash inflows attributable to future production of VPP volumes sold and does include estimated future cash outflows attributable to the costs of future production of VPP volumes sold. |
ITEM 9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure |
ITEM 9A. | Controls and Procedures |
ITEM 9B. | Other Information |
ITEM 10. | Directors, Executive Officers and Corporate Governance |
ITEM 11. | Executive Compensation |
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
ITEM 13. | Certain Relationships and Related Transactions and Director Independence |
ITEM 14. | Principal Accountant Fees and Services |
(a) | The following financial statements, financial statement schedules and exhibits are filed as a part of this report: |
1. | Financial Statements. Chesapeake's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements. |
2. | Financial Statement Schedules. Schedule II is included in Item 8 of Part II of this report with our consolidated financial statements. No other financial statement schedules are applicable or required. |
3. | Exhibits. The exhibits listed below in the Index of Exhibits (following the signatures page) are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K. |
CHESAPEAKE ENERGY CORPORATION | |||
Date: February 27, 2015 | By: | /s/ ROBERT D. LAWLER | |
Robert D. Lawler | |||
President and Chief Executive Officer |
Signature | Capacity | Date | ||
/s/ ROBERT D. LAWLER | President and Chief Executive Officer (Principal Executive Officer) | February 27, 2015 | ||
Robert D. Lawler | ||||
/s/ DOMENIC J. DELL'OSSO, JR. | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 27, 2015 | ||
Domenic J. Dell'Osso, Jr. | ||||
/s/ MICHAEL A. JOHNSON | Senior Vice President - Accounting, Controller and Chief Accounting Officer (Principal Accounting Officer) | February 27, 2015 | ||
Michael A. Johnson | ||||
/s/ ARCHIE W. DUNHAM | Chairman of the Board | February 27, 2015 | ||
Archie W. Dunham | ||||
/s/ VINCENT J. INTRIERI | Director | February 27, 2015 | ||
Vincent J. Intrieri | ||||
/s/ JOHN J. LIPINSKI | Director | February 27, 2015 | ||
John J. Lipinski | ||||
/s/ R. BRAD MARTIN | Director | February 27, 2015 | ||
R. Brad Martin | ||||
/s/ MERRILL A. MILLER, JR. | Director | February 27, 2015 | ||
Merrill A. Miller, Jr. | ||||
/s/ FREDRIC M. POSES | Director | February 27, 2015 | ||
Frederic M. Poses | ||||
/s/ LOUIS A. RASPINO | Director | February 27, 2015 | ||
Louis A. Raspino | ||||
/s/ THOMAS L. RYAN | Director | February 27, 2015 | ||
Thomas L. Ryan |
Incorporated by Reference | ||||||||||||
Exhibit Number | Exhibit Description | Form | SEC File Number | Exhibit | Filing Date | Filed or Furnished Herewith | ||||||
2.1.1* | Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and Southwestern Energy Production Company dated October 14, 2014. | X | ||||||||||
2.1.2* | Amendment to Purchase and Sale Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014. | X | ||||||||||
2.1.3 | Settlement Agreement by and between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (formerly Southwestern Energy Production Company) dated December 22, 2014. | X | ||||||||||
3.1.1 | Chesapeake’s Restated Certificate of Incorporation. | 10-Q | 001-13726 | 3.1.1 | 8/6/2014 | |||||||
3.1.2 | Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005B), as amended. | 10-Q | 001-13726 | 3.1.4 | 11/10/2008 | |||||||
3.1.3 | Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock, as amended. | 10-Q | 001-13726 | 3.1. 6 | 8/11/2008 | |||||||
3.1.4 | Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock (Series A). | 8-K | 001-13726 | 3.2 | 5/20/2010 | |||||||
3.1.5 | Certificate of Designation of 5.75% Cumulative Non-Voting Convertible Preferred Stock, as amended. | 10-Q | 001-13726 | 3.1.5 | 8/9/2010 | |||||||
3.2 | Chesapeake’s Amended and Restated Bylaws. | 8-K | 001-13726 | 3.2 | 6/9/2014 | |||||||
4.1** | Indenture dated as of August 16, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.5% Senior Notes due 2017. | 8-K | 001-13726 | 4.1 | 8/16/2005 | |||||||
4.2** | Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 6.875% Senior Notes due 2020. | 8-K | 001-13726 | 4.12.1 | 11/15/2005 | |||||||
4.3** | Indenture dated as of November 8, 2005 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.75% Contingent Convertible Senior Notes due 2035. | 8-K | 001-13726 | 4.12.2 | 11/15/2005 | |||||||
4.4** | Indenture dated as of December 6, 2006 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, The Bank of New York Mellon Trust Company, N.A., as Trustee, AIB/BNY Fund Management (Ireland) Limited, as Irish Paying Agent and Transfer Agent, and The Bank of New York, London Branch, as Registrar, Transfer Agent and Paying Agent, with respect to 6.25% Senior Notes due 2017. | 8-K | 001-13726 | 4.1 | 12/6/2006 | |||||||
4.5** | Indenture dated as of May 15, 2007 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.5% Contingent Convertible Senior Notes due 2037. | 8-K | 001-13726 | 4.1 | 5/15/2007 | |||||||
4.6** | Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 7.25% Senior Notes due 2018. | 8-K | 001-13726 | 4.1 | 5/29/2008 | |||||||
4.7** | Indenture dated as of May 27, 2008 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as Trustee, with respect to 2.25% Contingent Convertible Senior Notes due 2038. | 8-K | 001-13726 | 4.2 | 5/29/2008 | |||||||
4.8.1** | Indenture dated as of August 2, 2010 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and the Bank of New York Mellon Trust Company, N.A., as Trustee. | S-3 | 333-168509 | 4.1 | 8/3/2010 | |||||||
4.8.2 | First Supplemental Indenture dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.875% Senior Notes due 2018. | 8-A | 001-13726 | 4.2 | 9/24/2010 | |||||||
4.8.3 | Second Supplemental Indenture, dated as of August 17, 2010 to Indenture dated as of August 2, 2010 with respect to 6.625% Senior Notes due 2020. | 8-A | 001-13726 | 4.3 | 9/24/2010 | |||||||
4.8.4 | Fifth Supplemental Indenture dated February 11, 2011 to Indenture dated as of August 2, 2010 with respect to 6.125% Senior Notes due 2021. | 8-A | 001-13726 | 4.2 | 2/22/2011 | |||||||
4.8.5 | Fourteenth Supplemental Indenture dated March 18, 2013 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee, to Indenture dated as of August 2, 2010. | S-3 | 333-168509 | 4.17 | 3/18/2013 | |||||||
4.8.6 | Fifteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 3.25% Senior Notes due 2016. | 8-A | 001-13726 | 4.2 | 4/8/2013 | |||||||
4.8.7 | Sixteenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.375% Senior Notes due 2021. | 8-A | 001-13726 | 4.3 | 4/8/2013 | |||||||
4.8.8 | Seventeenth Supplemental Indenture dated April 1, 2013 to Indenture dated as of August 2, 2010 with respect to 5.75% Senior Notes due 2023. | 8-A | 001-13726 | 4.4 | 4/8/2013 | |||||||
4.9.1** | Indenture dated as of April 24, 2014 by and among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors, and Deutsche Bank Trust Company Americas, as Trustee. | 8-K | 001-13726 | 4.1 | 4/29/2014 | |||||||
4.9.2 | First Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24, 2014 with respect to Floating Rate Senior Notes due 2019. | 8-K | 001-13726 | 4.2 | 4/29/2014 | |||||||
4.9.3 | Second Supplemental Indenture dated as of April 24, 2014 to Indenture dated as of April 24 2014 with respect to 4.875% Senior Notes due 2022. | 8-K | 001-13726 | 4.3 | 4/29/2014 | |||||||
4.10** | Credit Agreement dated December 15, 2014 by and among: Chesapeake Energy Corporation, as borrower; MUFG Union Bank N.A., as administrative agent, co-syndication agent, a swingline lender and a letter of credit issuer; Wells Fargo Bank and National Association, as co-syndication agent, a swingline lender and a letter of credit issuer; Bank of America, N.A., Crédit Agricole Corporate and Investment Bank and JPMorgan Chase Bank, N.A., as co-documentation agents and letter of credit issuers; and certain other lenders named therein. | 8-K | 001-13726 | 10.1 | 12/16/2014 | |||||||
10.1.1† | Chesapeake's 2003 Stock Incentive Plan, as amended. | 10-Q | 001-13726 | 10.1.1 | 11/9/2009 | |||||||
10.1.2† | Form of 2013 Restricted Stock Award Agreement for Chesapeake's 2003 Stock Incentive Plan. | 10-K | 001-13726 | 10.1.3 | 3/1/2013 | |||||||
10.2† | Chesapeake's 2003 Stock Award Plan for Non-Employee Directors, as amended. | 10-Q | 001-13726 | 10.7 | 8/6/2013 | |||||||
10.3.1† | Chesapeake's 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.1 | 6/20/2013 | |||||||
10.3.2† | Form of 2013 Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.3 | 2/4/2013 | |||||||
10.3.3† | Form of Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.1 | 2/4/2013 | |||||||
10.3.4† | Form of Retention Nonqualified Stock Option Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 8-K | 001-13726 | 10.2 | 2/4/2013 | |||||||
10.3.5† | Form of 2013 Non-Employee Director Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.13.7 | 3/1/2013 | |||||||
10.3.6† | Form of 2013 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.13.9 | 3/1/2013 | |||||||
10.3.7† | Form of 2014 Performance Share Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-K | 001-13726 | 10.4.7 | 2/26/2014 | |||||||
10.3.8† | Form of Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-Q | 001-13726 | 10.8 | 8/6/2013 | |||||||
10.3.9† | Form of Non-Employee Director Restricted Stock Unit Award Agreement for 2005 Amended and Restated Long Term Incentive Plan. | 10-Q | 001-13726 | 10.9 | 8/6/2013 | |||||||
10.3.10† | Form of Pension and Equity Makeup Restricted Stock Award Agreement for 2005 Amended and Restated Long Term Incentive Plan for Robert D. Lawler. | 10-Q | 001-13726 | 10.10 | 8/6/2013 | |||||||
10.4† | Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan, as amended. | X | ||||||||||
10.5† | Chesapeake Energy Corporation Deferred Compensation Plan for Non-Employee Directors. | 10-K | 001-13726 | 10.16 | 3/13/2013 | |||||||
10.6† | Employment Agreement dated as of May 20, 2013 between Robert D. Lawler and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.1 | 5/23/2013 | |||||||
10.7† | Employment Agreement dated as of January 1, 2013 between Domenic J. Dell'Osso, Jr. and Chesapeake Energy Corporation. | 10-K | 001-13726 | 10.19 | 3/1/2013 | |||||||
10.8† | Employment Agreement dated as of January 1, 2013 between James R. Webb and Chesapeake Energy Corporation. | X | ||||||||||
10.9† | Employment Agreement dated as of August 14, 2013 between M. Christopher Doyle and Chesapeake Energy Corporation. | 10-Q/A | 001-13726 | 10.1 | 11/7/2013 | |||||||
10.10† | Employment Agreement dated as of August 4, 2013 between Mikell Jason Pigott and Chesapeake Energy Corporation. | 10-Q/A | 001-13726 | 10.2 | 11/7/2013 | |||||||
10.11† | Form of Employment Agreement dated as of January 1, 2013 between Executive Vice President/Senior Vice President and Chesapeake Energy Corporation. | 8-K | 001-13726 | 10.1 | 1/7/2013 | |||||||
10.12† | Form of Indemnity Agreement for officers and directors of Chesapeake Energy Corporation and its subsidiaries. | 8-K | 001-13726 | 10.3 | 6/27/2012 | |||||||
10.13† | Chesapeake Energy Corporation 2013 Annual Incentive Plan. | DEF 14A | 001-13726 | Exhibit G | 5/3/2013 | |||||||
10.14.1† | Chesapeake Energy Corporation 2014 Long Term Incentive Plan. | DEF 14A | 001-13726 | Exhibit F | 4/30/2014 | |||||||
10.14.2† | Form of Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.2 | 8/6/2014 | |||||||
10.14.3† | Form of Restricted Stock Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.3 | 8/6/2014 | |||||||
10.14.4† | Form of Nonqualified Stock Option Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.4 | 8/6/2014 | |||||||
10.14.5† | Form of Performance Share Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.5 | 8/6/2014 | |||||||
10.14.6† | Form of Director Restricted Stock Unit Award Agreement for 2014 Long Term Incentive Plan. | 10-Q | 001-13726 | 10.6 | 8/6/2014 | |||||||
12 | Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends. | X | ||||||||||
21 | Subsidiaries of Chesapeake Energy Corporation. | X | ||||||||||
23.1 | Consent of PricewaterhouseCoopers LLP. | X | ||||||||||
23.2 | Consent of PetroTechnical Services, Division of Schlumberger Technology Corporation. | X | ||||||||||
23.3 | Consent of Ryder Scott Company, L.P. | X | ||||||||||
31.1 | Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
31.2 | Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.1 | Robert D. Lawler, President and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
32.2 | Domenic J. Dell'Osso, Jr., Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | X | ||||||||||
99.1 | Report of PetroTechnical Services, Division of Schlumberger Technology Corporation. | X | ||||||||||
99.2 | Report of Ryder Scott Company, L.P. | X | ||||||||||
101 INS | XBRL Instance Document. | X | ||||||||||
101 SCH | XBRL Taxonomy Extension Schema Document. | X | ||||||||||
101 CAL | XBRL Taxonomy Extension Calculation Linkbase Document. | X | ||||||||||
101 DEF | XBRL Taxonomy Extension Definition Linkbase Document. | X | ||||||||||
101 LAB | XBRL Taxonomy Extension Labels Linkbase Document. | X | ||||||||||
101 PRE | XBRL Taxonomy Extension Presentation Linkbase Document. | X | ||||||||||
* | The Company agrees to furnish supplementally a copy of omitted exhibits and schedules to the Securities and Exchange Commission upon request. | |||||||||||
** | The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request. | |||||||||||
† | Management contract or compensatory plan or arrangement. |
1. | Definitions and References | 1 | |
1.1. | Definitions | 1 | |
1.2. | References; Construction | 18 | |
2. | Purchase and Sale; Purchase Price | 19 | |
2.1. | Title and Environmental Defects | 19 | |
2.2. | Preferential Purchase Rights; Required Consents | 24 | |
2.3. | Gas Imbalances | 26 | |
2.4. | Casualty Loss | 26 | |
2.5. | Certain Upward Adjustments | 26 | |
2.6. | Certain Downward Adjustments | 27 | |
2.7. | Closing Date Estimates | 27 | |
2.8. | Final Accounting | 28 | |
2.9. | Payments | 29 | |
2.10. | Administration of Unleased Accounts | 29 | |
2.11. | Tax Allocation | 30 | |
3. | Seller’s Representations and Warranties | 30 | |
3.1. | Organization and Good Standing. | 30 | |
3.2. | Legal Requirements | 30 | |
3.3. | No Breach | 30 | |
3.4. | Litigation | 31 | |
3.5. | Taxes | 31 | |
3.6. | Permits | 31 | |
3.7. | Compliance with Laws | 31 | |
3.8. | Contracts | 32 | |
3.9. | Environmental and Safety Matters | 33 | |
3.10. | Authority | 33 | |
3.11. | Broker’s or Finder’s Fees | 34 | |
3.12. | Bankruptcy | 34 | |
3.13. | Preferential Purchase Rights and Required Consents | 34 | |
3.14. | Gas Balancing | 34 | |
3.15. | Payment of Royalties and Expenses | 34 |
3.16. | Current Commitments | 34 | |
3.17. | Advance Payments | 34 | |
3.18. | Condemnation | 35 | |
3.19. | Payout Balances | 35 | |
3.20. | Compliance with Anti-Bribery Laws | 35 | |
4. | Buyer’s Representations and Warranties | 35 | |
4.1. | Organization and Good Standing. | 35 | |
4.2. | Powers | 35 | |
4.3. | No Restriction | 35 | |
4.4. | Authorization | 35 | |
4.5. | No Breach | 36 | |
4.6. | Governmental Consent | 36 | |
4.7. | Litigation | 36 | |
4.8. | Broker’s or Finder’s Fees | 36 | |
4.9. | Qualifications | 36 | |
4.10. | Bankruptcy | 36 | |
4.11. | Funding; Investment | 36 | |
4.12. | Compliance with Anti-Bribery Laws | 37 | |
5. | Covenants | 37 | |
5.1. | Access to Properties and Information | 37 | |
5.2. | Conduct of Business | 38 | |
5.3. | Revenues Held For Benefit of the Other Party | 40 | |
5.4. | Revenues and Expenses | 41 | |
5.5. | Suspended Funds | 41 | |
5.6. | HSR Act | 41 | |
5.7. | Governmental Bonds | 42 | |
5.8. | Gathering Agreements | 42 | |
5.9. | Limitations on Representations and Warranties | 45 | |
5.10. | Operatorship | 47 | |
5.11. | FERC Matters | 47 | |
5.12. | Satisfaction of Conditions | 48 | |
5.13. | Confidentiality | 48 | |
5.14. | Development Agreement | 48 |
5.15. | Selling Affiliates | 49 | |
6. | Buyer’s Conditions Precedent | 49 | |
7. | Seller’s Conditions Precedent | 50 | |
8. | The Closing | 51 | |
8.1. | Buyer’s Deliveries | 52 | |
8.2. | Seller’s Deliveries | 52 | |
8.3. | Post-Closing Adjustments | 54 | |
8.4. | Post-Closing Deliveries | 54 | |
8.5. | Costs | 54 | |
8.6. | Risk of Loss | 54 | |
9. | Press Releases | 54 | |
10. | Indemnification | 54 | |
10.1. | Assumed Obligations | 54 | |
10.2. | Seller’s Indemnification | 54 | |
10.3. | Buyer’s Indemnification | 55 | |
10.4. | EXTENT OF INDEMNIFICATION | 55 | |
10.5. | Indemnification Procedure | 56 | |
10.6. | Defense | 56 | |
10.7. | Certain Limitations on Indemnity Obligations | 57 | |
11. | Termination | 58 | |
11.1. | Right to Terminate | 58 | |
11.2. | Effect of Termination | 59 | |
12. | Default | 59 | |
13. | Arbitration | 59 | |
13.1. | Consolidation | 60 | |
13.2. | Initiation; Selection of Arbitrators | 60 | |
13.3. | Expenses | 60 | |
13.4. | Procedure | 60 | |
13.5. | Enforcement; Remedies | 61 | |
13.6. | Award of Fees | 61 | |
14. | Miscellaneous | 61 | |
14.1. | Time | 61 | |
14.2. | Notices | 61 |
14.3. | Survival | 62 | |
14.4. | Cooperation | 63 | |
14.5. | No Third Party Beneficiaries | 63 | |
14.6. | Cumulative Remedies | 63 | |
14.7. | Choice of Law | 63 | |
14.8. | Entire Agreement | 63 | |
14.9. | Assignment | 64 | |
14.10. | Amendment | 64 | |
14.11. | Severability | 64 | |
14.12. | Attorney Fees | 64 | |
14.13. | Waiver | 64 | |
14.14. | Counterparts; Facsimiles; Electronic Transmission | 64 | |
14.15. | JOINT ACKNOWLEDGMENT | 64 | |
14.16. | WAIVER OF JURY TRIAL, SPECIAL DAMAGES, ETC | 65 | |
14.17. | Mutuality | 65 | |
14.18. | Schedules | 65 | |
14.19. | 1031 Like-Kind Exchange | 65 | |
14.20. | Sharing of Certain Financial Information Subsequent to the Execution Date | 66 | |
14.21. | No Recourse to Financing Sources | 67 |
EXHIBITS | |
Exhibit A | Real Property Interests, Wells and Allocated Values |
Exhibit A-1 | Other Assets |
Exhibit A-2 | Transferred Gathering Systems |
Exhibit B-1 | Form of Assignment, Bill of Sale and Conveyance for certain Properties |
Exhibit B-2 | Forms of Assignment for Other Assets and Transferred Gathering Assets |
Exhibit C | Contracts |
Exhibit D | Consent Decree Agreement |
Exhibit E | Form of Fee Minerals Lease |
Exhibit F | Form of Non-Foreign Status Certificate |
Exhibit G | Form of Consent Letter |
SCHEDULES | |
Schedule 1.1 | Knowledge Persons |
Schedule 1.2 | Map of Contract Area and Utica Area |
Schedule 3.2 | Governmental Consents |
Schedule 3.3 | No Breaches |
Schedule 3.4 | Litigation |
Schedule 3.5 | Taxes |
Schedule 3.8 | Contracts |
Schedule 3.9 | Environmental and Safety Matters |
Schedule 3.13 | Preferential Purchase Rights and Required Consents |
Schedule 3.14 | Gas Balancing |
Schedule 3.16 | Current Commitments |
Schedule 3.17 | Advance Payments |
Schedule 3.19 | Payout Balances |
Schedule 5.8.1 | Buyer ATEX Volume |
Schedule 5.8.2 | Midstream Consent Contracts |
Schedule 5.11 | FERC Jurisdictional Contracts |
1.1. | Definitions. The following terms have the meanings given in this Section 1.1 or in the Section referred to below: |
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1.2. | References; Construction. All references in this Agreement to Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Sections, subsections or other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The |
PURCHASE AND SALE AGREEMENT | 18 |
2.1. | Title and Environmental Defects. The Purchase Price will be (a) decreased only for those uncured Title Defects and uncured Environmental Defects that are in excess of the respective Individual Defect Thresholds and the Aggregate Defect Threshold and (b) increased for Title Benefits, in each case, in accordance with this Section 2.1. The Buyer may deliver to the Seller, on or before the Defect Notice Date, one or more written notices specifying each defect associated with the Seller’s Properties that the Buyer asserts constitutes a Title Defect or an Environmental Defect, a specific description of each such Title Defect or Environmental Defect and the basis for such assertion under the terms of this Agreement, the amount of the adjustment to the Purchase Price that the Buyer asserts based on such Title Defect or Environmental Defect and its method of calculating such adjustment, together with all data and information reasonably necessary for the Seller to verify the existence of the alleged Title Defect or |
PURCHASE AND SALE AGREEMENT | 19 |
2.1.1 | No single Title Defect or Title Benefit shall be taken into account unless the value of such defect or benefit is determined to be more than (i) Twenty-Five Thousand Dollars ($25,000) with respect to any Well or (ii) Fifteen Thousand Dollars ($15,000) with respect to any Real Property Interest, and no single Environmental Defect shall be taken into account unless the value of such defect is determined to be more than Fifty Thousand Dollars ($50,000) (each an “Individual Defect Threshold”). |
2.1.2 | No adjustment will be made to the Purchase Price for either uncured Title Defects or for uncured Environmental Defects unless the total of all individual adjustments for such Title Defects and Environmental Defects that exceed the respective Individual Defect Thresholds exceeds one and one-tenth (1.1%) of the unadjusted Purchase Price in the aggregate (the “Aggregate Defect Threshold”) after first offsetting any Title Benefits. In the event that the total of all such individual adjustments for uncured Title Defects and uncured Environmental Defects exceeds the Aggregate Defect Threshold, the adjustment to the Purchase Price shall only be for the amount by which the total of all such individual adjustments for uncured Title Defects and uncured Environmental Defects exceeds the Aggregate Defect Threshold plus the total value of all individual adjustments for any Title Benefits. In no event will the aggregate amount of Title Defect adjustments with respect to a Property exceed the Allocated Value of such Property. With respect to any Title Defects or Environmental Defects for which an adjustment equal to the entire Allocated Value of the affected Property is made to the Purchase Price hereunder, at the Seller’s option, as a condition precedent to such adjustment, the Buyer will execute and deliver to the Seller an assignment (in substantially the same form as the Assignment) of such Property. |
PURCHASE AND SALE AGREEMENT | 20 |
2.1.3 | If the adjustment is based on the Seller owning an NRI in a Real Property Interest or Well which is less than that shown on Exhibit A, then the downward adjustment with respect to such Property shall be calculated by multiplying the Allocated Value shown for such Property on Exhibit A by a fraction, the numerator of which is an amount equal to the NRI shown for such Property on Exhibit A less the NRI to which the Seller is actually entitled taking such Title Defect into account, and the denominator of which is the NRI shown for such Property on Exhibit A. |
2.1.4 | If the adjustment is based on the Seller owning a Working Interest in a Well which is larger than the Working Interest shown for such Property on Exhibit A, but without a proportionate increase in the NRI for such Property, then the downward adjustment shall be calculated by determining the effective NRI that results from such larger Working Interest, determining what the NRI would be using such effective NRI and the Working Interest shown for such Property on Exhibit A and then calculating the adjustment in the manner set forth in Section 2.1.3. |
2.1.5 | If the adjustment is based on the Seller owning fewer Net Acres in a Real Property Interest than those shown for such Real Property Interest on Exhibit A, then the downward adjustment shall be calculated by multiplying the Allocated Value shown for such Property on Exhibit A by a fraction, the numerator of which is the number of Net Acres shown for such Property on Exhibit A minus the actual Net Acres actually owned in such Property, and the denominator of which is the number of Net Acres shown for such Property on Exhibit A. |
2.1.6 | If the adjustment is based on a Lien upon the Seller’s Real Property Interest or Well that is liquidated in amount, then the downward adjustment is the lesser of the amount necessary to remove such Lien from such Property or the Allocated Value of such Property. |
2.1.7 | If the adjustment is based on an Early Lease Expiration, then the downward adjustment shall be calculated by multiplying the Allocated Value shown for such Real Property Interest on Exhibit A by a fraction, (a) the numerator of which is (i) the lesser of 547 days and the number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A, minus (ii) the number of days within the period beginning on the Effective Time and ending on the actual expiration date of the Real Property Interest as set forth in the applicable lease, and (b) the denominator of which is the lesser of 547 days and number of days within the period beginning on the Effective Time and ending on the expiration date of the Real Property Interest as set forth on Exhibit A. Alternatively, if an adjustment is based on a Late Lease Expiration, then the upward adjustment shall be calculated by multiplying the Allocated Value shown for such Real Property Interest on Exhibit A by a fraction, (a) the numerator of which is (i) the lesser of |
PURCHASE AND SALE AGREEMENT | 21 |
2.1.8 | If the adjustment is based on a liability to remediate or otherwise cure an Environmental Defect related to a Real Property Interest, then the downward adjustment with respect to such Property is that portion of the amount necessary to implement and complete any remedial, removal, response, construction, closure, disposal or other corrective actions, or monitoring required under Environmental Laws to correct or remove such Environmental Defect in the most cost effective manner reasonably available and consistent with common industry practices for which the Buyer would be liable after Closing. |
2.1.9 | If the Seller determines that a Real Property Interest is subject to a Late Lease Expiration or that its ownership of (a) any Well entitles the Seller to a larger NRI or a smaller Working Interest (without a proportionately smaller NRI) than that shown for such Property on Exhibit A or (b) any Real Property Interest entitles the Seller to a larger NRI or a greater number of Net Acres than that shown for such Property on Exhibit A (each, a “Title Benefit”), then the Seller shall notify the Buyer of such Title Benefit in writing on or before the Defect Notice Date for Title Defects, which notice shall include a reasonably detailed description of such Title Benefit, the Dollar value that the Seller asserts is attributable to such Title Benefit and the Seller’s method of calculating such amount. The Seller shall be deemed to have conclusively waived any Title Benefits of which it fails to notify the Buyer in the manner and by the date specified in the preceding sentence. The upward adjustment to the Purchase Price in respect of each Title Benefit shall be determined using the same principles as provided in this Section 2.1 with respect to Title Defects. For the avoidance of doubt, a single matter shall be treated as a single Title Benefit even if affecting more than one Property. |
2.1.10 | If a Title Defect or an Environmental Defect is reasonably susceptible of being cured, then the Seller will have the right to cure such defect for a period of up to sixty (60) days after the respective Defect Notice Date (such period for Title Defects and such period for Environmental Defects, the respective “Cure Period”). The Buyer shall provide the Seller and its representatives access to the Properties and the Records after Closing in |
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2.1.11 | If after the respective Cure Period the Seller and the Buyer are not in agreement as to (a) whether a Defect Notice or notice of Title Benefit complies with the terms hereof, (b) the existence of or value attributable to a Title Defect, Title Benefit or Environmental Defect, (c) whether a Title Defect or Environmental Defect has been cured during the respective Cure Period, or (d) the amount of any adjustments to be made to the Purchase Price in respect of any uncured Title Defect, Title Benefit or uncured Environmental Defect, then the Seller and the Buyer will submit the dispute to arbitration as provided in this Section following written notice from one Party to the other Party on or before the date thirty (30) days after the end of the respective Cure Period that such Party is initiating dispute resolution in accordance with this Section, such notice to describe in reasonable detail the nature and specifics of the dispute. The Buyer, with respect to Environmental Defects, shall be deemed to have conclusively waived any unresolved Environmental Defect, or cure thereof, which is not submitted for resolution as provided in this Section on or before the date one hundred twenty (120) days after the end of the Cure Period applicable to Environmental Defects. The Buyer, with respect to Title Defects, and the Seller, with respect to Title Benefits, shall be deemed to have conclusively waived any unresolved Title Defect, or cure thereof, or any unresolved Title Benefit which is not submitted for resolution as provided in this Section on or before the date one hundred twenty (120) days after the end of the Cure Period applicable to Title Defects. The matter to be arbitrated shall be submitted to a title attorney licensed to practice in the state in which the applicable Property is located selected by the Seller and the Buyer, in the case of a Title Defect or Title Benefit, or to an environmental expert in the state in which the applicable Property is located selected by the Seller and the Buyer, in the case of an Environmental Defect (each such title attorney or environmental expert hereinafter, a “Consultant”). If the Seller and the Buyer are unable to agree on any Consultant within thirty (30) days after receipt of the initiating notice, then the Seller on the one hand and the Buyer on the other hand will each appoint one Consultant within ten (10) days thereafter and the two Consultants so appointed will appoint a third Consultant within ten (10) days after the second Consultant is appointed, and the three Consultants so appointed will resolve such matter. The cost of each Consultant shall be paid fifty percent (50%) by the Seller and fifty percent (50%) by the Buyer. The Seller and the Buyer shall each present to the Consultant(s), with a simultaneous copy to the other Party, a single written statement of its position on the defect or benefit in question, |
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2.1.12 | If the Parties have mutually agreed upon (or the Consultant(s) shall have finally determined) the amount of any Purchase Price adjustment required to be made pursuant to the terms of this Section 2.1 in respect of a Title Benefit or in respect of an Title Defect or Environmental Defect that the Seller have elected not to cure or that otherwise remains uncured after expiration of the respective Cure Period, in each case, (a) prior to the date the Closing Statement is initially delivered by the Seller to the Buyer pursuant to Section 2.7, then such amount will be included in the Purchase Price adjustments to be made at Closing in accordance with the Closing Statement, or (b) after the foregoing date but prior to the date the Final Statement is initially delivered by the Seller to the Buyer pursuant to Section 2.8, then such amount will be included in the Purchase Price adjustments to be made after Closing in accordance with the Final Statement, or (c) after both such dates, then such amount will be paid after the Closing in accordance with Section 2.9. |
2.2. | Preferential Purchase Rights; Required Consents. Within ten (10) Business Days (two (2) Business Days in the case of SUSA) after the Execution Date, the Seller shall provide any required notifications of a preferential purchase right, right of first refusal or other agreement which gives a Third Party a right to purchase a Real Property Interest or Well (or any part thereof) (“PPR”), requesting waivers thereof, in connection with the transactions contemplated hereby and otherwise in material compliance with the contractual provisions applicable to such PPR. Within ten (10) Business Days (two (2) Business Days in the case of SUSA) after the Execution Date, the Seller will send letters seeking (a) the SUSA consents, agreements and waivers described in Sections 6.4 and 7.5 and (b) all applicable Required Consents, excluding Customary Post-Closing Consents. The Seller will thereafter use commercially reasonable efforts (at no cost to the Seller) to ensure |
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2.2.1 | If, as of the Closing Date, (i) a holder of a PPR has notified the Seller that it elects to exercise its PPR with respect to the Properties (or portions thereof) to which its PPR applies (determined by and in accordance with the agreement under which the PPR arises), or (ii) no waiver, consent or exercise notice has been received by the Seller from the holder of a PPR but the time for exercising such PPR has not expired, then in each such case the Properties (or portions thereof) covered by the applicable PPR will not be sold to the Buyer (subject to the remaining provisions in this Section 2.2), and the Purchase Price will be reduced by the Allocated Value of the Properties (or portions thereof) subject to such PPR. If, as of the Closing Date, a holder of a Required Consent has not yet delivered such Required Consent, then the Properties (or portions thereof) covered by that Required Consent (i) will not be conveyed to the Buyer at Closing but shall still be considered part of the Properties in accordance with the provisions of Section 2.2.2, (ii) adjustments to the Purchase Price will still be made pursuant to Sections 2.5 and 2.6 with respect to such Property, and (iii) the Purchase Price will not be reduced as a result of such non-conveyance. |
2.2.2 | If Properties (or portions thereof) have been excluded from the Properties sold to the Buyer at the Closing (i) due to a pre-Closing exercise of a PPR, and if for any reason the purchase and sale of such Properties is not or cannot be consummated with the holder of such PPR that exercised such PPR and the Seller is thereby permitted to transfer such Properties (or portions thereof) to the Buyer pursuant to the terms of such PPR, or (ii) due to the Seller having not received a waiver, consent or exercise notice from the holder of a PPR and the time for exercising such PPR had not expired as of the Closing Date, and if the Seller subsequently receives such a waiver or consent, or if the Seller does not receive an exercise notice from the holder of the PPR with in the period for exercising such PPR, then in each such case the Seller shall so notify the Buyer and, within ten (10) Business Days after the Buyer’s receipt of such notice, the Seller shall sell, assign, and convey to the Buyer and the Buyer shall purchase and accept from the Seller such Properties pursuant to the terms of this Agreement and for the Allocated Value of such Properties, subject to adjustments in accordance with Sections 2.5 and 2.6. If Properties (or portions thereof) have been excluded from the Properties conveyed to the Buyer at the Closing due to the Seller having not received a Required Consent as of the Closing Date in accordance with Section 2.2.1, and if the Required Consent has been received or deemed received pursuant to the terms of the underlying agreement on or before the one (1) year anniversary of the Closing Date, then in each such case the Seller shall so notify the Buyer and, within ten (10) Business Days after the Buyer’s |
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2.2.3 | Properties excluded pursuant to this Section 2.2 will not be deemed to be affected by Title Defects or be subject to Section 2.1. |
2.3. | Gas Imbalances. The Purchase Price will be adjusted upward or downward, as applicable, by (a) the net mcf amount of the Seller’s aggregate wellhead gas imbalances as of the Effective Time multiplied by $2.75 per mcf (upward for underage and downward for overage); and (b) the mmbtu amount of any pipeline imbalances or unsatisfied throughput obligations attributable to the Seller or the Properties as of the Effective Time multiplied by $2.75 per mmbtu (upward for over deliveries and downward for under deliveries). |
2.4. | Casualty Loss. If, after the Execution Date but prior to the Closing Date, any portion of the Properties is damaged, destroyed or taken by condemnation or eminent domain or suffers a reduction in value as a result of a Casualty (a “Casualty Loss”), the Buyer will nevertheless be required to close and the Purchase Price will be adjusted in an amount equal to the lesser of (a) the Allocated Value of the Property affected by such Casualty Loss or (b) the amount of such Casualty Loss. |
2.5. | Certain Upward Adjustments. The Purchase Price shall be increased by the following (without duplication): (a) the value of all merchantable allowable oil or other liquid Hydrocarbons in storage above the pipeline connection at the Effective Time that is credited to the Properties in accordance with gauging and other customary industry procedures, such value to be the current market price at |
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2.6. | Certain Downward Adjustments. The Purchase Price shall be decreased by the following (without duplication): (a) the amount of any proceeds actually received by the Seller from the sale of Hydrocarbons produced from and after the Effective Time from the Properties (net of royalties and other burdens, and production, severance, sales, use and similar Taxes measured by or payable out of production; provided, that on oil the amount shall be the amount paid by the purchaser to the Seller) net of marketing fees; (b) the amount equal to all unpaid ad valorem, property, production, severance and similar Taxes (excluding income, capital gains, franchise or similar Taxes) based upon or measured by the ownership of the Properties or the production of Hydrocarbons therefrom or the receipt of proceeds attributable thereto, which accrue to or are chargeable against the Properties in accordance with GAAP prior to the Effective Time, which amount shall, to the extent not actually assessed or known, be computed based upon such Taxes for the immediately preceding calendar year, or, if such Taxes are assessed on other than a calendar year basis, for the Tax period last ended; (c) the amount of all unpaid costs and expenditures in connection with the ownership, operation and maintenance of the Properties (including rentals, overhead, royalties, prepayments, operating, drilling and completion costs and other charges and expenses billed under applicable operating agreements) attributable to periods prior to the Effective Time and that are subsequently paid by or on behalf of Buyer; (d) the amount of any proceeds of the type referenced in (a) attributable to periods after the Effective Time received by Seller on behalf of the unleased interests; (e) all expenses of the type referenced in (c) paid by or on behalf of the Buyer in connection with unleased interests and incurred prior to the Effective Time; and (f) any other amount agreed upon by the Buyer and the Seller, or otherwise required to be reflected pursuant to the other provisions of this Section 2. |
2.7. | Closing Date Estimates. On or before three (3) Business Days prior to the Closing Date, the Seller (with the cooperation of the Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to the Buyer a statement (the “Closing Statement”) setting forth each adjustment to the |
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2.8. | Final Accounting. On or before one hundred twenty (120) days after the Closing Date, the Seller (with the cooperation of the Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to the Buyer, a post-closing statement setting forth a detailed calculation of all final adjustments to the Purchase Price which takes into account all such adjustments provided in this Agreement (except as otherwise set forth in Section 2.1.12) (the “Final Statement”). If the Buyer disputes any items in or the accuracy and completeness of the Final Statement, then as soon as reasonably practicable, but in no event later than fifteen (15) days after its receipt of the Final Statement, the Buyer will deliver to the Seller a written exception report containing any changes the Buyer proposes to be made to the Final Statement. If the Buyer fails to deliver such exception report to the Seller within that period, the Final Statement as delivered by the Seller will be deemed to be true and correct, binding upon and not subject to dispute by any Party. If the Buyer delivers a timely exception report, as soon as reasonably practicable, but in no event later than thirty (30) days after the Seller receives the Buyer’s exception report, the Parties will meet and undertake to agree on the final post-Closing adjustments to the Purchase Price. If the Parties fail to agree on the final post-Closing adjustments within sixty (60) days after the Seller’s receipt of the Buyer’s exception report, any Party will be entitled to submit the dispute for resolution by the Accounting Referee. The cost of the Accounting Referee shall be paid fifty percent (50%) by the Seller and fifty percent (50%) by the Buyer. The Seller and the Buyer shall each present to the Accounting Referee, with a simultaneous copy to the other Party, a single written statement of its position on the dispute in question, together with a copy of this Agreement, the Closing Statement, the proposed Final Statement, and the Buyer’s written exception report and any supporting material that such Party desires to furnish, not later than ten (10) Business Days after appointment of the Accounting Referee. In making its determination, the Accounting Referee shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Party, may consider such other accounting and financial standards matters as in its opinion are necessary or appropriate to make a proper determination. The Parties shall direct the Accounting Referee to resolve the disputes within thirty (30) days after receipt of the written statements submitted for review and to render a decision in writing based upon such written statements. The Accounting Referee shall act as an expert for the limited purpose of determining the specific Final Statement dispute presented to it, shall not act as an arbitrator, shall not consider any other disputes or matters and may not award damages, interest, costs or penalties to either Party. In addition, the Accounting Referee shall agree in writing to keep strictly confidential the specifics and existence of such dispute as well as all proprietary records of the Parties reviewed by the Accounting Referee in the process of resolving such dispute. Upon agreement of the Parties to the adjustments to the |
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2.9. | Payments. Payments to be made following the Closing under this Section 2 shall be made (i) except as otherwise set forth in Section 2.1.12, within five (5) Business Days after the final determination is made that such payments are due and payable and (ii) by wire transfer of immediately available funds (pursuant to wire transfer instructions designated in advance by the receiving Party to the paying Party writing) for the account of the receiving Party. |
2.10. | Administration of Unleased Accounts. Until the date five (5) years after the Effective Time, the Seller shall retain all rights to the unleased owner joint interest billing account balances (the “Unleased A/R”) and unleased owner revenue account balances (the “Unleased Revenue”), as of the Effective Time (the Unleased A/R and the Unleased Revenue are collectively referred to herein as the “Unleased Accounts”). For a period of five (5) years following the Effective Time, the Seller shall retain the Unleased Accounts pursuant to this section, and the Seller shall be entitled to all proceeds recovered by the Buyer from unleased owners with Unleased A/R (up to the full Unleased A/R account balance for each such owner as of the Effective Time) as a result of any purchase of unleased property, mineral leasing or payment of a revised joint interest billing by any such Person (including Buyer) following a unit reduction. The Seller shall retain a copy of any decks related to the Unleased Accounts as of the Effective Time, and the Buyer agrees to provide the Seller quarterly updates regarding the Buyer’s purchase, leasing, unit reduction and revised joint interest billing activities affecting the Unleased Accounts. The Buyer further agrees to promptly deliver to the Seller all resulting proceeds on a quarterly basis. The Seller shall thereafter deliver to the Buyer corresponding Unleased Revenue that is then due to any Person (including Buyer) on account of payment by the Buyer to the Seller of such proceeds. Upon receipt of any Unleased Revenue, the Buyer shall assume all payment obligations relating to such Unleased Revenue and shall be liable for the payment thereof to the proper Persons. The Seller waives any and all rights to the Unleased A/R and Unleased Revenue from and after the five (5) year anniversary of the Effective Time, and at such time the Seller shall deliver all Unleased Revenue not previously delivered hereunder and supply all necessary data, and the Buyer shall assume all payment obligations and shall be responsible and liable for the payment thereof to the proper Persons. |
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2.11. | Tax Allocation. The Seller and the Buyer shall cooperate in the preparation of Internal Revenue Service Form 8594 to report the allocation of the Purchase Price among the Properties. The Buyer shall prepare and deliver to the Seller a draft Form 8594 within twenty (20) days after the determination of the Final Statement and any further adjustments to the Purchase Price relative to title or environmental issues pursuant to this Agreement. If the Seller disputes any items in the Buyer's draft Form 8594, then as soon as reasonably practicable, but in no event later than twenty (20) days after receipt of such draft Form 8594, the Seller will deliver to the Buyer a written exception report containing any changes the Seller proposes to be made to the Form 8594. The Parties agree to use reasonable efforts to reach an agreement on any and all disputed items in the draft Form 8594 within twenty (20) days after the later of the Seller’s receipt of the Buyer's draft Form 8594 or Buyer's receipt of any exceptions timely submitted by the Seller; provided, however, that if the Parties are unable to agree upon a final Form 8594, then the Parties agree to engage an Accounting Referee to resolve such dispute in accordance with the procedures set forth in Section 2.8 of this Agreement. |
3.1. | Organization and Good Standing. The Seller is duly formed, validly existing and in good standing under the laws of the State of its formation. Seller is duly qualified and/or licensed, as may be required, to do business as a foreign limited liability company or corporation, as applicable, in and is in good standing in the State of West Virginia and the Commonwealth of Pennsylvania. |
3.2. | Legal Requirements. The Seller has all requisite power and authority to own and operate its Properties as now being operated by the Seller and to carry on its business as now conducted. Except as set forth on Schedule 3.2, no consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of Seller in connection with the valid execution and delivery of the Transaction Documents or the consummation of transactions they contemplate, except the filing and other requirements of the HSR Act, if applicable, and any Customary Post-Closing Consents. |
3.3. | No Breach. Except as disclosed in Schedule 3.3, the execution, delivery, performance of the Transaction Documents and the consummation of the transactions they contemplate do not and will not: (a)(i) violate, conflict with or constitute a default or an event that, with notice or lapse of time or both, would be a default, breach, or violation under any term or provision of any governing document of the Seller or (ii) any instrument, agreement, contract, commitment, license, promissory note, indenture, mortgage, deed of trust, lease or other arrangement to which the Seller is a party or by which the Seller or its interest in any of the Properties is bound; (b) violate, conflict with or constitute a breach of any Law applicable to the Seller or by which the Seller or its interest in any of the Properties is bound; or (c) except with respect to Permitted Encumbrances, result in the creation, imposition or continuation of any Lien on or affecting the Seller’s |
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3.4. | Litigation. Except as disclosed in Schedule 3.4, (a) there are no Proceedings or arbitration proceedings pending or, to the Seller’s Knowledge, threatened in writing against the Seller or, to Seller’s Knowledge, for which Seller would be liable involving its interest in the Properties or, if applicable, the operation by the Seller thereof or questioning the validity of or seeking to prevent the consummation of this the Transaction Documents or any other action taken or to be taken in connection therewith, and (b) there are no Proceedings or investigations pending or, to the Seller’s Knowledge, threatened before or by any Governmental Authority involving its interest in the Properties or, if applicable, the operation by the Seller thereof or questioning the validity of or seeking to prevent the consummation of Transaction Documents or any other action taken or to be taken in connection therewith. To the Seller’s Knowledge, there exist no unsatisfied judgments of any Governmental Authority that would result in impairment or loss of the Seller’s interest in any part of the Properties. |
3.5. | Taxes. Except as disclosed in Schedule 3.5, to the Seller’s Knowledge, all Taxes based on or measured by the Seller’s ownership of property comprising its interest in the Properties or the production or removal of Hydrocarbons or the receipt of proceeds therefrom (including applicable escheatment requirements) have been timely paid when due and are not in arrears. The Seller is neither a “foreign person” within the meaning of Section 1445 of the Code nor a disregarded entity within the meaning of Section 1.1445-2(b)(2)(iii) of the United States Treasury Regulations promulgated under the Internal Revenue Code of 1986, as amended. |
3.6. | Permits. The Seller (a) has obtained all of its Permits, except where the absence of which, singly or in the aggregate, would not have a Material Adverse Effect, and (b) is not in violation with respect to or in default under, nor to the Seller’s Knowledge has it received any written notice from any Governmental Authority of any violation with respect to or any default under, any of its Permits that has not been (or will not be prior to Closing) corrected or settled, except where the violation or default would not have a Material Adverse Effect. |
3.7. | Compliance with Laws. During the period that the Seller or its Affiliates have operated any of the Properties and, to the Seller’s Knowledge, during the period any Third Party has operated any of the Properties, those Properties have been operated in compliance with the provisions and requirements of all applicable Laws (other than Environmental Laws), except for prior instances of non-compliance that have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters. |
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3.8. | Contracts. |
3.8.1 | Excluding the Development Agreement, joint operating agreements (except as otherwise set forth in subpart (i) below), and oil, gas and mineral leases, the Seller has listed in Schedule 3.8: (a) all farm-in, farm-out, exploration, development, participation, joint venture, partnership, area of mutual interest, purchase and/or acquisition Contracts, Contracts containing options to acquire any of the Properties, Contracts containing obligations not to compete, and any other similar Contracts, in the case of each of the foregoing, of which any terms remain executory which relate to or affect its interest in any of the Properties and which will be binding on the Buyer after Closing; (b) all material Hydrocarbon purchase and/or sale Contracts, gathering Contracts, processing Contracts, transportation Contracts, marketing Contracts, treating Contracts and all other similar material Contracts affecting its interest in any of the Properties which are not, by the terms thereof, subject to termination (without penalty) upon sixty (60) days or less notice; (c) all material water, sourcing, impoundment, storage, disposal or injection Contracts; (d) all production payments or net profits interests burdening its interest in any of the Properties; (e) all Contracts relating to the Properties that can reasonably be expected to result in aggregate payments by or revenues to the Seller of more than $200,000 during any calendar year; (f) all Contracts that constitute a lease under which the Seller is the lessor or the lessee of real or personal property, which lease cannot be terminated by the Seller without penalty upon thirty (30) days or less notice and involves an annual base rental of more than $200,000; (g) Contracts containing calls on production, if any; (h) all Contracts with any Affiliate of the Seller; (i) joint operating agreements that contain any of the contractual provisions expressly described in subparts (a), (b), (d), (g) or (h) above, and which provisions are not customary and generally considered unusual to be included within a joint operating agreement; and (j) all coal disturbance agreements or other agreements regarding the accommodation of coal mining operations or gas storage operations, in each case, which are not, by the terms thereof, subject to termination (without penalty) upon sixty (60) days or less notice (the Contracts required to be listed in Schedule 3.8, together with the Development Agreement but only if the Buyer partially assumes the Development Agreement as and only to the extent described in Sections 5.14, 6.4 and 7.5, collectively, the “Material Contracts”). |
3.8.2 | The Seller has made available or caused to be made available to Buyer true, correct and complete copies of the Material Contracts and all amendments thereto, but excluding a copy of the Development Agreement (except if and when a copy is required to be provided by Seller pursuant to Section 5.14). The Seller is not in default of any of its material obligations under any |
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3.9. | Environmental and Safety Matters. Insofar as it pertains to the Properties, except as set forth in Schedule 3.9: |
3.9.1 | During the period that the Seller has operated any of the Properties and, to the Seller’s Knowledge, during the period any other party operated any of the Properties, such Properties have been operated in material compliance with all applicable Environmental Laws and with the terms and conditions of all environmental Permits, except for prior instances of non-compliance that have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters. |
3.9.2 | There are no Proceedings relating to an alleged breach of Environmental Laws on or with respect to the Properties, and the Seller has not received any written notice of any environmental, health or safety claim, demand, filing, investigation, administrative proceeding, or other Proceeding relating to the Properties (an “Environmental Claim”) or notice of any alleged or actual violation or non-compliance with any Environmental Law or of non-compliance with the terms or conditions of any environmental permits, arising from, based upon, associated with or related to the Properties or the ownership or operation of any thereof. |
3.9.3 | During the period that the Seller has operated any of the Properties and, to the Seller’s Knowledge, during the period any other party operated any of the Properties, no pollutant, waste, contaminant or hazardous, extremely hazardous or toxic material, substance, chemical or waste identified, defined or regulated under any Environmental Law is present or has been handled, managed, stored, transported, processed, treated, disposed of, released, migrated or escaped on, in, from, under or in connection with the Properties or the ownership or operation of any thereof, such as to cause a condition or circumstance that would reasonably be expected to result in an Environmental Claim or a violation of an Environmental Law. |
3.10. | Authority. The Seller has taken all necessary action to authorize the execution, delivery and performance of the Transaction Documents to which it is a party and has adequate power, authority and legal right to enter into, execute, deliver and perform such Transaction Documents and to consummate the transactions they contemplate. This Agreement is, and upon delivery at the Closing as contemplated by this Agreement the other Transaction Documents will be, legal, |
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3.11. | Broker’s or Finder’s Fees. The Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by the Transaction Documents for which the Buyer will have any responsibility whatsoever. |
3.12. | Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or, to the Seller’s Knowledge, threatened against the Seller or any Affiliate of the Seller. |
3.13. | Preferential Purchase Rights and Required Consents. Except as set forth in Schedule 3.13, no interest of the Seller in a Property is subject to any preferential right of purchase, right of first refusal or other agreement which gives a Third Party the right to purchase any interest of the Seller in a Property or Required Consent of any Third Party to the sale and conveyance of the Seller’s interest in the Properties as provided for in this Agreement. |
3.14. | Gas Balancing. Except as set forth in Schedule 3.14, the Seller has no obligation to deliver gas (or cash in lieu thereof) from its interest in the Properties to other owners of interest as a result of past production by the Seller or its predecessors in excess of the share to which they are entitled, nor any right to receive deliveries of gas (or cash in lieu thereof) with respect to its interest in the Properties from other owners of interest as a result of past production by the Seller or its predecessors of less than the share to which they were entitled. |
3.15. | Payment of Royalties and Expenses. Except for such items that are being held in suspense as permitted pursuant to applicable Laws and the Unleased Revenue, the Seller has paid or caused to be paid all rentals, delay rentals, shut-in royalties, royalties, overriding royalties and other burdens upon, measured by or payable out of production, and other payments, in each case, due by the Seller under, with respect to or in connection with the ownership and/or operation of the Seller’s Properties or, if not paid, is contesting the same in good faith in the normal course of business. |
3.16. | Current Commitments. Except for the continuing operations and other matters set forth in Schedule 3.16, the Seller is not legally obligated for any future commitments requiring an expenditure by the Seller in excess of Two Hundred Thousand Dollars ($200,000.00) (net to the Seller’s interest) relating to any of the Properties. |
3.17. | Advance Payments. Except as set forth in Schedule 3.17, the Seller is not obligated by virtue of any take or pay payment, advance payment or other similar payment (other than gas balancing arrangements) to deliver Hydrocarbons, or |
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3.18. | Condemnation. The Seller has not received any written notice of any pending or threatened condemnation of any portion of its Properties. |
3.19. | Payout Balances. Schedule 3.19 contains a list, which is complete and accurate in all material respects, of the status of the Payout Balance, as of the Effective Time, for each Well in which the Seller has an interest. “Payout Balance” means the status, as of the dates of the calculations, of the recovery by the Seller or a third party of a cost amount specified in the contract relating to a well out of the revenue from such well where the net revenue interest of the Seller therein will be reduced or the working interest therein will be increased when such amount has been recovered. |
3.20. | Compliance with Anti-Bribery Laws. The Seller is not in violation of and no event has occurred or that would constitute a violation of any applicable State or Federal statute prohibiting bribery in any form. |
4.1. | Organization and Good Standing. The Buyer is duly formed, validly existing and in good standing under the laws of the State of Texas. The Buyer has the power and authority to acquire and own the Properties and to conduct business in the Commonwealth of Pennsylvania and the State of West Virginia. |
4.2. | Powers. The Buyer is duly authorized and empowered to execute, deliver and perform the Transaction Documents to which it is, or will be, a party and to consummate the transactions they contemplate. Neither the certificate of formation nor the bylaws of the Buyer, nor any other instrument to which the Buyer is a party or is bound, nor any court order or governmental law, rule or regulation, will be violated by the Buyer’s execution and consummation of the Transaction Documents. |
4.3. | No Restriction. The Buyer is not subject to any order, judgment or decree, or the subject of any litigation, claim or Proceeding, pending or threatened or any other restriction of any kind or character specific to the Buyer (other than restrictions imposed by the HSR, if applicable), which would affect the Buyer’s ability to carry out the transactions contemplated by the Transaction Documents. |
4.4. | Authorization. The Buyer has taken all necessary action to authorize the execution, delivery and performance of the Transaction Documents to which it is, or will be, a party and has adequate power, authority and legal right to enter into, execute, deliver and perform such Transaction Documents and to consummate the transactions they contemplate. This Agreement is, and upon delivery at the Closing as contemplated by this Agreement the other Transaction Documents will be, legal, valid and binding with respect to the Buyer and enforceable in |
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4.5. | No Breach. The execution, delivery, performance, and consummation of the Transaction Documents and the transactions they contemplate do not and will not: (a) violate any provision of any governing document of the Buyer; or (b) breach or violate, or result (with notice or lapse of time or both) in the breach, violation, acceleration or termination of, any contract, indenture, Lien, note, lease, agreement, license or Law to which the Buyer is subject or by which any of its assets are bound or subject, except, with respect to any such breach, violation, acceleration or termination which would not reasonably be expected to prevent the consummation of the transactions contemplated hereby by the Buyer or result in the Seller incurring any loss or liability therefrom. |
4.6. | Governmental Consent. No consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of the Buyer in connection with the valid execution and delivery of the Transaction Documents to which it is or will be a party or the consummation of transactions they contemplate, except the filing and other requirements of the HSR Act, if applicable, and any Customary Post-Closing Consents. |
4.7. | Litigation. There are no Proceedings pending or, to the Buyer’s Knowledge, threatened in writing against the Buyer questioning the validity of or seeking to prevent the consummation of the Transaction Documents or any other action taken or to be taken in connection herewith, or which would have a material adverse effect on the Buyer or its ability to consummate the transactions contemplated hereby. |
4.8. | Broker’s or Finder’s Fees. The Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by the Transaction Documents for which the Seller will have any responsibility whatsoever. |
4.9. | Qualifications. On the Closing Date the Buyer will be qualified with all applicable Governmental Authorities to own and operate the Properties. |
4.10. | Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or, to the Buyer’s Knowledge, threatened against the Buyer or any Affiliate of the Buyer. |
4.11. | Funding; Investment. On the Closing Date the Buyer will have available (through cash on hand or existing credit arrangements or otherwise) all of the funds necessary for the acquisition of all of the Properties pursuant to the Transaction Documents, as and when needed, and to perform its obligations thereunder. The Buyer is experienced in and knowledgeable about the oil and gas business and the acquisition of oil and gas properties and the Buyer is aware of the risks of such investments. The Buyer acknowledges that the Seller has not made any |
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4.12. | Compliance with Anti-Bribery Laws. The Buyer is not in violation of and no event has occurred or that would constitute a violation of any applicable State or Federal statute prohibiting bribery in any form. |
5.1. | Access to Properties and Information. Buyer will have the opportunity to conduct, prior to the Defect Notice Date and at its sole risk and expense, an environmental assessment of the Properties, including a Phase I assessment as that term is defined by the ASTM E1527-13 All Appropriate Inquiry Standard. Seller will provide reasonable access for this purpose to Properties operated by Seller. Notwithstanding anything herein to the contrary, Buyer shall not conduct any ASTM Phase II environmental review or any test drilling or sampling or other invasive activities without prior notice to and consent of Seller (which notice shall be sent at least fifteen (15) days prior to the Defect Notice Date, and which consent Seller may give or withhold in its sole discretion, and which consent will be considered denied by Seller if Seller fails to respond within five (5) Business Days after receiving such notice). Buyer shall provide Seller with a minimum of three (3) Business Days’ advance notice of its proposed environmental assessment activities prior to entering the Property to be assessed and Buyer shall (a) coordinate the conduct of such environmental assessment with Seller’s representatives, (b) not interfere with the normal operation of the Properties, and (c) comply with all applicable Laws and all requirements and safety policies of Seller and, if Seller is not the operator of the Properties, the operator of the Properties. If Buyer or any of its consultants, agents and representatives prepares an environmental assessment, Buyer will furnish a copy thereof to Seller upon request and (until and unless Closing occurs and Buyer purchases the relevant Properties) will keep (and cause its consultants, agents and representatives to keep) any and all such assessments and reports strictly confidential. In connection with the granting of such access, Buyer represents that it is adequately insured and, except to the extent caused by the gross negligence or willful misconduct of the Seller Indemnified Parties, Buyer waives, releases and agrees to defend and indemnify the Seller Indemnified Parties against any and all claims for injury to, or death of, persons or for damage to property arising in any way from the access afforded to Buyer hereunder or the activities of Buyer related to such access or any environmental assessment. This waiver, release and indemnity by Buyer shall survive termination of this Agreement. If Buyer conducts a Phase I assessment that indicates that a Phase II assessment as that term is defined by |
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5.2. | Conduct of Business. |
5.2.1 | From and after the Execution Date until Closing, the Seller will: |
(a) | to the extent the Seller operates any Properties, operate such Properties as a prudent operator in accordance with all Contracts and all applicable Laws in the Ordinary Course of Business; |
(b) | maintain its books of account and records relating to the Properties in the usual, regular and ordinary manner, in accordance with the usual accounting practices of the Seller and GAAP; |
(c) | pay, as they become due, that portion of the expenses related to the Properties that are attributable or allocated to the Seller’s interest in the Properties, except for amounts contested in good faith; |
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(d) | notify Buyer of any election that the Seller is required to make under any Contract, specifying the nature and time period associated with such election, and consult with the Buyer (and attempt in good faith to reach a mutually acceptable agreement with the Buyer regarding such election); |
(e) | notify Buyer, in a timely manner, of any Real Property Interest expirations or intention not to conduct any continuous drilling or other operations obligations that would result in any termination or expiration of any Real Property Interest prior to the Closing Date, and consult with the Buyer (and attempt in good faith to reach a mutually acceptable agreement with the Buyer regarding actions, if any, to be taken in connection therewith); and |
(f) | act in a reasonably prudent manner to maintain in full force and effect its Permits. |
5.2.2 | Except as provided in the Contracts, as required by Law or Permit, or as specifically contemplated by this Agreement, from and after the Execution Date until Closing, the Seller shall not: |
(a) | convey, encumber (except for Permitted Encumbrances), abandon or otherwise dispose of any part of the Properties, other than: (i) the sale of Hydrocarbons or obsolete machinery and equipment in the Ordinary Course of Business, unless the Buyer shall otherwise consent in writing (such consent not to be unreasonably delayed, conditioned or withheld) or (ii) the assignment of interests to another joint working interest owner to the extent such assignments do not, individually or in the aggregate, reduce the Seller’s Net Revenue Interest or increase the Seller’s Working Interest (without at least a proportionate corresponding increase in the Seller’s Net Revenue Interest) in any Well or Real Property Interest or reduce the Seller’s Net Acres with respect to any Real Property Interest from that shown for the Seller on Exhibit A; |
(b) | except in emergencies, enter into any material agreement, contract or commitment which, if entered into prior to the Execution Date, would be required to be listed in a Schedule attached to this Agreement, or materially amend or change the terms of, or terminate, extend, violate, breach or default under any such agreement, contract or commitment, or waive any right thereunder, in each case, without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such agreement, contract or commitment); |
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(c) | enter into any transaction, the effect of which would be to reduce the Seller’s NRI in a Property from that shown on Exhibit A; provided, however, for clarity, this Section 5.2.2(c) shall not apply to any decision to become a non-consenting party in any operation proposed with respect to any of the Properties; |
(d) | become a non-consenting party in any operation proposed with respect to any of the Properties without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such election); |
(e) | relinquish voluntarily its position as operator with respect to any Property without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding the operatorship of such Property); |
(f) | except for those existing as of the Execution Date, encumber any Property of the Seller with any Required Consent or PPR in favor of any Third Party; or |
(g) | waive, compromise or settle any material claim involving the Properties without first consulting with the Buyer (and attempting in good faith to reach a mutually acceptable agreement with the Buyer regarding such claim). |
5.3. | Revenues Held For Benefit of the Other Party. In the event either (a) the Buyer receives production or other revenues attributable to any of the Properties for any |
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5.4. | Revenues and Expenses. For all purposes, including adjustments to the Purchase Price under Section 2 of this Agreement, the Seller and the Buyer will properly allocate revenues and expenses before and after the Effective Time and will make payments to each other to the extent necessary for such proper allocation. All expenses incurred in the operation of the Properties before the Effective Time will be borne by the Seller and all proceeds from the sale of Hydrocarbons produced from or attributable to the Properties prior to the Effective Time will be the property of the Seller, and all expenses incurred in the operation of the Properties after the Effective Time will be borne by the Buyer and all proceeds from the sale of Hydrocarbons produced from or attributable to the Properties after the Effective Time will be the property of the Buyer. Ad valorem Taxes, property Taxes and other similar obligations will be prorated between the Seller and the Buyer as of the Effective Time. |
5.5. | Suspended Funds. As part of the final accounting in connection with the Final Statement pursuant to Section 2.8, the Seller will deliver to the Buyer the Suspended Funds along with an “Excel” spreadsheet containing the owner name, owner number, social security or federal ID number, reason for suspense, and the amount of Suspended Funds payable for each entry, together with monthly line item production detail including gross and net volumes and deductions for all suspense entries. Upon receipt of such information, the Buyer shall administer all such accounts and assume all payment obligations relating to the Suspended Funds in accordance with all applicable Laws, and shall be liable for the payment thereof to the proper parties, except that the Seller will retain all responsibility and liability for (a) statutory penalties and interest, if any, owing to any interest owner attributable to the Suspended Funds accruing prior to the Effective Time and (b) penalties and interest, if any, attributable to the Suspended Funds accruing prior to the Effective Time, payable to any state under existing escheat or unclaimed property statutes. If any such penalties or interest are due to the respective suspense account owner or any state under such statutes and the Seller fails to promptly reimburse such sums to the Buyer, then the Buyer shall return to the Seller the Suspended Funds in such account that existed as of the Effective Time, and the Seller shall thereupon assume all obligations for the final payment and settlement of any such claims and accompanying Suspended Funds. |
5.6. | HSR Act. In the event the Parties determine that filings by the Parties are required under the HSR Act, within ten (10) days following the execution by the Buyer and the Seller of this Agreement, the Buyer and the Seller will each prepare and simultaneously file with the Department of Justice (“DOJ”) and Federal Trade Commission (“FTC”) the notification and report form required for the transactions contemplated by this Agreement by the HSR Act, and request early |
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5.7. | Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by Seller or its Affiliates with Governmental Authorities or other Third Parties and relating to the Properties will be transferred to Buyer. Prior to Closing, Buyer shall post all bonds and other security with all applicable Governmental Authorities (in each case meeting the requirements of such authorities) as are necessary for Buyer to own and operate the Properties. In addition, at or immediately following Closing, Buyer shall replace those bonds, letters of credit and guarantees of Seller or its Affiliates related to the Properties and of which Buyer has been notified by Seller at least ten (10) Business prior to Closing. Thereafter, if either Party identifies any additional bond, letter of credit or guarantee of Seller or its Affiliates related to any Properties and which has not been released, then such Party shall promptly notify the other Party and promptly thereafter Buyer shall replace such bond, letter of credit or guarantee. Promptly following request by Seller, Buyer shall deliver to Seller evidence of Buyer’s posting of the bonds, security, letters of credit and guarantees required to be posted or replaced by Buyer pursuant to this Section 5.7. |
5.8. | Gathering Agreements. |
5.8.1 | ATEX Agreement. The Buyer and the Seller will jointly contact Enterprise (defined below) to request Enterprise’s consent to the Seller partially assigning to the Buyer a portion of the Transportation Services Agreement dated November 17, 2011 (the “ATEX Agreement”), between Enterprise Liquids Pipeline LLC (as assigned to Enterprise TE Products Pipeline Company, LLC (“Enterprise”) and CEMI, and if Enterprise refuses to consent to such partial assignment of the ATEX Agreement to Buyer upon terms acceptable to both the Seller and the Buyer in each Party’s sole discretion, the ATEX Agreement will not be assigned to the Buyer, however, the Buyer will be responsible for the volume as detailed in Schedule 5.8.1 (the “Buyer ATEX Volume”) under the ATEX agreement as set forth below. If Enterprise refuses to consent to such partial assignment of the ATEX Agreement to Buyer upon terms |
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5.8.2 | Consents. Within seven (7) Business Days after the Execution Date, the Seller will send letters seeking consents to the assignment of the Contracts listed on Schedule 5.8.2 (“Midstream Consent Contracts”). The Seller and the Buyer will thereafter use commercially reasonable efforts (at no cost to the Seller) to obtain such consents. At or prior to Closing, the Buyer will use its commercially reasonable efforts to furnish to the Seller a written acknowledgement from the counterparty to each Midstream Consent Contract that (a) any required consent thereunder to assignment of such Midstream Consent Contract has been granted, (b) the Buyer meets the creditworthiness standard, if any, set forth in such Midstream Consent Contract, and (c) upon the Seller’s assignment of such Midstream Consent Contract to the Buyer, the Seller and/or CEMI, as applicable, will be released from all obligations under such Midstream Consent Contracts (with respect to each Midstream Consent Contract, the “Applicable Consent”). The Buyer agrees to supply such guaranties or other credit support necessary to replace the credit support provided by CEMI or its Affiliates or otherwise reasonably required by such counterparty to meet any such creditworthiness standard. If the Buyer is unable or otherwise |
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5.8.3 | Form of Assignment. Prior to Closing, the Seller and the Buyer will negotiate in good faith mutually acceptable forms of assignment, assumption and, as applicable, and consent and release agreements to effect, in accordance with the terms of this Agreement, the assignments to the Buyer at Closing of the Midstream Consent Contracts (subject to Section 5.8.2) and all other gathering Contracts set forth on Exhibit C (collectively, the “Midstream Agreements” and such assignment, assumption and consent agreements for the Midstream Agreements, collectively, the “Midstream Assignments”). Upon Closing, the Seller will assign (and cause CEMI to assign) its rights and obligations contained in the Midstream Agreements (subject to Section 5.8.2), and the Buyer will assume (and, upon delivery by the Seller of the Assignment, the Buyer shall be deemed to have assumed), and thereafter will be bound by and comply with and perform, all of the obligations of CEMI and the Seller contained in the assigned Midstream Agreements; in such each |
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5.9. | Limitations on Representations and Warranties. EXCEPT FOR THE EXPRESS AND SPECIFIC REPRESENTATIONS AND WARRANTIES OF THE SELLER IN THIS AGREEMENT (AS BROUGHT DOWN BY SELLER’S CERTIFICATE DELIVERED AT CLOSING), THE ASSIGNMENTS OR OTHER TRANSACTION DOCUMENTS (IF ANY) THAT CONTAIN REPRESENTATIONS AND WARRANTIES, THE BUYER ACKNOWLEDGES THAT THE SELLER HAS NOT MADE, AND THE SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, AND THE BUYER HEREBY EXPRESSLY WAIVES, ANY REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE IN ANY WAY RELATED TO THIS AGREEMENT, THE TRANSACTION DOCUMENTS, OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY, INCLUDING RELATING TO (a) PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION, OR THE QUALITY, QUANTITY OR VOLUME OF THE RESERVES OF HYDROCARBONS, IF ANY, ATTRIBUTABLE TO THE PROPERTIES OR THE SELLER’S INTEREST THEREIN, (b) THE ACCURACY, COMPLETENESS OR MATERIALITY OF ANY RECORDS, INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) NOW, HERETOFORE OR HEREAFTER FURNISHED TO THE BUYER BY OR ON BEHALF OF THE SELLER, AND (c) THE ENVIRONMENTAL OR OTHER CONDITION OF THE PROPERTIES. |
5.9.1 | EXCEPT FOR THE EXPRESS REPRESENTATIONS AND WARRANTIES OF THE SELLER IN THIS AGREEMENT (AS BROUGHT DOWN BY SELLER’S CERTIFICATE DELIVERED AT CLOSING), THE ASSIGNMENTS OR OTHER TRANSACTION DOCUMENTS (IF ANY) THAT CONTAIN REPRESENTATIONS AND WARRANTIES, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, THE SELLER EXPRESSLY DISCLAIMS AND NEGATES, AND THE BUYER HEREBY WAIVES, AS TO PERSONAL PROPERTY, EQUIPMENT, INVENTORY, MACHINERY AND FIXTURES CONSTITUTING A PART OF THE PROPERTIES (a) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (b) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (c) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (d) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, (e) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM |
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5.9.2 | THE SELLER AND THE BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION 5.9.3ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER. |
5.9.3 | THE BUYER ACKNOWLEDGES THAT THE PROPERTIES HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT, AND PRODUCTION OF OIL AND GAS AND THAT EQUIPMENT AND SITES INCLUDED IN THE PROPERTIES MAY CONTAIN ASBESTOS, NATURALLY OCCURRING RADIOACTIVE MATERIAL (“NORM”) OR OTHER HAZARDOUS SUBSTANCES. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS, AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS, AND EQUIPMENT LOCATED ON THE PROPERTIES OR INCLUDED IN THE PROPERTIES MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES. NORM CONTAINING MATERIAL AND/OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING AIR, WATER, SOILS OR SEDIMENT. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION, OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE PROPERTIES. NOTHING CONTAINED IN THIS SECTION 5.9.3 WILL LIMIT, RESTRICT OR OTHERWISE AFFECT THE BUYER’S RIGHTS TO RAISE ENVIRONMENTAL DEFECTS UNDER SECTION 2.1 OF THIS AGREEMENT. |
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5.10. | Operatorship. At Closing, the Seller shall send notices to co-owners of those Properties that the Seller (or any Affiliate of the Seller) currently operates indicating that the Seller (or such Affiliate) is resigning as operator, effective upon the Closing Date, and recommending that Buyer be elected successor operator. The Seller makes no representations or warranties to Buyer as to the transferability of operatorship of any Properties which the Seller (or its Affiliates) currently operate. Rights and obligations associated with operatorship of the Properties are governed by operating agreements or similar agreements and will be decided in accordance with the terms of such agreements. |
5.11. | FERC Matters. |
5.11.1 | The Buyer and the Seller and their Affiliates will cooperate in obtaining (a) waivers from the FERC of its capacity release regulations and any other applicable FERC regulations (the “FERC Waivers”), and (b) related approvals, including but not limited to securing any and all timely consents to transfer from interstate pipelines providing transportation service pursuant to the FERC Jurisdictional Contracts (the “Pipeline Waivers”), and (c) execution of all necessary documents, as may be reasonably necessary to facilitate the permanent transfer from the Seller and its Affiliates to the Buyer or its designee of those contracts set forth on Schedule 5.11 (or any renewals, extensions or replacements thereof) (collectively, the “FERC Jurisdictional Contracts”). Upon receipt of such FERC Waivers and any or all of the Pipeline Waivers, the Seller or its Affiliate will assign or release to the Buyer or its designee their interests in the FERC Jurisdictional Contracts, on rates, terms and conditions identical to those being paid by the Seller, their Affiliates or their designees prior to the contemplated transfer. |
5.11.2 | From and after the later of Closing or the commencement of services under any FERC Jurisdictional Contract, until the earlier of (a) the effective date of the transfer of each such FERC Jurisdictional Contract to the Buyer or its designee in accordance with this Section 5.11.1 or to a Third Party pursuant to Section 5.11.3, or (b) if such transfer of a FERC Jurisdictional Contract does not occur, termination of the applicable FERC Jurisdictional Contract; the Seller shall, or shall cause its Affiliates to purchase hydrocarbons produced from the Properties at a price equal to 100% of the weighted average sales price of the products marketed, including natural gas liquids, if applicable, less applicable transportation fees and expenses and a marketing fee equal to one and one-half percent (1½%). Seller will cause its parent, Chesapeake Energy Corporation, to provide Buyer with a performance guaranty of the obligations under such purchase arrangement . |
5.11.3 | In the event that the Parties are unable to obtain the FERC Waivers or the Pipeline Waivers, the Buyer may request at any time, and upon receipt of such request from the Buyer, the Seller shall, and shall cause their |
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5.12. | Satisfaction of Conditions. The Parties agree to use commercially reasonable efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement (including satisfaction, but not waiver, of the Closing conditions for which they are responsible or otherwise in control). |
5.13. | Confidentiality. From the Execution Date until Closing, unless this Agreement is terminated, the Seller shall maintain the Records (including, as applicable, any confidentiality thereof) as would a reasonably prudent owner and operator of oil and gas properties, subject to the requirements of the Real Property Interests and any other applicable contracts. Without limiting Seller’s obligations under Section 8.4, if Closing occurs, then for a period of one (1) year after the Closing Seller shall maintain in confidence those Records to the extent related to the Properties that are conveyed to Buyer. The foregoing obligations of confidentiality shall not apply to (a) any information that is or becomes generally available to the public through no fault of Seller, or that is or was communicated to Seller by a Third Party free of any obligation of confidence known to Seller, or (b) any Records to the extent related to any Property not conveyed to Buyer or to the extent related to any Retained Liabilities. Seller may disclose any information to the extent necessary and appropriate to company with applicable Law, or to attorneys of litigants or Governmental Authorities to comply with any obligation imposed on Seller or its Affiliates in connection with a proceeding in a court or other Governmental Authority of competent jurisdiction. |
5.14. | Development Agreement. If the conditions set forth in Sections 6.4(a), 6.4(b), 7.5(a) and 7.5(b) are satisfied, but SUSA does not agree in writing that the Properties to be assigned to the Buyer hereunder will, effective upon such |
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5.15. | Selling Affiliates. To the extent any of the Properties or any of the fee minerals described on Exhibit A under the heading Fee Mineral Lease are held by any Affiliates of Seller, then, subject to the other terms of this Agreement, Seller will cause such Affiliates (a) to transfer title to such Properties by an assignment substantially in the form of the Assignment or to deliver the corresponding Fee Mineral Lease, as applicable, to Buyer, in each case, at the Closing and (b) to comply with any other terms of this Agreement to the extent specifically pertaining to such Properties or Fee Mineral Leases. |
6.1 | (a) No preliminary or permanent injunction or other order will have been issued (and remain in force) by any Governmental Authority having appropriate jurisdiction preventing consummation of the transactions contemplated by the Transaction Documents, and (b) to the extent required to be obtained prior to Closing, the consents, approvals and other items on Schedule 3.2 shall have been obtained; |
6.2 | No Proceeding will have been commenced by any Third Party against any of the Seller, the Buyer or any of their respective Affiliates, associates, officers or directors seeking to restrain, enjoin, prevent or challenge the transactions contemplated by the Transaction Documents or seeking material damages arising from the transactions contemplated by the Transaction Documents; |
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6.3 | All representations and warranties of the Seller contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date); |
6.4 | The Seller shall provide written evidence to Buyer that (a) SUSA has unconditionally consented to the assignment of the Seller’s interests in the Properties to the Buyer pursuant to this Agreement by countersigning a form of consent letter substantially in the form of Exhibit G; (b) SUSA has waived its PPR under the Development Agreement or such PPR has otherwise expired in accordance with the terms of the Development Agreement; and (c) either (i) the Buyer shall have notified the Seller, pursuant to Section 5.14, that the Buyer is willing to assume and accept at Closing the DA Assumed Obligations or (ii) SUSA shall have agreed in writing that the Properties actually assigned to the Buyer hereunder will, effective upon such assignment, cease to be subject to the Development Agreement in any respect and will cease to be “Joint Interests” under the Development Agreement; |
6.5 | Consummation of the transactions contemplated under the terms of the Transaction Documents is not prevented from occurring by (and the required waiting period, if any, has expired under) the HSR Act and the rules and regulations of the FTC and the DOJ thereunder; and |
6.6 | The Seller will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in this Agreement to be performed or complied with by the Seller on or prior to the Closing Date. |
7.1 | (a) No preliminary or permanent injunction or other order will have been issued (and remain in force) by any Governmental Authority having appropriate jurisdiction preventing consummation of the transactions contemplated by the Transaction Documents, and (b) to the extent required to be obtained prior to Closing, the consents, approvals and other items on Schedule 3.2 shall have been obtained; |
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7.2 | No Proceeding will have been commenced by any Third Party against the Seller, the Buyer or any of their respective Affiliates, associates, officers or directors seeking to restrain, enjoin, prevent or challenge the transactions contemplated by the Transaction Documents or seeking material damages arising from the transactions contemplated by the Transaction Documents; |
7.3 | All representations and warranties of the Buyer contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date); |
7.4 | The Buyer will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in this Agreement to be performed or complied with by the Buyer on or prior to the Closing Date; |
7.5 | The Seller shall have received written evidence that is reasonably satisfactory to the Seller that (a) SUSA has unconditionally consented to the assignment of the Seller’s interests in the Properties to the Buyer pursuant to this Agreement by countersigning a form of consent letter substantially in the form of Exhibit G, and (b) SUSA has waived its PPR under the Development Agreement or such PPR has otherwise expired in accordance with the terms of the Development Agreement; and (c) either (i) the Buyer shall have notified the Seller, pursuant to Section 5.14, that the Buyer is willing to assume and accept at Closing the DA Assumed Obligations or (ii) SUSA shall have agreed in writing that the Properties actually assigned to the Buyer hereunder will, effective upon such assignment, cease to be subject to the Development Agreement in any respect and will cease to be “Joint Interests” under the Development Agreement; |
7.6 | If applicable, consummation of the transactions contemplated under the terms of the Transaction Documents is not prevented from occurring by (and the required waiting period, if any, has expired under) the HSR Act and the rules and regulations of the FTC and the DOJ thereunder; and |
7.7 | The Deposit shall have been made to the Seller in accordance with Section 2 |
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8.1. | Buyer’s Deliveries. At the Closing, and subject to the simultaneous performance by the Seller of its obligations under Section 8.2, the Buyer will execute and deliver or cause to be executed and delivered to the Seller the following items: |
8.1.1 | Purchase Price. The Purchase Price as directed in writing by the Seller (as adjusted pursuant to Section 2.7 and less the Deposit); |
8.1.2 | Buyer’s Certificate. A certificate dated as of the Closing Date executed by an authorized officer of Buyer certifying on behalf of Buyer that the conditions set forth in Section 7.3 and Section 7.4 have been satisfied; |
8.1.3 | Secretary’s Certificate. A certificate duly executed by Buyer’s secretary or assistant secretary, dated as of the Closing Date, (i) attaching and certifying complete and correct copies of (A) the certificate of formation of Buyer in effect as of the Closing and (B) the resolutions of the board of directors of Buyer authorizing the execution, delivery and performance by Buyer of the Transaction Documents to which it is a party and the transactions they contemplate and (ii) certifying on behalf of Buyer the incumbency of each officer of Buyer executing each of the Transaction Documents to which it is a party; |
8.1.4 | Closing Statement. An original counterpart of the Closing Statement signed on behalf of the Buyer; |
8.1.5 | Consent Decree Agreement. An original counterpart of the Consent Decree Agreement signed on behalf of the Buyer; |
8.1.6 | Fee Minerals Lease. An original counterpart of the Fee Minerals Lease(s) signed on behalf of Buyer; and |
8.1.7 | Additional Documents. Such additional documents customary in similar transactions as might be reasonably requested by the Seller and are reasonably required to consummate the transactions contemplated by this Agreement, including, without limitation, the written acknowledgements and the such consents or agreements as my be required to satisfy the Buyer’s obligations under Sections 5.8 and 5.11. |
8.2. | Seller’s Deliveries. At the Closing, and subject to the simultaneous performance by the Buyer of its obligations under Section 8.1, the Seller will execute and deliver or cause to be executed and delivered to the Buyer the following items: |
8.2.1 | Assignments. An original counterpart of the Assignment for each County in which its Real Property Interests or Wells are located, executed by an authorized officer of the Seller and covering all of the Seller’s interest in the Properties (other than the Other Assets, the Transferred Gathering Systems, the Fee Minerals Lease(s) and those Properties to be excluded in accordance with the terms hereof) in recordable form, and an original counterpart of an Assignment of the Other Assets and the Transferred |
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8.2.2 | State and Federal Assignments. The Seller shall execute, acknowledge and deliver assignments, on appropriate forms, of state and of federal Real Property Interests, if any, in sufficient counterparts for filing with the applicable Governmental Authority; |
8.2.3 | Non-Foreign Status Certificate. A non-foreign entity certificate, in substantially the form of Exhibit F attached hereto; |
8.2.4 | Seller’s Certificate. A certificate dated as of the Closing Date executed by an authorized officer of the Seller certifying on behalf of the Seller that the conditions set forth in Section 6.3 and Section 6.4 have been satisfied; |
8.2.5 | Secretary’s Certificate. A certificate duly executed by Seller’s secretary or assistant secretary, dated as of the Closing Date, (i) attaching and certifying complete and correct copies of (A) the certificate of formation of Seller in effect as of the Closing and (B) the resolutions of the board of directors or other governing body of Seller authorizing the execution, delivery and performance by Seller of the Transaction Documents to which it is a party and the transactions they contemplate and (ii) certifying on behalf of Seller the incumbency of each officer of Seller executing each of the Transaction Documents to which it is a party; |
8.2.6 | Closing Statement. An original counterpart of the Closing Statement signed on behalf of the Seller; |
8.2.7 | Letters in Lieu. Letters in lieu of division and transfer orders executed by it relating to such Properties in form reasonably acceptable to the Buyer to reflect the conveyance by the Seller contemplated hereby; |
8.2.8 | Change of Operator. With respect to any Wells operated by the Seller, counterparts of such documents as are required to transfer the regulatory authority to operate such Wells to Buyer; |
8.2.9 | Consent Decree Agreement. An original counterpart of the Consent Decree Agreement signed on behalf of the Seller; |
8.2.10 | G&G License. The G&G License executed by an authorized officer of the Seller. |
8.2.11 | Fee Minerals Lease. An original counterpart of the Fee Minerals Lease(s) signed on behalf of Seller; and |
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8.2.12 | Additional Documents. Such additional documents customary in similar transactions as might be reasonably requested by the Buyer and are reasonably required to consummate the transactions contemplated by this Agreement, including, without limitation, the written acknowledgements and such consents or agreements as my be required to satisfy the Seller’s obligations under Sections 5.8 and 5.11. |
8.3. | Post-Closing Adjustments. The Buyer and the Seller agree that the Purchase Price may be further adjusted after the Closing Date in accordance with the provisions of Section 2 of this Agreement. |
8.4. | Post-Closing Deliveries. The Seller shall deliver the Records to the Buyer promptly after Closing, but no later than forty-five (45) days after the Closing Date. |
8.5. | Costs. The Seller will pay its attorney fees and other expenses; and the Buyer will pay the Buyer’s attorney fees and other expenses including, without limitation, the recording costs for the Assignments and all taxes (including sales taxes and transfer taxes), duties, levies or other governmental charges imposed on the transfers of the Properties pursuant to the Transaction Documents. |
8.6. | Risk of Loss. As of the consummation of the Closing, beneficial ownership and the risk of loss of the Properties will pass from the Seller to the Buyer effective from and after the Effective Time. |
10.1. | Assumed Obligations. Upon the Closing, the Buyer shall assume all of the Assumed Obligations (and, upon delivery by the Seller of the Assignment, the Buyer shall be deemed to have assumed the Assumed Obligations). |
10.2. | Seller’s Indemnification. Upon the Closing, the Seller shall agree (and, upon the delivery of the Assignment to the Buyer, the Seller shall be deemed to have agreed) to pay, defend, indemnify, reimburse and hold harmless the Buyer, its Affiliates and their respective directors, officers, agents and employees (the |
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10.3. | Buyer’s Indemnification. Upon the Closing, the Buyer shall agree (and, upon the delivery by the Seller to the Buyer of the Assignment, the Buyer shall be deemed to have agreed) to pay, defend, indemnify, reimburse and hold harmless the Seller, its Affiliates and their respective directors, partners, members, managers, officers, agents and employees (the “Seller Indemnified Parties”) for, from and against any loss, damage, diminution in value, claim, liability, debt, obligation or expense (including interest, reasonable legal fees, and expenses of litigation and attorneys’ fees in enforcing this indemnity) incurred, suffered, paid by or resulting to any of the Seller Indemnified Parties and which results from, arises out of or in connection with, is based upon, or exists by reason of: (a) the breach of any representation or warranty of the Buyer set forth in this Agreement (as brought down by the Buyer’s certificate delivered at Closing); (b) or any failure by the Buyer to perform any of its covenants or obligations set forth in this Agreement which is not cured as provided in Section 12 of this Agreement; or (c) any of the Assumed Obligations (except matters which constitute “Assumed Obligations” but which arise out of a breach by the Seller of its covenants in Section 5.2 of this Agreement for which the Seller is required to indemnify the Buyer under Section 10.2(b) at the time notice of a claim related to such matter is first presented under this Agreement). |
10.4. | EXTENT OF INDEMNIFICATION. WITHOUT LIMITING OR ENLARGING THE SCOPE OF THE INDEMNIFICATION, DEFENSE AND ASSUMPTION PROVISIONS SET FORTH IN THIS AGREEMENT, TO THE FULLEST EXTENT PERMITTED BY LAW, AN INDEMNIFIED PERSON SHALL BE ENTITLED TO INDEMNIFICATION HEREUNDER IN ACCORDANCE WITH THE TERMS OF SECTIONS 10.2 OR 10.3, REGARDLESS OF WHETHER THE ACT, OCCURRENCE OR CIRCUMSTANCE GIVING RISE TO ANY SUCH INDEMNIFICATION OBLIGATION IS THE RESULT OF THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY, BREACH OF DUTY (STATUTORY OR OTHERWISE), OR OTHER FAULT OR VIOLATION OF ANY LAW OF OR BY ANY SUCH INDEMNIFIED PERSON, PROVIDED THAT NO SUCH |
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10.5. | Indemnification Procedure. If any indemnified party discovers or otherwise becomes aware of an indemnification claim arising under this Agreement, such party will give written notice to the indemnifying Party, specifying such claim, and may thereafter exercise any remedies available to such indemnified party under this Agreement; provided, however, the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby. Further, promptly after receipt by an indemnified party hereunder of written notice of the commencement of any action or proceeding with respect to which a claim for indemnification may be made against any indemnifying Party, the indemnified party will give written notice to the indemnifying Party of the commencement of such action; provided, however, the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby. |
10.6. | Defense. If any action is brought against an indemnified party by a Third Party with respect to a matter subject to indemnification under this Agreement, the indemnifying Party will be entitled to participate in and to assume the defense thereof to the extent that it may wish, and after notice from the indemnifying Party to such indemnified party of the indemnifying Party’s election to assume the defense thereof, the indemnifying Party shall not be liable to such indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof unless the indemnifying Party has failed to assume and diligently prosecute the defense of such claim. Notwithstanding any of the foregoing to the contrary, the indemnified party will be entitled to select its own counsel and assume the defense of any action brought against it if the indemnifying Party fails to assume or diligently prosecute such defense, the |
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10.7. | Certain Limitations on Indemnity Obligations. |
10.7.1 | No claim of the Buyer or the Buyer Indemnified Parties pursuant to Section 10.2(a) shall be made hereunder unless the amount of such claim exceeds an amount equal to Two Hundred Thousand Dollars ($200,000.00) (each an “Individual Claim”). No claim of the Buyer or the Buyer Indemnified Parties pursuant to Section 10.2(a) shall be made hereunder until the total of all Individual Claims exceeds one and one-tenth percent (1.1%) of the unadjusted Purchase Price (the “Basket”). If the total amount of all of the Buyer’s or the Buyer Indemnified Parties’ Individual Claims exceeds the Basket, then the Seller’s obligations under Section 10.2(a) shall be limited to the amount by which the aggregate amount of such Individual Claims exceeds the Basket. All of the representations and warranties set forth in this Agreement or any certificate that are qualified as to “material,” “materiality,” “material respects,” “material adverse effect,” “Material Adverse Effect” or words of similar import or effect shall be deemed to have been made without any such qualification solely for purposes of determining whether a claim exceeds the Individual Claim threshold or Basket or whether the Buyer is entitled to indemnification under Section 10.2(a) for a breach by the Seller of a representation or warranty contained in Section 3.6 (and, for the avoidance of doubt, not for purposes of determining whether a Closing condition has been satisfied or whether the Buyer is entitled to indemnification under Section 10.2(a) for a breach by the Seller of any other representation or warranty contained in Section 3). |
10.7.2 | In no event will the Seller’s aggregate liability under Section 10.2(a), other than claims for breaches of the representations and warranties made in Sections 3.1, 3.2, 3.3(a)(i), 3.10 and 3.11, exceed twenty percent (20%) of the unadjusted Purchase Price. |
10.7.3 | The amount of any indemnification provided under Section 10.2 or 10.3 shall be net of any corresponding insurance proceeds, from insurance |
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10.7.4 | Notwithstanding anything stated herein to the contrary: (a) neither Party will have any liability to the other Party or such other Party’s indemnified parties under this Section 10 with respect to any item for which an adjustment has already been made to the Purchase Price under the terms of this Agreement; and (b) the Seller will have no liability to the Buyer or the Buyer Indemnified Parties under this Section 10 for any matter (including any breach of a representation or warranty under Section 3) which constitutes a Title Defect or an Environmental Defect. Claims for Title Defects or Environmental Defects, whether or not resulting in a Purchase Price adjustment because the applicable Aggregate Defect Threshold is not exceeded, are not subject to the terms of this Section 10, may not be claimed under this Section 10, may not be included for purposes of determining whether the limitations set forth in this Section 10.7 have been met and may not be included in the Basket for purposes of the limitations set forth in this Section 10.7. |
10.7.5 | The Parties specifically agree that the Buyer will not have any right to pursue a claim under the special warranty of title in the Assignment with respect to any matters which existed on or before the Effective Time that were raised by the Buyer as a Title Defect under Section 2.1 of this Agreement. |
11.1. | Right to Terminate. Subject to Section 11.2, this Agreement may be terminated (except for the provisions referenced in Section 11.2) at any time prior to the consummation of the Closing upon the occurrence of any one or more of the following: (a) by mutual consent of the Seller and the Buyer; (b) by the Buyer, if the Seller has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section 6 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it will not be possible for such condition to be satisfied); provided, however, that in the case of a breach that is capable of being cured, the Seller shall have a period of ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section 11.1(b) shall not become effective unless the Seller fails to cure such breach prior to the end of such ten (10) day period; (c) by the Seller if the Buyer has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section 7 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it will not be possible for such condition to be satisfied); provided, however, that in the case of a breach that is capable of being cured, the Buyer shall have a period of ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section 11.1(c) shall not become effective unless the Buyer fails to cure such breach prior to the end of such ten (10) day period; (d) by the Seller or the Buyer |
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11.2. | Effect of Termination. In the event of termination, written notice thereof will be given to the other Party or Parties specifying the provision pursuant to which such termination is made. Except as specifically provided in Section 12, on the termination of this Agreement the Deposit will be refunded to the Buyer. If this Agreement is terminated in accordance with Section 11.1, the provisions contained in this Section 11.2 and in Sections 8.5, 9, 12, 13, 14.1, 14.2, 14.5 through 14.17, and such defined terms in Section 1 as may be required to give meaning to such sections, shall survive termination of this Agreement. No termination of this Agreement under Section 11 shall relieve any Party of liability for breach of this Agreement arising prior to such termination. |
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13.1. | Consolidation. If there is more than one (1) Arbitrable Dispute that involves the same facts and Parties as the facts and Parties with respect to which arbitration has been initiated pursuant to this Agreement, such disputes shall be consolidated into the first arbitration initiated pursuant to this Agreement. |
13.2. | Initiation; Selection of Arbitrators. Arbitration may be initiated by a Party (“Claimant”) serving written notice on the other Party (“Respondent”) that the Claimant has referred the Arbitrable Dispute to binding arbitration. Claimant’s notice initiating binding arbitration must describe in reasonable detail the nature of the Arbitrable Dispute and the facts and circumstances relating thereto and identify the arbitrator Claimant has appointed. Respondent shall respond to Claimant within thirty (30) days after receipt of Claimant’s notice, identifying the arbitrator Respondent has appointed. All arbitrators must be neutral parties who have never been officers, directors or employees of, or have performed material work for, any of the Parties or their Affiliates within the preceding five (5) year period. Arbitrators must have a formal education or training in the area of dispute resolution and must have not less than seven (7) years’ experience as a lawyer in the energy industry with experience in exploration and production issues. The two (2) arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed. If either the Respondent fails to name its Party-appointed arbitrator within the time permitted, or if the two arbitrators are unable to agree on a third arbitrator within thirty (30) days from the date the second arbitrator has been appointed, then the missing arbitrator(s) shall be selected by the AAA with due regard given to the selection criteria above and input from the Parties and other arbitrators. The AAA shall select the missing arbitrator(s) not later than ninety (90) days from initiation of arbitration. In the event the AAA should fail to select the third arbitrator within ninety (90) days from initiation of arbitration, then either Party may petition the Chief United States District Judge for the Northern District of Texas to select the third arbitrator. Such selection shall be consistent with the selection criteria above and with due regard given to input from the Parties and other arbitrators. |
13.3. | Expenses. Claimant and Respondent shall each pay one-half of the compensation and expenses of the AAA and the arbitrator(s). |
13.4. | Procedure. The hearing shall be conducted in Dallas, Texas and commence within sixty (60) days after the selection of the third arbitrator, unless delayed by order of the arbitrators. The hearing shall be based upon written position papers submitted by Claimant and Respondent within twenty (20) Business Days after the selection of the third arbitrator, stating such Party’s proposed resolution of the dispute. The Parties and the arbitrators shall proceed diligently and in good faith in order that the award may be made as promptly as possible. The arbitrators |
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13.5. | Enforcement; Remedies. A Party may, prior to the appointment of the third arbitrator, seek temporary injunctive relief from any court of competent jurisdiction, provided that the Party seeking such relief shall (if arbitration has not already been commenced) simultaneously commence arbitration. Such court-ordered relief shall not continue more than ten (10) days after the appointment of the arbitrators and in no event for longer than ninety (90) days. In order to prevent irreparable harm, the arbitrators shall have the power to grant temporary or permanent injunctive or other equitable relief. Except as provided in the Federal Arbitration Act, the decision of the arbitrators shall be binding on and non-appealable by the Parties. Each Party agrees that any arbitration award against it may be enforced in any court of competent jurisdiction and that any Party may authorize any such court to enter judgment on the arbitrators’ decisions. The arbitrators may not grant or award indirect, consequential, punitive or exemplary damages or damages for lost profits. |
13.6. | Award of Fees. In any action under this Agreement, the prevailing Party or Parties (or other indemnified Persons) shall be entitled to recover arbitration and court costs and attorneys’ fees in addition to any other relief to which such Party or Persons are entitled. |
14.1. | Time. Time is of the essence of this Agreement. |
14.2. | Notices. All notices and communications required or permitted under this Agreement shall be in writing addressed as indicated below, and any communication or delivery hereunder shall be deemed to have been duly delivered upon the earliest of: (a) actual receipt by the Party to be notified; (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, then the date shown as received on the return notice; (c) if by facsimile transmission, then upon confirmation by the recipient of receipt, provided that if such facsimile is received after 5:00 pm local time of such recipient, such facsimile will be deemed to have been received on the following Business Day; (d) if by email, then upon an affirmative reply by email by the intended recipient that such email was received, provided that if such email is received after 5:00 pm local time of such recipient, such email will be deemed to have been received on the following Business Day; or (e) if by Federal Express overnight delivery (or other reputable overnight |
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To the Seller: | Chesapeake Appalachia, L.L.C. 6100 North Western Avenue Oklahoma City, Oklahoma 73118 Attention: Mr. Douglas J. Jacobson Telephone: (405) 935-9233 Facsimile: (405) 849-9233 Email: doug.jacobson@chk.com |
With a copy to: | Commercial Law Group, P.C. 5520 North Francis Avenue Oklahoma City, Oklahoma 73118 Attention: Mr. Ray Lees Telephone: (405) 254-5725 Facsimile: (405) 232-5553 Email: rlees@clgroup.org |
To the Buyer: | Southwestern Energy Production Company 2350 N. Sam Houston Parkway East, Suite 125 Houston, Texas 77032 Attention: Jeff Sherrick Telephone: (281) 618-4002 Facsimile: (281) 618-3095 Email: jeff_sherrick@swn.com |
With a copy to: | Southwestern Energy Production Company 2350 N. Sam Houston Parkway East, Suite 125 Houston, Texas 77032 Attention: Associate General Counsel Telephone: (281) 618-4819 Facsimile: (281) 618-4820 Email: rick_ogle@swn.com |
14.3. | Survival. The representations and warranties of the Seller contained in this Agreement or in any certificate delivered in connection with this Agreement (other than the representations and warranties in Sections 3.1, 3.5, 3.10, 3.11, 4.1, 4.4 and 4.8), together with the indemnification rights with respect thereto, will survive the Closing Date for a period of twelve (12) months and shall thereafter be of no further force or effect (the “Expiration Date”); provided, however, any representation or warranty as to which a claim shall have been asserted prior to the Expiration Date shall survive until such claim and the indemnity with respect thereto are resolved. The representations and warranties in Sections 3.1, 3.5, |
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14.4. | Cooperation. Prior to termination of this Agreement and at all times following the consummation of this Agreement, the Parties agree to execute and deliver, or cause to be executed and delivered, such documents and do, or cause to be done, such other acts and things as might reasonably be requested by any Party to this Agreement to assure that the benefits of this Agreement are realized by the Parties. |
14.5. | No Third Party Beneficiaries. Except for the indemnification rights of the Seller Indemnified Parties and the Buyer Indemnified Parties under Section 10, nothing in this Agreement, express or implied, is intended to confer upon anyone, other than the Parties hereto and their respective successors and assigns, any rights or remedies under or by reason of this Agreement or to constitute any Person a third party beneficiary of this Agreement; provided, however that the Financing Sources are intended beneficiaries of, and shall be entitled to enforce, Sections 14.10, 14.21 and this Section 14.5. |
14.6. | Cumulative Remedies. Subject to the other provisions hereof, no failure on the part of any Party to this Agreement to exercise and no delay in exercising any right thereunder will operate as a waiver thereof, nor will any single or partial exercise by any Party hereto of any right hereunder preclude any other or further right of exercise thereof or the exercise of any other right. |
14.7. | Choice of Law. This Agreement will be interpreted, construed and enforced in accordance with the laws of the State of Texas, without giving effect to any rules or principles of conflicts of law that might otherwise refer to the laws of another jurisdiction. |
14.8. | Entire Agreement. The Transaction Documents constitute the entire agreement between the Parties with respect to the subject matter hereof and there are no agreements, understandings, warranties or representations except as set forth herein or therein. |
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14.9. | Assignment. No Party may assign such Party’s rights nor delegate such Party’s duties under this Agreement without the express written consent of the other Party to this Agreement. |
14.10. | Amendment. Neither this Agreement nor any of the provisions thereof can be changed, waived, discharged or terminated, except by an instrument in writing signed by the Party against whom enforcement of the change, waiver, discharge or termination is sought. The Parties agree that the provisions of Section 14.5, this Section 14.10 and Section 14.21 and the definitions of Financing, Financing Commitment, Financing Sources and Finance Related Parties shall not be amended in a manner adverse to the Financing Sources under the Financing Commitments without their prior written consent. |
14.11. | Severability. If any clause or provision of this Agreement is illegal, invalid or unenforceable under any present or future law, the remainder of this Agreement will not be affected thereby. It is the intention of the Parties that if any such provision is held to be illegal, invalid or unenforceable, there will be added in lieu thereof a provision as similar in terms to such provisions as is possible to make such provision legal, valid and enforceable. |
14.12. | Attorney Fees. If any Party institutes an action or proceeding against any other Party relating to the provisions of this Agreement, including arbitration, the Party to such action or proceeding which does not prevail will reimburse the prevailing Party therein for the reasonable expenses of attorneys’ fees and disbursements incurred by the prevailing Party. |
14.13. | Waiver. Waiver of performance of any obligation or term contained in this Agreement by any Party, or waiver by one Party of the other’s default hereunder will not operate as a waiver of performance of any other obligation or term of this Agreement or a future waiver of the same obligation or a waiver of any future default. |
14.14. | Counterparts; Facsimiles; Electronic Transmission. This Agreement may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one agreement. The execution and delivery of this Agreement by any Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which shall be binding upon all Parties. |
14.15. | JOINT ACKNOWLEDGMENT. THIS WRITTEN AGREEMENT REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. |
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14.16. | WAIVER OF JURY TRIAL, SPECIAL DAMAGES, ETC. EACH OF THE BUYER AND THE SELLER HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY AND IRREVOCABLY (a) WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY A JURY IN RESPECT OF ANY LITIGATION BASED HEREON, OR DIRECTLY OR INDIRECTLY AT ANY TIME ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY OR ASSOCIATED HEREWITH, (b) WAIVES, TO THE MAXIMUM EXTENT NOT PROHIBITED BY LAW, ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LITIGATION OR ARBITRATION ANY “SPECIAL DAMAGES,” AS DEFINED BELOW, AND (c) ACKNOWLEDGES THAT IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS CONTAINED IN THIS SECTION, IN EACH CASE IT BEING THE EXPRESS INTENT, UNDERSTANDING, AND AGREEMENT OF THE PARTIES THAT SUCH WAIVERS ARE TO BE GIVEN THE FULLEST EFFECT, NOTWITHSTANDING THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY PARTY. AS USED IN THIS SECTION, “SPECIAL DAMAGES” MEANS ALL SPECIAL, CONSEQUENTIAL, EXEMPLARY OR PUNITIVE DAMAGES (REGARDLESS OF HOW NAMED), BUT DOES NOT INCLUDE ANY PAYMENTS OR FUNDS WHICH ANY PARTY HERETO HAS EXPRESSLY PROMISED TO PAY OR DELIVER TO ANY OTHER PARTY HERETO OR ANY CLAIMS OF ANY THIRD PARTY FOR WHICH ONE PARTY HAS AGREED TO INDEMNIFY THE OTHER PARTY UNDER THIS AGREEMENT. |
14.17. | Mutuality. The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them. Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by any Party. |
14.18. | Schedules. The inclusion of any information (including dollar amounts) in any section of the disclosure Schedules hereto shall not be deemed to be an admission or acknowledgment by the Seller that such information is required to be listed on such Schedule or is material to or outside the Ordinary Course of Business of the Seller. The information contained in this Agreement, the Exhibits and the Schedules hereto is disclosed solely for purposes of this Agreement, and no information contained herein or therein shall be deemed to be an admission by any Party hereto to any Third Party of any matter whatsoever (including any violation of a legal requirement or breach of contract). |
14.19. | 1031 Like-Kind Exchange. The Seller and Buyer agree that the Seller or Buyer may elect to treat the acquisition or sale of the Properties as an exchange of like- |
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14.20. | Sharing of Certain Financial Information Subsequent to the Execution Date. After the Execution Date, the Seller shall give the Buyer (and/or any of its Affiliates) and its (and/or their, as applicable) representatives reasonable access during normal business hours to those Financial Records (as hereinafter defined), including data necessary for disclosures pursuant to ASC 805, ASC 932 or other requirements of GAAP or the Securities and Exchange Commission, necessary for the Buyer’s or its respective Affiliate’s preparation of financial statements and other financial data relating to the Properties that (a) is necessary to enable the Buyer to furnish the Financing Sources with such financial information regarding the historical performance of the Properties of the type customarily included, and required to be included, in the offering documentation reasonably requested by the Buyer and customary for public offerings of debt and equity securities or (b) may be required to be included in any current or future filing by the Buyer (and/or |
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14.20.1 | The Financial Statements data shall be prepared and audited or reviewed at the sole cost and expense of the Buyer. If requested in writing, the Seller shall execute and deliver to the external independent accounting firm that audits, reviews or assists the Buyer or its respective Affiliate in the preparation of the Financial Statements or such other independent accounting firm designated by the Buyer to provide such procedures (the “Audit Firm”), such representation letters, in form and substance customary for representation letters provided to external audit firms by management of the company whose financial statements are the subject of an audit or are the subject of a review pursuant to Public Company Accounting Oversight Board (PCAOB) AU Section 722 (Interim Financial Information), as may be reasonably requested by the Audit Firm, with respect to the Financial Statements, including, as requested, representations regarding internal accounting controls and disclosure controls. As used in this Section 14.20, the term “Financial Records” means all ledgers, books, data, files, and accounting and financial records (whether in physical or electronic form) in the possession of the Seller and its Affiliates, in each case, solely to the extent related to the Properties; provided, however, “Financial Records” does not include any records or information (a) that the Seller considers to be confidential and proprietary, or (b) that may be protected by an attorney-client privilege, or (c) that cannot be disclosed to the Buyer or its representatives as a result of confidentiality arrangements with third parties. |
14.20.2 | The obligations of the Seller under this Section 14.20 shall expire on the earlier of (a) termination of this Agreement or (b) ninety (90) days after the close of the 2014 fiscal year of the Seller unless a request with respect to Financial Statements has been made prior to such time, in which event the obligations of the Seller shall continue until the preparation of such Financial Statements has been completed. |
14.21. | No Recourse to Financing Sources. Notwithstanding any provision of this Agreement, the Seller agrees on its behalf and on behalf of its Affiliates that no Financing Source or Finance Related Parties under any Financing Commitment nor any other Financing Source shall have any liability or obligation to the Seller and its Affiliates relating to this Agreement or any of the transactions contemplated hereby (including the Financing), whether at law, in equity, in contract, in tort or otherwise, in each case, whether arising, in whole or in part, out of comparative, contributory or sole negligence by any Financing Source or any Finance Related Party. |
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SELLER: | ||||
CHESAPEAKE APPALACHIA, L.L.C., | ||||
an Oklahoma limited liability company | ||||
By: | /s/ Douglas J. Jacobson | |||
Douglas J. Jacobson, Executive Vice President |
BUYER: | ||||
SOUTHWESTERN ENERGY PRODUCTION COMPANY, | ||||
a Texas corporation | ||||
By: | /s/ Jeffrey B. Sherrick | |||
Jeffrey B. Sherrick, Executive Vice President, Corporate Development |
SELLER: | ||||
CHESAPEAKE APPALACHIA, L.L.C., | ||||
an Oklahoma limited liability company | ||||
By: | /s/ Douglas J. Jacobson | |||
Douglas J. Jacobson, Executive Vice President |
BUYER: | ||||
SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation | ||||
By: | /s/ Jeffrey B. Sherrick | |||
Jeffrey B. Sherrick, Executive Vice President, Corporate Development |
1. | Settlement. In exchange for the Seller’s agreement to: (a) waive and release all rights of the Seller to claim Title Benefits under the PSA, and (b) a downward adjustment to the Purchase Price in the amount of Four Hundred Million Dollars ($400,000,000.00), the Buyer hereby waives and releases: (i) with respect to any of the Properties, (A) all rights of the Buyer to make any claims for Environmental Defects or Title Defects or (B) with respect to the special warranty of title under the Assignments and Fee Mineral Leases, except to the extent specifically set forth below, (ii) any breaches of the covenants and agreements of Seller under Section 5.2.1(e) of the PSA, (iii) any breaches of any representations, warranties or covenants including Sections 3.8 and 5.2 as a result of the omission from Exhibit C or Schedule 3.8 of the PSA of that certain Amended and Restated Gas Gathering Contract and Novation dated effective as of July 1, 2012, by and among Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Seller and Appalachia Midstream Services, L.L.C., (iv) any breaches of any representations, warranties or covenants including Sections 3.8 and 5.2 as a result of the Seller failing to disclose the release of the Seller’s rights to Train 6 under that certain Second Amended and Restated Gas Processing Agreement dated April 24, 2012, by and between Markwest Liberty Midstream & Resources, L.L.C. and Chesapeake Energy Marketing, Inc. or otherwise relating to the Seller releasing the Seller’s rights to Train 6 under such Markwest agreement, and (v) any and all rights of the Buyer to claim indemnities under Section 10.2 of the PSA with respect to any of the matters set forth in subparts (i), (ii), (iii) and (iv) of this Section 1. The waiver and release with respect to the special warranty of title set forth in subpart (i)(B) above will not apply to claims made with respect to title to the Properties by any person claiming by, through or under the Seller with respect to actions by the Seller during the period from the Effective Time to the Closing Date. The Parties hereby agree that the Assignments and Fee Mineral Leases |
2. | Effective Date of Settlement. The Seller and the Buyer hereby acknowledge and agree that the terms of conditions of the settlement set forth in Section 1 of this Agreement will not be effective until such time as the Buyer, the Seller and SUSA have each executed and delivered that certain Consent and Confirmation attached as Exhibit G to the Amendment to the PSA dated December 22, 2014 between the Seller and the Buyer (the “Consent”). Upon the date of execution and delivery of the Consent (the “Effective Date”) by the Buyer, the Seller and SUSA, this Agreement and all of the terms and conditions set forth herein shall be effective and binding upon the Parties as of the Effective Date including, without limitation, the Seller’s waiver and release of any Title Benefits and agreement to adjust the Purchase Price under subparts (a) and (b) of Section 1 hereof and the waivers and releases of the Buyer under subparts (i), (ii), (iii), (iv) and (v) of Section 1 hereof. |
3. | Entire Agreement. This instrument constitutes the entire and complete understanding of the Parties hereto with respect to the subject matter hereof, constitutes their full and final settlement with respect to the matters set forth herein, and supersedes all prior agreements, arrangements and representations relating to the subject matter of this Agreement. |
4. | Representations and Acknowledgments. Each Party to this Agreement acknowledges that no representations, inducements, promises, understandings or agreements, oral or otherwise, have been made by the other Party, or anyone acting on behalf of the other Party, that are not embodied herein. Each Party has relied upon such advice as it has deemed necessary together with its own judgment, and enters into this Agreement of its own free will, to accomplish the mutual intent of the Parties hereto, and not based upon any representation, inducement, promise, understanding or assurance made by the other Party. Each Party represents and acknowledges that such Party has had the opportunity to seek the advice of any person necessary to fully evaluate this Agreement, including counsel, regarding the effect, implications and ramifications of the terms of this Agreement. |
5. | No Admissions. The Parties agree that nothing contained herein, and no actions taken by either Party hereto with regard to this Agreement, shall be construed as an admission by either Party of liability as to any of the matters settled. No action taken by either Party in effecting this Agreement may be used in any future or pending demand, administrative proceeding, litigation, or similar action involving the Parties, as an admission of liability in any respect. |
6. | No Third Party Beneficiaries. Nothing in this Agreement, express or implied, is intended to confer upon anyone, other than the Parties hereto and their respective successors and assigns, any rights or remedies under or by reason of this Agreement or to constitute any Person a third party beneficiary of this Agreement. |
7. | Counterparts; Facsimiles, Electronic Transmission. This Agreement may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one amendment. The execution and delivery of this Agreement by either Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which will be binding upon both Parties. |
8. | Construction. This Amendment will be interpreted, construed and enforced in accordance with the laws of the State of Texas. The provisions of Sections 13 and 14 of the PSA are incorporated herein, with any necessary modifications. |
9. | Mutuality. The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them. Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by either Party. |
10. | Binding Effect. This Agreement shall be binding upon and shall inure to the benefit of the Parties to this Agreement and their respective successors and assigns. |
BUYER: | ||||
SWN PRODUCTION COMPANY, LLC, a Texas limited liability company, formerly known as SOUTHWESTERN ENERGY PRODUCTION COMPANY, a Texas corporation | ||||
By: | /s/ Jeffrey B. Sherrick | |||
Jeffrey B. Sherrick, Executive Vice President, Corporate Development |
SELLER: | ||||
CHESAPEAKE APPALACHIA, L.L.C., | ||||
an Oklahoma limited liability company | ||||
By: | /s/ Douglas J. Jacobson | |||
Douglas J. Jacobson, Executive Vice President |
ARTICLE I | ||
Establishment and Purpose | 1 | |
ARTICLE II | ||
Definitions | 1 | |
ARTICLE III | ||
Eligibility and Participation | 10 | |
ARTICLE IV | ||
Deferrals | 10 | |
ARTICLE V | ||
Company Contributions | 14 | |
ARTICLE VI | ||
Benefits | 16 | |
ARTICLE VII | ||
Modifications to Payment Schedules | 21 | |
ARTICLE VIII | ||
Valuation of Account Balances; Investments | 22 | |
ARTICLE IX | ||
Administration | 23 | |
ARTICLE X | ||
Amendment and Termination | 25 | |
ARTICLE XI | ||
Informal Funding | 25 | |
ARTICLE XII | ||
Claims | 26 | |
ARTICLE XIII | ||
General Provisions | 32 | |
2.1 | Account. Account means a bookkeeping account maintained by the Committee to record the payment obligation of a Participating Employer to a Participant as determined under the terms of the Plan. The Committee may maintain an Account to record the total |
2.2 | Account Balance. Account Balance means, with respect to any Account, the total payment obligation owed to a Participant from such Account as of the most recent Valuation Date. |
2.3 | Adopting Employer. Adopting Employer means an Affiliate who, with the consent of the Committee, has adopted the Plan for the benefit of its eligible employees. |
2.4 | Affiliate. Affiliate means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c). |
2.5 | Beneficiary. Beneficiary means a natural person, estate, or trust designated by a Participant to receive payments to which a Beneficiary is entitled in accordance with provisions of the Plan. The Participant's spouse, if living, otherwise the Participant's estate, shall be the Beneficiary if: (i) the Participant has failed to properly designate a Beneficiary, or (ii) all designated Beneficiaries have predeceased the Participant. |
2.6 | Business Day. A Business Day is each day on which the New York Stock Exchange is open for business. |
2.7 | Change in Control. Change in Control, with respect to a Participating Employer that is organized as a corporation, occurs on the date on which any of the following events occur (i) a change in the ownership of the Participating Employer; (ii) a change in the effective control of the Participating Employer; (iii) a change in the ownership of a substantial portion of the assets of the Participating Employer. |
2.8 | Claimant. Claimant means a Participant or Beneficiary filing a claim under Article XII of this Plan. |
2.9 | Code. Code means the Internal Revenue Code of 1986, as amended from time to time. |
2.10 | Code Section 409A. Code Section 409A means section 409A of the Code, and regulations and other guidance issued by the Treasury Department and Internal Revenue Service thereunder. |
2.11 | Committee. Committee means the committee appointed by the Board of Directors of the Company (or the appropriate committee of such board) to administer the Plan. If no designation is made, the Chief Executive Officer of the Company or his delegate shall have and exercise the powers of the Committee. |
2.12 | Company. Company means Chesapeake Energy Corporation. |
2.13 | Company Contribution. Company Contribution means a credit by a Participating Employer to a Participant's Account(s) in accordance with the provisions of Article V of the Plan. Company Contributions are credited at the sole discretion of the Participating Employer and the fact that a Company Contribution is credited in one year shall not obligate the Participating Employer to continue to make such Company Contribution in subsequent years. Unless the context clearly indicates otherwise, a reference to Company Contribution shall include Earnings attributable to such contribution. |
2.14 | Company Stock. Company Stock means phantom shares of common stock issued by the Company. |
2.15 | Compensation. Compensation means a Participant's base salary, bonus, commission, Director fees, and such other cash or equity-based compensation (if any) identified by the Committee on Exhibit B attached hereto as Compensation that may be deferred under this Plan. Compensation shall not include any compensation that has been previously deferred under this Plan or any other arrangement subject to Code Section 409A. The types of deferrable Compensation identified on Exhibit B may be amended from time to time by the Committee without formal amendment of the Plan. |
2.16 | Compensation Deferral Agreement. Compensation Deferral Agreement means an agreement between a Participant and a Participating Employer that specifies (i) the amount of each component of Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV, and (ii) the Payment Schedule applicable to one or more Accounts. The Committee may permit different deferral amounts for each component of Compensation and may establish a minimum or maximum deferral amount for each such component. Unless otherwise specified by the Committee in the Compensation Deferral Agreement, Participants may defer up to 75% of their base salary and up to 100% of other types of Compensation for a Plan Year. A Compensation Deferral Agreement may also specify the investment allocation described in Section 8.4. |
2.17 | Death Benefit. Death Benefit means the benefit payable under the Plan to a Participant's Beneficiary(ies) upon the Participant's death as provided in Section 6.1 of the Plan. |
2.18 | Deferral. Deferral means a credit to a Participant's Account(s) that records that portion of the Participant's Compensation that the Participant has elected to defer to the Plan in accordance with the provisions of Article IV. Unless the context of the Plan clearly indicates otherwise, a reference to Deferrals includes Earnings attributable to such Deferrals. |
2.19 | Director. Director means a member of the Board of Directors of the Company. |
2.20 | Disability Benefit. Disability Benefit means the benefit payable under the Plan to a Participant in the event such Participant is determined to be Disabled. |
2.21 | Disabled. Disabled means that a Participant is, by reason of any medically-determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than twelve months, (i) unable to engage in any substantial gainful activity, or (ii) receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Participant's employer. The Committee shall determine whether a Participant is Disabled in accordance with Code Section 409A provided, however, that a Participant shall be deemed to be Disabled if determined to be totally disabled by the Social Security Administration or the Railroad Retirement Board. Notwithstanding anything to the contrary herein, Disability with respect to a Grandfathered Account means a physical or mental disability as a result of which, at least 180 days after commencement of such disability, the Participant is determined, by a physician selected by the Company and acceptable to the Participant or the Participant's legal representative, to be totally and permanently disabled. |
2.22 | Earnings. Earnings means a positive or negative adjustment to the value of an Account, based upon the allocation of the Account by the Participant among deemed investment options in accordance with Article VIII. |
2.23 | Effective Date. Effective Date means January 1, 2008. |
2.24 | Eligible Employee. Eligible Employee means, for a Plan Year, a member of a "select group of management or highly compensated employees" of a Participating Employer within the meaning of Sections 201(2), 30l(a)(3) and 401(a)(l) of ERISA, as determined by the Committee from time to time in its sole discretion, who has been designated by the Committee as eligible to participate in the Plan. The Committee may in its discretion establish criteria to use in determining which Employees are Eligible Employees, which criteria may include income level, period of employment, participation in other plans, or such other criteria as it may deem appropriate. Any criteria established may be described on an Exhibit A to the Plan, and such criteria can be amended from time to time without formal amendment of the Plan. |
2.25 | Employee. Employee means a common-law employee of an Employer. |
2.26 | Employer. Employer means, with respect to Employees it employs, the Company and each Affiliate. |
2.27 | ERISA. ERISA means the Employee Retirement Income Security Act of 1974, as amended from time to time. |
2.28 | Fiscal Year Compensation. Fiscal Year Compensation means Compensation earned during one or more consecutive fiscal years of a Participating Employer, all of which is paid after the last day of such fiscal year or years. |
2.29 | Grandfathered Account. Grandfathered Account means amounts deferred under the Prior Plans prior to January 1, 2005 that were vested as of December 31, 2004. |
2.30 | Participant. Participant means an Eligible Employee or a Director who has received notification of his or her eligibility to defer Compensation under the Plan under Section 3.1 and any other person with an Account Balance greater than zero, regardless of whether such individual continues to be an Eligible Employee or a Director. A Participant's continued participation in the Plan shall be governed by Section 3.2 of the Plan. |
2.31 | Participating Employer. Participating Employer means the Company and each Adopting Employer. |
2.32 | Payment Schedule. Payment Schedule means the date as of which payment of an Account under the Plan will commence and the form in which payment of such Account will be made. |
2.33 | Performance-Based Compensation. Performance-Based Compensation means Compensation where the amount of, or entitlement to, the Compensation is contingent on the satisfaction of pre-established organizational or individual performance criteria relating to a performance period of at least twelve consecutive months. Organizational or individual performance criteria are considered pre-established if established in writing by not later than ninety (90) days after the commencement of the period of service to which the criteria relate, provided that the outcome is substantially uncertain at the time the criteria are established. The determination of whether Compensation qualifies as "Performance-Based Compensation" will be made in accordance with Treas. Reg. Section 1.409A-l(e) and subsequent guidance. |
2.34 | Plan. Generally, the term Plan means the "Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan" as documented herein and as may be amended from time to time hereafter. However, to the extent permitted or required under Code Section 409A, the term Plan may in the appropriate context also mean a portion of the Plan that is treated as a single plan under Treas. Reg. Section 1.409A-l(c), or the Plan or portion of the Plan and any other nonqualified deferred compensation plan or portion thereof that is treated as a single plan under such section. |
2.35 | Plan Year. Plan Year means January 1 through December 31. |
2.36 | Qualified Plan. Qualified Plan means the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan. |
2.37 | Retirement. Retirement means a Participant's Separation from Service after attainment of age fifty-five (55) and completion often (10) Years of Service. |
2.38 | Retirement Benefit. Retirement Benefit means the benefit payable to a Participant under the Plan following the Retirement of the Participant. |
2.39 | Retirement/Termination Account. Retirement/Termination Account means an Account established by the Committee to record the amounts payable to a Participant that have not been allocated to a Specified Date Account. Unless the Participant has established a Specified Date Account, all Deferrals and Company Contributions shall be allocated to a Retirement/Termination Account on behalf of the Participant. |
2.40 | Separation from Service. An Employee incurs a Separation from Service upon termination of employment with the Employer. A Director incurs a Separation from Service upon the expiration of all contracts with the Employer, provided the contractual relationship has in good faith been completely terminated. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Code Section 409A. |
2.41 | Specified Date Account. A Specified Date Account means an Account established pursuant to Section 4.3 that will be paid (or that will commence to be paid) at a future date as specified in the Participant's Compensation Deferral Agreement. Unless otherwise determined by the Committee, a Participant may maintain no more than five (5) Specified Date Accounts. A Specified Date Account may be identified in enrollment materials as an "In-Service Account". |
2.42 | Specified Date Benefit. Specified Date Benefit means the benefit payable to a Participant under the Plan in accordance with Section 6.1(c). |
2.43 | Specified Employee. Specified Employee means an Employee who, as of the date of his Separation from Service, is a "key employee" of the Company or any Affiliate, any stock of which is actively traded on an established securities market or otherwise. An Employee is a key employee if he meets the requirements of Code Section 416(i)(l)(A)(i), (ii), or (iii) (applied in accordance with applicable regulations thereunder and without regard to Code Section 416(i)(5)) at any time during the 12-month period ending on the Specified Employee Identification Date. Such Employee shall be treated as a key employee for the entire 12-month period beginning on the Specified Employee Effective Date. |
2.44 | Specified Employee Identification Date. Specified Employee Identification Date means December 31, unless the Employer has elected a different date through action that is legally binding with respect to all nonqualified deferred compensation plans maintained by the Employer. |
2.45 | Specified Employee Effective Date. Specified Employee Effective Date means the first day of the fourth month following the Specified Employee Identification Date, or such earlier date as is selected by the Committee. |
2.46 | Substantial Risk of Forfeiture. Substantial Risk of Forfeiture shall have the meaning specified in Treas. Reg. Section 1.409A-l(d). |
2.47 | Termination Benefit. Termination Benefit means the benefit payable to a Participant under the Plan following the Participant's Separation from Service prior to Retirement. |
2.48 | Unforeseeable Emergency. An Unforeseeable Emergency means a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant's spouse, the Participant's dependent (as defined in Code section 152, without regard to section 152(b)(l), (b)(2), and (d)(l)(B)), or a Beneficiary; loss of the Participant's property due to casualty (including the need to rebuild a home following damage to a home not otherwise covered by insurance, for example, as a result of a natural disaster); or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The types of events which may qualify as an Unforeseeable Emergency may be limited by the Committee. |
2.49 | Valuation Date. Valuation Date shall mean each Business Day. |
2.50 | Year of Service. A Year of Service shall mean each 12-month period of continuous service with the Employer. |
3.1 | Eligibility and Participation. An Eligible Employee or a Director becomes a Participant upon the earlier to occur of (i) a credit of Company Contributions under Article V or (ii) receipt of notification of eligibility to participate. |
3.2 | Duration. A Participant shall be eligible to defer Compensation and receive allocations of Company Contributions, subject to the terms of the Plan, for as long as such Participant remains an Eligible Employee or a Director. A Participant who is no longer an Eligible Employee or a Director but has not Separated from Service may not defer Compensation under the Plan beyond the Plan Year in which he or she became ineligible but may otherwise exercise all of the rights of a Participant under the Plan with respect to his or her Account(s). On and after a Separation from Service, a Participant shall remain a Participant as long as his or her Account Balance is greater than zero and during such time may continue to make allocation elections as provided in Section 8.4. An individual shall cease being a Participant in the Plan when all benefits under the Plan to which he or she is entitled have been paid. |
(a) | A Participant shall submit a Compensation Deferral Agreement during the enrollment periods established by the Committee and in the manner specified by the Committee, but in any event, in accordance with Section 4.2. A Compensation Deferral Agreement that is not timely filed with respect to a service period or component of Compensation shall be considered void and shall have no effect with respect to such service period or Compensation. The Committee may modify any Compensation Deferral Agreement prior to the date the election becomes irrevocable under the rules of Section 4.2. |
(b) | The Participant may elect on the Compensation Deferral Agreement to defer (i) an amount of Compensation equal to the percentage of Compensation he has elected to defer to the Qualified Plan reduced by the maximum amount he is permitted to defer to such plan, and/or (ii) additional amounts of Compensation that are independent of his deferral election under the Qualified Plan. The deferral election under the Qualified Plan shall be irrevocable for a year to the extent the Participant makes an election of the type described in (i) above. |
(c) | The Participant shall specify on his or her Compensation Deferral Agreement whether to allocate Deferrals to a Retirement/Termination Account or to a |
(d) | Notwithstanding any other provision of this Plan, a Director may not establish a Specified Date Account or allocate Deferrals to an existing Specified Date Account. All Deferrals by a Director shall be allocated to such Director's Retirement/Termination Account. |
(a) | First Year of Eligibility. In the case of the first year in which an Eligible Employee or a Director becomes eligible to participate in the Plan, he has up to 30 days following his initial eligibility to submit a Compensation Deferral Agreement with respect to Compensation to be earned during such year. The Compensation Deferral Agreement described in this paragraph becomes irrevocable upon the end of such 30-day period. The determination of whether an Eligible Employee or a Director may file a Compensation Deferral Agreement under this paragraph shall be determined in accordance with the rules of Code Section 409A, including the provisions of Treas. Reg. Section 1.409A-2(a)(7). |
(b) | Prior Year Election. Except as otherwise provided in this Section 4.2, Participants may defer Compensation by filing a Compensation Deferral Agreement no later than December 31 of the year prior to the year in which the Compensation to be deferred is earned. A Compensation Deferral Agreement described in this paragraph shall become irrevocable with respect to such Compensation as of January 1 of the year in which such Compensation is earned. |
(c) | Performance-Based Compensation. Participants may file a Compensation Deferral Agreement with respect to Performance-Based Compensation no later than the date that is six months before the end of the performance period, provided that: |
(i) | the Participant performs services continuously from the later of the beginning of the performance period or the date the criteria are established through the date the Compensation Deferral Agreement is submitted; and |
(ii) | the Compensation is not readily ascertainable as of the date the Compensation Deferral Agreement is filed. |
(d) | Fiscal Year Compensation. A Participant may defer Fiscal Year Compensation by filing a Compensation Deferral Agreement prior to the first day of the fiscal year or years in which such Fiscal Year Compensation is earned. The Compensation Deferral Agreement described in this paragraph becomes irrevocable on the first day of the fiscal year or years to which it applies. |
(e) | Short-Term Deferrals. Compensation that meets the definition of a "short-term deferral" described in Treas. Reg. Section 1.409A-l(b)(4) may be deferred in accordance with the rules of Article VII, applied as if the date the Substantial Risk of Forfeiture lapses is the date payments were originally scheduled to commence, provided, however, that the provisions of Section 7.3 shall not apply to payments attributable to a Change in Control (as defined in Treas. Reg. Section 1.409A-3(i)(5)). |
(f) | Certain Forfeitable Rights. With respect to a legally binding right to a payment in a subsequent year that is subject to a forfeiture condition requiring the Participant's continued services for a period of at least twelve months from the date the Participant obtains the legally binding right, an election to defer such Compensation may be made on or before the 30th day after the Participant obtains the legally binding right to the Compensation, provided that the election is made at least twelve months in advance of the earliest date at which the forfeiture condition could lapse. The Compensation Deferral Agreement described in this paragraph becomes irrevocable after such 30th day. If the forfeiture condition applicable to the payment lapses before the end of the required service period as a result of the Participant's death or disability (as defined in Treas. Reg. Section 1.409A-3(i)(4)) or upon a Change in Control (as defined in Treas. Reg. Section 1.409A-3(i)(5)), the Compensation Deferral Agreement will be void unless it would be considered timely under another rule described in this Section. |
(g) | Company Awards. Participating Employers may unilaterally provide for deferrals of Company awards prior to the date of such awards. Deferrals of Company awards (such as sign-on, retention, severance pay, etc.) may be negotiated with a |
(h) | "Evergreen" Deferral Elections. The Committee, in its discretion, may provide in the Compensation Deferral Agreement that such Compensation Deferral Agreement will continue in effect for each subsequent year or performance period. Such "evergreen" Compensation Deferral Agreements will become effective with respect to an item of Compensation on the date such election becomes irrevocable under this Section 4.2. An evergreen Compensation Deferral Agreement may be terminated or modified prospectively with respect to Compensation for which such election remains revocable under this Section 4.2. A Participant whose Compensation Deferral Agreement is cancelled in accordance with Section 4.6 will be required to file a new Compensation Deferral Agreement under this Article IV in order to recommence Deferrals under the Plan. |
(i) | Deferrals On Or Before March 15, 2005. Notwithstanding any other provisions of the Plan, the Committee is authorized to allow any Participant to file an initial deferral election on or before March 15, 2005 with respect to amounts earned on or before December 31, 2005 and which have not become payable as of the date such deferral election is filed. |
4.3 | Allocation of Deferrals. Except as provided in Section 4.1(c), a Compensation Deferral Agreement may allocate Deferrals to one or more Specified Date Accounts and/or to the Retirement/Termination Account. The Committee may, in its discretion, establish a minimum deferral period for Specified Date Accounts (for example, the third Plan Year following the year Compensation subject to the Compensation Deferral Agreement is earned). |
4.4 | Deductions from Pay. The Committee has the authority to determine the payroll practices under which any component of Compensation subject to a Compensation Deferral Agreement will be deducted from a Participant's Compensation. |
4.5 | Vesting. Participant Deferrals shall be 100% vested at all times. |
4.6 | Cancellation of Deferrals. The Committee may cancel a Participant's Deferrals (i) for the balance of the Plan Year in which an Unforeseeable Emergency payment occurs and for the following Plan Year, (ii) if the Participant receives a hardship distribution under the Employer's qualified 401(k) plan, through the end of the Plan Year in which the six month anniversary of the hardship distribution falls, and (iii) during periods in which the Participant is unable to perform the duties of his or her position or any substantially similar position due to a mental or physical impairment that can be expected to result in death or last for a continuous period of at least six months, provided cancellation occurs by the later of the end of the taxable year of the Participant or the 15th day of the third |
5.1 | Company Make-Up Contribution. Provided the Participating Employer has made the maximum matching contribution to the Qualified Plan that is permissible under Section 401(m) of the Code, a Participating Employer will credit to the Retirement/Termination Account of each eligible Participant a Company Make-Up Contribution in an amount (if any) equal to (a) minus (b) below: |
(a) | 100% of a Participant's Deferrals into this Plan that do not exceed 15% of such Participant's base salary and bonus (or such other percentage as determined by the Committee in its discretion); |
(b) | The actual amount of any Company matching contributions to its qualified 401(k) plan for such Participant during the Plan Year. |
5.2 | Discretionary Company Contributions. The Participating Employer may, from time to time in its sole and absolute discretion, credit Company Contributions to any Participant in any amount determined by the Participating Employer. Such contributions will be credited to a Participant's Retirement/Termination Account. |
5.3 | Vesting. Company Make-Up Contributions described in Section 5.1, above, and the Earnings thereon, shall vest in accordance with the following vesting schedule on a "rolling vesting" basis (each Company Make-Up Contribution has its own vesting schedule): |
Years of Service Since the Date of the Company Make-Up Contribution | Percent Vested |
Less than 1 | 0% |
At least 1 but fewer than 2 | 25% |
At least 2 but fewer than 3 | 50% |
At least 3 but fewer than 4 | 75% |
4 or more | 100% |
(a) | Retirement Benefit. Upon the Participant's Separation from Service due to Retirement, he or she shall be entitled to a Retirement Benefit. The Retirement Benefit shall be equal to the vested portion of the Retirement/Termination Account and (i) if the Retirement/Termination Account is payable in a lump sum, the unpaid balances of any Specified Date Accounts, or (ii) if the Retirement/Termination Account is payable in installments, the vested portion of any Specified Date Accounts with respect to which payments have not yet commenced. The Retirement Benefit shall be based on the value of that Account |
(b) | Termination Benefit. Upon the Participant's Separation from Service for reasons other than death, Disability or Retirement, he or she shall be entitled to a Termination Benefit. The Termination Benefit shall be equal to the vested portion of the Retirement/Termination Account and the vested portion of any unpaid balances in any Specified Date Accounts. The Termination Benefit shall be based on the value of the Retirement/Termination Account as of the end of the month in which Separation from Service occurs. Payment of the Termination Benefit will be made or begin in the month following the month in which Separation from Service occurs, provided, however, that with respect to a Participant who is a Specified Employee as of the date such Participant incurs a Separation from Service, payment will be made or begin in the seventh month following the month in which such Separation from Service occurs. |
(c) | Specified Date Benefit. If the Participant has established one or more Specified Date Accounts, he or she shall be entitled to a Specified Date Benefit with respect to each such Specified Date Account. The Specified Date Benefit shall be equal to the vested portion of the Specified Date Account, based on the value of that Account as of the end of the month designated by the Participant at the time the Account was established. Payment of the Specified Date Benefit will be made or begin in the month following the designated month. |
(d) | Disability Benefit. Upon a determination by the Committee that a Participant is Disabled, he or she shall be entitled to a Disability Benefit. The Disability Benefit shall be equal to the vested portion of the Retirement/Termination Account and (i) if the Retirement/Termination Account is payable in a lump sum, the unpaid balances of any Specified Date Accounts, or (ii) if the Retirement/Termination Account is payable in installments, the vested portion of any Specified Date Accounts with respect to which payments have not yet commenced. The Disability Benefit shall be based on the value of the Accounts as of the last day of the month in which Disability occurs and will be paid in the following month. |
(e) | Death Benefit. In the event of the Participant's death, his or her designated Beneficiary(ies) shall be entitled to a Death Benefit. The Death Benefit shall be equal to the vested portion of the Retirement/Termination Account and the vested |
(f) | Unforeseeable Emergency Payments. A Participant who experiences an Unforeseeable Emergency may submit a written request to the Committee to receive payment of all or any portion of his or her Deferrals. The minimum withdrawal is the lesser of $25,000 or 100% of the Deferrals credited to the Participant's Account. Whether a Participant or Beneficiary is faced with an Unforeseeable Emergency permitting an emergency payment shall be determined by the Committee based on the relevant facts and circumstances of each case, but, in any case, a distribution on account of Unforeseeable Emergency may not be made to the extent that such emergency is or may be reimbursed through insurance or otherwise, by liquidation of the Participant's assets, to the extent the liquidation of such assets would not cause severe financial hardship, or by cessation of Deferrals under this Plan. If an emergency payment is approved by the Committee, the amount of the payment shall not exceed the amount reasonably necessary to satisfy the need, taking into account the additional compensation that is available to the Participant as the result of cancellation of deferrals to the Plan, including amounts necessary to pay any taxes or penalties that the Participant reasonably anticipates will result from the payment. The amount of the emergency payment shall be subtracted first from the vested portion of the Participant's Retirement/Termination Account until depleted and then from the vested Specified Date Accounts, beginning with the Specified Date Account with the latest payment commencement date. Emergency payments shall be paid in a single lump sum within the 90-day period following the date the payment is approved by the Committee. |
(g) | Voluntary Withdrawal of Grandfathered Amounts. A Participant may elect at any time to voluntarily withdraw not less than 25% of any Deferrals credited to his or her Grandfathered Account. If such a withdrawal is requested, the Participant (i) shall forfeit an amount equal to 10% of the amount requested, (ii) shall not be permitted to make Deferrals to the Plan in the Plan Year following the Plan Year in which the withdrawal is made, and (iii) shall forfeit any Company Discretionary Contributions (whether vested or unvested) attributable to the amounts so distributed. |
(a) | Retirement Benefit. A Participant who is entitled to receive a Retirement Benefit shall receive payment of such benefit in a single lump sum, unless the Participant elects on his or her initial Compensation Deferral Agreement to have such benefit paid in an alternative form of payment. Alternative forms of payment include (i) a lump sum payment between 0% and 100% of the balance in the |
(b) | Termination Benefit. A Participant who is entitled to receive a Termination Benefit shall receive payment of such benefit in a single lump sum. |
(c) | Specified Date Benefit. The Specified Date Benefit shall be paid in a single lump sum, unless the Participant elects on the Compensation Deferral Agreement with which the account was established to have the Specified Date Account paid in substantially equal annual installments over a period of two to five years, as elected by the Participant. |
(d) | Disability Benefit. A Participant who becomes entitled to receive a Disability Benefit prior to eligibility for Retirement shall receive payment of such benefit in a single lump sum. A Participant who becomes entitled to receive a Disability Benefit after eligibility for Retirement shall receive payment of such benefit in a single lump sum, unless the Participant elects on his or her initial Compensation Deferral Agreement to have such benefit paid in an alternative form of payment. Alternative forms of payment include (i) a lump sum payment between 0% and 100% of the balance in the Retirement/Termination Account; and (ii) any remaining Account Balance payable in a series of substantially equal annual installments from two to twenty years. |
(e) | Death Benefit. A designated Beneficiary who is entitled to receive a Death Benefit shall receive payment of such benefit in a single lump sum. |
(f) | Change in Control. A Participant will receive a single lump sum payment equal to the unpaid balance of all of his or her Accounts if a Separation from Service occurs within 24 months following a Change in Control. In addition to the foregoing, upon a Change in Control, a Participant who has incurred a Separation |
(g) | Small Account Balances. The Committee shall pay the value of the Participant's Accounts upon a Separation from Service in a single lump sum if the balance of such Accounts is not greater than the applicable dollar amount under Code Section 402(g)(l)(B), provided the payment represents the complete liquidation of the Participant's interest in the Plan. |
(h) | Rules Applicable to Installment Payments. If a Payment Schedule specifies installment payments, annual payments will be made beginning as of the payment commencement date for such installments and shall continue on each anniversary thereof until the number of installment payments specified in the Payment Schedule has been paid. The amount of each installment payment shall be determined by dividing (a) by (b), where (a) equals the Account Balance as of the Valuation Date and (b) equals the remaining number of installment payments. |
(i) | Payments from Grandfathered Accounts. Notwithstanding anything to the contrary in this Article VI, the portion of a Retirement Benefit or Disability Benefit credited to a Grandfathered Account (i) shall, if the applicable Account Balance is less than $50,000, be paid in a lump sum, and (ii) shall, if the applicable Account Balance is at least $50,000, be paid commencing within 30 days of the calendar quarter following the one-year anniversary of the Participant's date of termination or date of Disability or, if the Participant has elected a lump sum payment, shall be paid 13 months following the Participant's date of termination or date of Disability. Further, the portion of a Specified Date Benefit credited to a Grandfathered Account shall be paid in a lump sum if the applicable Account Balance is less than $25,000. |
6.3 | Acceleration of or Delay in Payments. The Committee, in its sole and absolute discretion, may elect to accelerate the time or form of payment of a benefit owed to the Participant hereunder, provided such acceleration is permitted under Treas. Reg. Section 1.409A-3G)(4). The Committee may also, in its sole and absolute discretion, delay the time for payment of a benefit owed to the Participant hereunder, to the extent permitted under Treas. Reg. Section 1.409A-2(b)(7). Notwithstanding anything to the contrary herein, no payments shall be made from the Plan pursuant to a domestic relations order. |
7.1 | Participant's Right to Modify. A Participant may modify any or all of the alternative Payment Schedules with respect to an Account, consistent with the permissible Payment Schedules available under the Plan, provided such modification complies with the requirements of this Article VII. Notwithstanding the foregoing, prior to January 1, 2009, the Committee may permit a Participant to modify any or all of the alternative Payment Schedules with respect to an Account, consistent with the permissible Payment Schedules available under the Plan, and without regard to Sections 7.2, 7.3 and 7.4 hereof, provided such modification complies with the requirements of IRS Notice 2007-86. |
7.2 | Time of Election. The date on which a modification election is submitted to the Committee must be at least twelve months prior to the date on which payment is scheduled to commence under the Payment Schedule in effect prior to the modification. |
7.3 | Date of Payment under Modified Payment Schedule. Except with respect to modifications that relate to the payment of a Death Benefit or a Disability Benefit, the date payments are to commence under the modified Payment Schedule must be no earlier than five years after the date payment would have commenced under the original Payment Schedule. Under no circumstances may a modification election result in an acceleration of payments in violation of Code Section 409A. |
7.4 | Effective Date. A modification election submitted in accordance with this Article VII is irrevocable upon receipt by the Committee and becomes effective 12 months after such date. |
7.5 | Effect on Accounts. An election to modify a Payment Schedule is specific to the Account or payment event to which it applies, and shall not be construed to affect the Payment Schedules of any other Accounts. |
7.6 | Modifications to Grandfathered Accounts. Notwithstanding the preceding provisions of this Article VII, a Participant may modify the form of payment in which a Retirement Benefit or Disability Benefit applicable to a Grandfathered Account is payable only if the Committee, in its sole discretion, determines the Participant to be subject to special circumstances, and only if the change is submitted before the 12-month period prior to the date payment was scheduled to commence. A Participant may also postpone payment of a Specified Date Benefit applicable to a Grandfathered Account to a date at least one year later than the previously scheduled payment date if a request is filed with the Committee at least one year prior to the date payments are scheduled to begin. |
8.1 | Valuation. Deferrals shall be credited to appropriate Accounts on the date such Compensation would have been paid to the Participant absent the Compensation Deferral Agreement. Company Contributions shall be credited to the Retirement/Termination Account at the times determined by the Committee. Valuation of Accounts shall be performed under procedures approved by the Committee. |
8.2 | Adjustment for Earnings. Each Account will be adjusted to reflect Earnings on each Business Day. Adjustments shall reflect the net earnings, gains, losses, expenses, appreciation and depreciation associated with an investment option for each portion of the Account allocated to such option ("investment allocation"). |
8.3 | Investment Options. Investment options will be determined by the Committee. The Committee, in its sole discretion, shall be permitted to add or remove investment options from the Plan menu from time to time, provided that any such additions or removals of investment options shall not be effective with respect to any period prior to the effective date of such change. |
8.4 | Investment Allocations. A Participant's investment allocation constitutes a deemed, not actual, investment among the investment options comprising the investment menu. At no time shall a Participant have any real or beneficial ownership in any investment option included in the investment menu, nor shall the Participating Employer or any trustee acting on its behalf have any obligation to purchase actual securities as a result of a Participant's investment allocation. A Participant's investment allocation shall be used solely for purposes of adjusting the value of a Participant's Account Balances. |
8.5 | Unallocated Deferrals and Accounts. If the Participant fails to make an investment allocation with respect to an Account, such Account shall be invested in an investment option, the primary objective of which is the preservation of capital, as determined by the Committee. |
8.6 | Company Stock. The Committee may include Company Stock as one of the investment options described in Section 8.3. The Committee may, in its sole discretion, limit the investment allocation of Company Contributions to Company Stock. The Committee may also require Deferrals consisting of equity-based Compensation to be allocated to Company Stock. |
8.7 | Diversification. A Participant may not re-allocate an investment in Company Stock into another investment option. The portion of an Account that is invested in Company Stock will be paid under Article VI in the form of whole shares of Company Stock. |
8.8 | Effect on Installment Payments. If an Account is to be paid in installments, the Committee will determine the portion of each payment that will be paid in the form of Company Stock. |
8.9 | Dividend Equivalents. Dividend equivalents with respect to Company Stock will be credited to the applicable Accounts in the form of additional shares or units of Company Stock. |
9.1 | Plan Administration. This Plan shall be administered by the Committee which shall have discretionary authority to make, amend, interpret and enforce all appropriate rules and regulations for the administration of this Plan and to utilize its discretion to decide or resolve any and all questions, including but not limited to eligibility for benefits and interpretations of this Plan and its terms, as may arise in connection with the Plan. Claims for benefits shall be filed with the Committee and resolved in accordance with the claims procedures in Article XII. |
9.2 | Administration Upon Change in Control. Upon a Change in Control, the Committee, as constituted immediately prior to such Change in Control, shall continue to act as the Committee. The individual who was the Chief Executive Officer of the Company (or if such person is unable or unwilling to act, the next highest ranking officer) prior to the Change in Control shall have the authority (but shall not be obligated) to appoint an independent third party to act as the Committee. |
9.3 | Withholding. The Participating Employer shall have the right to withhold from any payment due under the Plan (or with respect to any amounts credited to the Plan) any taxes required by law to be withheld in respect of such payment (or credit). Withholdings with respect to amounts credited to the Plan shall be deducted from Compensation that has not been deferred to the Plan. |
9.4 | Indemnification. The Participating Employers shall indemnify and hold harmless each employee, officer, director, agent or organization, to whom or to which are delegated duties, responsibilities, and authority under the Plan or otherwise with respect to administration of the Plan, including, without limitation, the Committee and its agents, against all claims, liabilities, fines and penalties, and all expenses reasonably incurred by or imposed upon him or it (including but not limited to reasonable attorney fees) which arise as a result of his or its actions or failure to act in connection with the operation and administration of the Plan to the extent lawfully allowable and to the extent that such claim, liability, fine, penalty, or expense is not paid for by liability insurance purchased or paid for by the Participating Employer. Notwithstanding the foregoing, the Participating Employer shall not indemnify any person or organization if his or its actions or failure to act are due to gross negligence or willful misconduct or for any such amount incurred through any settlement or compromise of any action unless the Participating Employer consents in writing to such settlement or compromise. |
9.5 | Delegation of Authority. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with legal counsel who shall be legal counsel to the Company. |
9.6 | Binding Decisions or Actions. The decision or action of the Committee in respect of any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations thereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. |
10.1 | Amendment and Termination. The Company may at any time and from time to time amend the Plan or may terminate the Plan as provided in this Article X. Each Participating Employer may also terminate its participation in the Plan. |
10.2 | Amendments. The Company, by action taken by its Board of Directors, may amend the Plan at any time and for any reason, provided that any such amendment shall not reduce the vested Account Balances of any Participant accrued as of the date of any such amendment or restatement (as if the Participant had incurred a voluntary Separation from Service on such date) or reduce any rights of a Participant under the Plan or other Plan features with respect to Deferrals made prior to the date of any such amendment or restatement without the consent of the Participant. The Board of Directors of the Company may delegate to the Committee the authority to amend the Plan without the consent of the Board of Directors for the purpose of (i) conforming the Plan to the requirements of law, (ii) facilitating the administration of the Plan, (iii) clarifying provisions based on the Committee's interpretation of the document and (iv) making such other amendments as the Board of Directors may authorize. |
10.3 | Termination. The Company, by action taken by its Board of Directors, may terminate the Plan and pay Participants and Beneficiaries their Account Balances in a single lump sum at any time, to the extent and in accordance with Treas. Reg. Section 1.409A-3G)(4)(ix). If a Participating Employer terminates its participation in the Plan, the benefits of affected Employees shall be paid at the time provided in Article VI. |
10.4 | Accounts Taxable Under Code Section 409A. The Plan is intended to constitute a plan of deferred compensation that meets the requirements for deferral of income taxation under Code Section 409A. The Committee, pursuant to its authority to interpret the Plan, may sever from the Plan or any Compensation Deferral Agreement any provision or exercise of a right that otherwise would result in a violation of Code Section 409A. |
11.1 | General Assets. Obligations established under the terms of the Plan may be satisfied from the general funds of the Participating Employers, or a trust described in this Article XI. No Participant, spouse or Beneficiary shall have any right, title or interest whatever in assets of the Participating Employers. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship, between the Participating Employers and any Employee, spouse, or Beneficiary. To the extent that any person acquires a right to receive payments hereunder, such rights are no greater than the right of an unsecured general creditor of the Participating Employer. |
11.2 | Rabbi Trust. A Participating Employer may, in its sole discretion, establish a grantor trust, commonly known as a rabbi trust, as a vehicle for accumulating assets to pay benefits under the Plan. Payments under the Plan may be paid from the general assets of the Participating Employer or from the assets of any such rabbi trust. Payment from any such source shall reduce the obligation owed to the Participant or Beneficiary under the Plan. |
12.1 | Filing a Claim. Any controversy or claim arising out of or relating to the Plan shall be filed in writing with the Committee which shall make all determinations concerning such claim. Any claim filed with the Committee and any decision by the Committee denying such claim shall be in writing and shall be delivered to the Participant or Beneficiary filing the claim (the "Claimant"). |
(a) | In General. Notice of a denial of benefits (other than Disability benefits) will be provided within ninety (90) days of the Committee's receipt of the Claimant's claim for benefits. If the Committee determines that it needs additional time to review the claim, the Committee will provide the Claimant with a notice of the extension before the end of the initial ninety (90) day period. The extension will not be more than ninety (90) days from the end of the initial ninety (90) day period and the notice of extension will explain the special circumstances that require the extension and the date by which the Committee expects to make a decision. |
(b) | Disability Benefits. Notice of denial of Disability benefits will be provided within forty-five (45) days of the Committee's receipt of the Claimant's claim for Disability benefits. If the Committee determines that it needs additional time to review the Disability claim, the Committee will provide the Claimant with a notice of the extension before the end of the initial forty-five (45) day period. If the Committee determines that a decision cannot be made within the first extension period due to matters beyond the control of the Committee, the time period for making a determination may be further extended for an additional thirty (30) days. If such an additional extension is necessary, the Committee shall notify the Claimant prior to the expiration of the initial thirty (30) day extension. Any notice of extension shall indicate the circumstances necessitating the extension of time, the date by which the Committee expects to furnish a notice of decision, the specific standards on which such entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim and any additional information needed to resolve those issues. A Claimant will be provided a minimum of forty-five (45) days to submit any necessary additional information to the Committee. In the |
(c) | Contents of Notice. If a claim for benefits is completely or partially denied, notice of such denial shall be in writing and shall set forth the reasons for denial in plain language. The notice shall (i) cite the pertinent provisions of the Plan document and (ii) explain, where appropriate, how the Claimant can perfect the claim, including a description of any additional material or information necessary to complete the claim and why such material or information is necessary. The claim denial also shall include an explanation of the claims review procedures and the time limits applicable to such procedures, including a statement of the Claimant's right to bring a civil action under Section 502(a) of ERISA following an adverse decision on review. In the case of a complete or partial denial of a Disability benefit claim, the notice shall provide a statement that the Committee will provide to the Claimant, upon request and free of charge, a copy of any internal rule, guideline, protocol, or other similar criterion that was relied upon in making the decision. |
12.2 | Appeal of Denied Claims. A Claimant whose claim has been completely or partially denied shall be entitled to appeal the claim denial by filing a written appeal with a committee designated to hear such appeals (the "Appeals Committee"). A Claimant who timely requests a review of the denied claim (or his or her authorized representative) may review, upon request and free of charge, copies of all documents, records and other information relevant to the denial and may submit written comments, documents, records and other information relevant to the claim to the Appeals Committee. All written comments, documents, records, and other information shall be considered "relevant" if the information (i) was relied upon in making a benefits determination,(ii) was submitted, considered or generated in the course of making a benefits decision regardless of whether it was relied upon to make the decision, or (iii) demonstrates compliance with administrative processes and safeguards established for making benefit decisions. The Appeals Committee may, in its sole discretion and if it deems appropriate or necessary, decide to hold a hearing with respect to the claim appeal. |
(a) | In General. Appeal of a denied benefits claim (other than a Disability benefits claim) must be filed in writing with the Appeals Committee no later than sixty (60) days after receipt of the written notification of such claim denial. The Appeals Committee shall make its decision regarding the merits of the denied claim within sixty (60) days following receipt of the appeal (or within one hundred and twenty (120) days after such receipt, in a case where there are special circumstances requiring extension of time for reviewing the appealed claim). If an extension of time for reviewing the appeal is required because of special |
(b) | Disability Benefits. Appeal of a denied Disability benefits claim must be filed in writing with the Appeals Committee no later than one hundred eighty (180) days after receipt of the written notification of such claim denial. The review shall be conducted by the Appeals Committee (exclusive of the person who made the initial adverse decision or such person's subordinate). In reviewing the appeal, the Appeals Committee shall (i) not afford deference to the initial denial of the claim, (ii) consult a medical professional who has appropriate training and experience in the field of medicine relating to the Claimant's disability and who was neither consulted as part of the initial denial nor is the subordinate of such individual and (iii) identify the medical or vocational experts whose advice was obtained with respect to the initial benefit denial, without regard to whether the advice was relied upon in making the decision. The Appeals Committee shall make its decision regarding the merits of the denied claim within forty-five (45) days following receipt of the appeal (or within ninety (90) days after such receipt, in a case where there are special circumstances requiring extension of time for reviewing the appealed claim). If an extension of time for reviewing the appeal is required because of special circumstances, written notice of the extension shall be furnished to the Claimant prior to the commencement of the extension. The notice will indicate the special circumstances requiring the extension of time and the date by which the Appeals Committee expects to render the determination on review. Following its review of any additional information submitted by the Claimant, the Appeals Committee shall render a decision on its review of the denied claim. |
(c) | Contents of Notice. If a benefits claim is completely or partially denied on review, notice of such denial shall be in writing and shall set forth the reasons for denial in plain language. |
(d) | For the denial of a Disability benefit, the notice will also include a statement that the Appeals Committee will provide, upon request and free of charge, (i) any internal rule, guideline, protocol or other similar criterion relied upon in making the decision, (ii) any medical opinion relied upon to make the decision and (iii) the required statement under Section 2560.503-1(j)(5)(iii) of the Department of Labor regulations. |
12.3 | Claims Appeals Upon Change in Control. Upon a Change in Control, the Appeals Committee, as constituted immediately prior to such Change in Control, shall continue to act as the Appeals Committee. Upon such Change in Control, the Company may not remove any member of the Appeals Committee, but may replace resigning members if 2/3rds of the members of the Board of Directors of the Company and a majority of Participants and Beneficiaries with Account Balances consent to the replacement. |
12.4 | Legal Action. A Claimant may not bring any legal action, including commencement of any arbitration, relating to a claim for benefits under the Plan unless and until the Claimant has followed the claims procedures under the Plan and exhausted his or her administrative remedies under such claims procedures. |
12.5 | Discretion of Appeals Committee. All interpretations, determinations and decisions of the Appeals Committee with respect to any claim shall be made in its sole discretion, and shall be final and conclusive. |
12.6 | Arbitration. |
(a) | Prior to Change in Control. If, prior to a Change in Control, any claim or controversy between a Participating Employer and a Participant or Beneficiary is not resolved through the claims procedure set forth in Article XII, such claim shall be submitted to and resolved exclusively by expedited binding arbitration by a single arbitrator. Arbitration shall be conducted in accordance with the following procedures: |
(b) | Upon Change in Control. If, upon the occurrence of a Change in Control, any dispute, controversy or claim arises between a Participant or Beneficiary and the Participating Employer out of or relating to or concerning the provisions of the Plan, such dispute, controversy or claim shall be finally settled by a court of competent jurisdiction which, notwithstanding any other provision of the Plan, shall apply a de novo standard of review to any determination made by the Company or its Board of Directors, a Participating Employer, the Committee, or the Appeals Committee. |
13.1 | Assignment. No interest of any Participant, spouse or Beneficiary under this Plan and no benefit payable hereunder shall be assigned as security for a loan, and any such purported assignment shall be null, void and of no effect, nor shall any such interest or any such benefit be subject in any manner, either voluntarily or involuntarily, to anticipation, sale, transfer, assignment or encumbrance by or through any Participant, spouse or Beneficiary. |
13.2 | No Legal or Equitable Rights or Interest. No Participant or other person shall have any legal or equitable rights or interest in this Plan that are not expressly granted in this Plan. Participation in this Plan does not give any person any right to be retained in the service |
13.3 | No Employment Contract. Nothing contained herein shall be construed to constitute a contract of employment between an Employee and a Participating Employer. |
13.4 | Notice. Any notice or filing required or permitted to be delivered to the Committee under this Plan shall be delivered in writing, in person, or through such electronic means as is established by the Committee. Notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. Written transmission shall be sent by certified mail to: |
13.5 | Headings. The headings of Sections are included solely for convenience of reference, and if there is any conflict between such headings and the text of this Plan, the text shall control. |
13.6 | Invalid or Unenforceable Provisions. If any provision of this Plan shall be held invalid or unenforceable, such invalidity or unenforceability shall not affect any other provisions hereof and the Committee may elect in its sole discretion to construe such invalid or unenforceable provisions in a manner that conforms to applicable law or as if such provisions, to the extent invalid or unenforceable, had not been included. |
13.7 | Lost Participants or Beneficiaries. Any Participant or Beneficiary who is entitled to a benefit from the Plan has the duty to keep the Committee advised of his or her current mailing address. If benefit payments are returned to the Plan or are not presented for payment after a reasonable amount of time, the Committee shall presume that the payee is missing. The Committee, after making such efforts as in its discretion it deems reasonable and appropriate to locate the payee, shall stop payment on any uncashed checks and may discontinue making future payments until contact with the payee is restored. |
13.8 | Facility of Payment to a Minor. If a distribution is to be made to a minor, or to a person who is otherwise incompetent, then the Committee may, in its discretion, make such |
13.9 | Governing Law. To the extent not preempted by ERISA, the laws of the State of Oklahoma shall govern the construction and administration of the Plan. |
By: | Lisa M. Phelps | (Print Name) |
Its: | Vice President of HR | (Title) |
/s/ Lisa M. Phelps | (Signature) | |
• | Receive a base salary of at least $150,000 during the 12-month period immediately preceding the Plan Year, and |
• | Have completed at least three Years of Service as of the December 31 immediately preceding the Plan Year, and |
• | Receive a base salary of at least $150,000 during the 12-month period immediately preceding the Plan Year, and |
• | Have completed at least one Year of Service as of the December 31 immediately preceding the Plan Year, and |
2.24 | Eligible Employee. Eligible Employee means, for a Plan Year, a member of a 'select group of management or highly compensated employees' of a Participating Employer within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of ERISA, as determined by the Committee from time to time in its sole discretion, who has been designated by the Committee as eligible to participate in the Plan. |
5.3 | Vesting. Company Make-Up Contributions described in Section 5.1 above that were made during or after the Plan Year beginning January 2, 2015, and the Earnings thereon, shall vest in accordance with the following vesting schedule: |
Years of Service | Percent Vested |
Less than 1 | 0% |
At least 1 but fewer than 2 | 20% |
At least 2 but fewer than 3 | 40% |
At least 3 but fewer than 4 | 60% |
At least 4 but fewer than 5 | 80% |
5 or more | 100% |
Years of Service Since the Date of the Company Make-Up Contribution | Percent Vested |
Less than 1 | 0% |
At least 1 but fewer than 2 | 25% |
At least 2 but fewer than 3 | 50% |
At least 3 but fewer than 4 | 75% |
4 or more | 100% |
By: | Jay Hawkins | |
Its: | VP-Human Resources | |
/s/ Jay Hawkins | ||
Signature |
1. | Employment. The Company hereby employs the Executive and the Executive hereby accepts such employment subject to the terms and conditions contained in this Agreement. The Executive is engaged as an Executive of the Company, and the Executive and the Company do not intend to create a joint venture, partnership or other relationship which might impose a fiduciary obligation on the Executive or the Company in the performance of this Agreement. |
2. | Executive's Duties. The Executive is employed on a full-time basis. Throughout the term of this Agreement, the Executive will use the Executive's best efforts and due diligence to assist the Company in achieving the most profitable operation of the Company and the Company's affiliated entities consistent with developing and maintaining a quality business operation. The Executive shall also devote all of Executive's working time, attention and energies to the performance of Executive's duties and responsibilities under this Agreement. |
2.1 | Specific Duties. The Executive will serve as Senior Vice President – Legal and General Counsel for the Company, and in such other positions as might be mutually agreed upon by the parties. The Executive shall perform all of the duties required to fully and faithfully execute the office and position to which the Executive is appointed, and such other duties as may be reasonably requested by the Executive's supervisor. During the term of this Agreement, the Executive may be nominated for election or appointed to serve as a director or officer of any of the Company's affiliated entities as determined in such affiliates' Board of Directors' sole discretion. The services of the Executive will be requested and directed by the Company's Chief Executive Officer, Mr. Aubrey K. McClendon. |
2.2 | Rules and Regulations. The Company has issued various policies and procedures applicable to employees and the Executive including an Employment Policies Manual which sets forth the general human |
3. | Other Activities. Except as provided in this Agreement or approved by the Compensation Committee, or its designee, as applicable, in writing, the Executive agrees not to: (a) engage in other operating business activities independent of the Company; (b) serve as a general partner, officer, executive, director or member of any corporation, partnership, company or firm; or (c) directly or indirectly invest, participate or engage in the Oil and Gas Business. For purposes of this Agreement the term "Oil and Gas Business" means: (i) producing oil and gas; (ii) drilling, owning or operating an interest in oil and gas leases or wells; (iii) providing material or services to the Oil and Gas Business; (iv) refining, processing, gathering, compressing, transporting or marketing oil or gas; or (v) owning an interest in or assisting any corporation, partnership, company, entity or person in any of the foregoing. The foregoing will not prohibit: (v) ownership of publicly traded securities; (w) ownership of royalty interests where the Executive owns or previously owned the surface of the land covered in whole or in part by the royalty interest and the ownership of the royalty interest is incidental to the ownership of such surface estate; (x) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas owned prior to the Executive's date of first employment with the Company and disclosed to the Company in writing; (y) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas acquired by the Executive through a bona fide gift or inheritance subject to disclosure by Executive to the Company in writing; or (z) service as an officer or director of a not-for-profit organization so long as such activity does not materially interfere with Executive’s obligations under this Agreement. If the Executive serves as a director or officer of a not-for-profit organization, the Executive shall disclose the name of the organization and their involvement in an annual disclosure statement, the form of which shall be provided by the Company. |
4. | Executive's Compensation. The Company agrees to compensate the Executive as follows: |
4.1 | Base Salary. A base salary (the "Base Salary"), at the initial annual rate of not less than Four Hundred Fifty Thousand Dollars ($450,000.00) will be paid to the Executive in regular installments in accordance with the Company's designated payroll schedule increasing to not less than Four Hundred Seventy-Five Thousand Dollars ($475,000.00) not later than July 31, 2013, and increasing to not less than Five Hundred Thousand Dollars ($500,000.00) not later than July 31, 2014, assuming the Executive’s continued employment with the Company at the time of any salary increase. |
4.2 | Bonus. In addition to the Base Salary described in paragraph 4.1 of this Agreement, the Executive shall be eligible for an annual bonus for each fiscal year during the Term on the same basis as other executive officers under the Company’s then current annual incentive plan which shall be payable in accordance with the terms of such plan. |
4.3 | Equity Compensation. In addition to the compensation set forth in paragraphs 4.1 and 4.2 of this Agreement, the Executive may periodically receive grants of Chesapeake Energy Corporation restricted stock or other awards from the Company's various equity compensation plans (generally referred to as “Equity Compensation Plans”), subject to the terms and conditions thereof. |
4.4 | Benefits. The Company will provide the Executive such retirement benefits, and such other benefits as are customarily provided to similarly situated executives of the Company and as are set forth in and governed by the Company's Employment Policies Manual. The Executive will be entitled to take one hundred seventy-six (176) hours of Paid Time Off (“PTO”) annually, calculated from the Executive's anniversary date, during the term of this Agreement. No additional compensation will be paid for failure to take PTO. The Company will also provide the Executive the opportunity to apply for coverage under the Company's medical, life and disability plans, if any. If the Executive is accepted for coverage under such plans, the Company will make such coverage available to the Executive on the same terms as is customarily provided by the Company to the plan participants as modified from time to time. The Executive is subject to all of the terms and provisions of the Company's benefit plans or policies. Executive will be entitled to receive reimbursement for all reasonable business expenses incurred by Executive in accordance with the Company’s expense reimbursement policy. All payments for reimbursement under this Section 4.4 shall be paid promptly but in no event later than the last day of Executive’s taxable year following the taxable year in which Executive incurred such expenses. |
5. | Term. The term of Executive’s employment under the provisions of this Agreement shall be for a period commencing on the Effective Date and ending on December 31, 2015 (the "Term"); provided, however, if during the Term of this Agreement a Change of Control occurs, the Term of this Agreement shall be extended to the later of the original expiration date of the Term or the expiration of the Change of Control Period. For purposes of this Agreement, a "Change of Control" means the occurrence of any of the following: |
(a) | the acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of thirty percent (30%) or more of either (i) the then outstanding shares of Chesapeake Energy Corporation |
(b) | during any period of not more than twenty-four (24) months, the individuals who constitute the Board of Directors (the "Incumbent Board") of Chesapeake Energy Corporation as of the beginning of the period cease for any reason to constitute at least a majority of the Board of Directors. Any individual becoming a director whose election, or nomination for election by Chesapeake Energy Corporation's shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board. |
(c) | the consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of Chesapeake Energy Corporation (a "Business Combination"), unless following such Business Combination: (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding CHK Common Stock and Outstanding CHK Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than sixty percent (60%) of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns Chesapeake Energy Corporation or all or substantially all of Chesapeake Energy Corporation's assets either directly or through |
(d) | the approval by the shareholders of Chesapeake Energy Corporation of a complete liquidation or dissolution of Chesapeake Energy Corporation. |
6. | Termination. This Agreement will continue in effect until the expiration of the term stated in Section 5 of this Agreement unless earlier terminated pursuant to this Section 6. For purposes of this Agreement, “Termination Date” shall mean (a) if Executive’s employment is terminated by death, the date of death; (b) if Executive’s employment is terminated pursuant to Section 6.4 due to a disability, thirty (30) days after notice of termination is provided to Executive in accordance with Section 6.4; (c) if Executive’s employment is terminated by Company without Cause or by Executive for Good Reason pursuant to Section 6.1.1 or 6.1.2, on the effective date of termination specified in the notice required by Section 6.1.1 or 6.1.2 respectively; (d) if Executive’s employment is terminated by Company for Cause pursuant to Section 6.1.3, the date on which the notice of termination required by Section 6.1.3 is given; or (e) if Executive’s employment is terminated by Executive pursuant to Section 6.2, on the effective date of termination specified by Executive in the notice of termination required by Section 6.2 unless the Company rejects such date as allowed by Section 6.2, in which case it would be the date specified by the Company. |
6.1 | Termination by Company. The Executive’s employment under this Agreement may be terminated prior to the expiration of the Term under the following circumstances: |
6.1.1 | Termination without Cause or for Good Reason Outside of a Change of Control Period. |
(a) | Termination by the Company without Cause. The Company may terminate the Executive’s employment without Cause at any time by the service of written notice of termination to the Executive specifying an effective date of such termination not sooner than thirty (30) business days after the date of such notice. |
(b) | Termination by the Executive for Good Reason. Executive may terminate employment with the Company for “Good Reason” and such termination will not be a breach of this Agreement by Executive. For purposes of this paragraph 6.1.1(b), Good Reason shall mean the occurrence of one of the events set forth below: |
(i) | elimination of the Executive's job position or material reduction in duties and/or reassignment of the Executive to a new position of materially less authority; or |
(ii) | a material reduction in the Executive’s Base Salary. |
(c) | Obligations of the Company. In the event the Executive is Terminated without Cause or terminates employment for Good Reason outside of a Change of Control Period, the Executive will receive as termination compensation within thirty (30) days of the Termination Date: (a) a payment of one (1) times the sum of Base Salary and Annual Bonus in a lump sum payment; (b) all unvested awards granted to Executive prior to January 1, 2013 under the Equity |
6.1.2 | Termination without Cause or for Good Reason During a Change of Control Period. |
(a) | Termination by the Company without Cause. The Company may terminate the Executive’s employment without Cause during a Change of Control Period at any time by the service of written notice of termination to the Executive specifying an effective date of such termination |
(b) | Termination by the Executive for Good Reason. Executive may terminate employment with the Company for “Good Reason” and such termination will not be a breach of this Agreement by Executive. For purposes of this paragraph 6.1.2(b), Good Reason during a Change of Control Period shall mean the occurrence of one of the events set forth below: |
(i) | elimination of the Executive's job position or material reduction in duties and/or reassignment of the Executive to a new position of materially less authority; |
(ii) | a material reduction in Executive’s Base Salary; or |
(iii) | a requirement that the Executive relocate to a location outside of a fifty (50) mile radius of the location of his/her office or principal base of operation immediately prior to the effective date of a Change of Control. |
(c) | Obligations of the Company. In the event the Executive is Terminated without Cause or terminates employment for Good Reason during a Change of Control Period, the Executive will receive as termination compensation within thirty (30) days of the Termination Date: (a) a payment of two (2) times the sum of Base Salary and Annual Bonus in a lump sum payment; (b) all unvested awards granted under the Equity Compensation Plans shall be immediately vested (provided performance share units |
6.1.3 | Termination for Cause. The Company may terminate the employment of the Executive hereunder at any time for Cause (as hereinafter defined) (such a termination being referred to in this Agreement as a "Termination For Cause") by giving the Executive written notice of such termination. As used in this Agreement, "Cause" means: |
(i) | the willful and continued failure of the Executive to perform substantially the Executive’s duties with the Company or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or the Chief Executive Officer of the Company which specifically identifies the manner in which the Board or Chief Executive Officer believes that the Executive has not substantially performed the Executive’s duties, or |
(ii) | the willful engaging by the Executive in illegal conduct or gross misconduct which is materially and demonstrably injurious to the Company. For purposes of this provision, no act, or failure to act, on the part of the Executive shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of the Company. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the instructions of the Chief Executive Officer or based upon the advice of counsel for the Company shall be conclusively presumed |
6.2 | Termination by Executive. The Executive may voluntarily terminate employment under this Agreement for any reason by the service of written notice of such termination to the Company specifying an effective date of termination no sooner than thirty (30) days and no later than sixty (60) days after the date of such notice; provided, however, if less than thirty (30) days remain in the Term, the minimum notice required from Executive under this Section 6.2 shall be reduced from thirty (30) to seven (7) days. The Company reserves the right to end the employment relationship at any time after the date such notice is given to the Company and to pay Executive through the Termination Date. |
6.3 | Retirement by Executive. In the event the Executive is fifty-five (55) years or older and the Executive’s employment is terminated under Sections 6.1.1 or 6.2 of this Agreement, the Executive will be (a) eligible for accelerated vesting of the unvested awards granted to the Executive prior to January 1, 2013 under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); (b) eligible for continued post-retirement vesting of the unvested awards granted to the Executive on or after January 1, 2013 under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (c) eligible for accelerated vesting of the unvested Supplemental Matching Contributions to the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the "401(k) Make-Up Plan"). The vesting under clauses (a), (b) and (c) of this Section 6.3 will be in accordance with the retirement matrix (the "Retirement Matrix") attached to this Agreement. The right to acceleration and continued vesting is subject to the Executive’s execution of the Company’s severance agreement which will include a release of all legally waivable claims between the parties as of the effective date of the release except for the Company’s obligation to pay the foregoing severance compensation and the Executive’s obligation to comply with all post-employment obligations under this Agreement. |
6.4 | Disability. If the Executive suffers from a physical or mental condition which in the reasonable judgment of the Company's management prevents the Executive from being able to perform the duties specified herein for a period of twelve (12) consecutive weeks, the Executive may be terminated by the Company. In the event the Executive is terminated due to Disability (a) all unvested awards granted to the Executive under the Equity Compensation Plans shall be immediately vested (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (b) any Supplemental Matching Contributions to the Chesapeake Energy 401(k) Make-Up Plan shall be immediately vested. Executive shall also receive a lump sum payment within thirty (30) days of the Termination Date of any PTO pay accrued but unused through the Termination Date. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the Executive or the Executive's legal representative of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company. In applying this Section 6.4, the Company will comply with any applicable legal requirements, including the Americans with Disabilities Act. |
6.5 | Death of Executive. If the Executive dies during the term of this Agreement, the Company may thereafter terminate this Agreement without compensation. In the event of the Executive’s death the Company will (a) immediately vest all unvested awards granted to the Executive under the Equity Compensation Plans (provided performance share units shall only be payable subject to the attainment of the performance measures for the applicable performance period as provided under the terms of the applicable award agreement); and (b) immediately vest any Supplemental Matching Contributions to the Chesapeake Energy 401(k) Make-Up Plan. Executive’s beneficiaries/estate shall also receive a lump sum payment within thirty (30) days of death of any PTO pay accrued but unused through the Termination Date. Amounts payable under this Section 6.5 shall be paid to the beneficiary designated on the Company's universal beneficiary designation form in effect on the date of the Executive's death. If the Executive fails to designate a beneficiary or if such designation is ineffective, in whole or in part, any payment that would otherwise have been paid under this Section 6.5 shall be paid to the Executive's estate. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the beneficiary, or as applicable, the administrator of the Executive's estate of the Company's severance agreement which will operate as a release of all legally waivable claims against the Company. |
6.6 | Effect of Termination. The termination of this Agreement, when accompanied by the termination of Executive’s employment with the |
7. | Non-Competition. For a period of one (1) year after the Executive is no longer employed by the Company for any reason, the Executive will not knowingly acquire, attempt to acquire or aid another in the acquisition or attempted acquisition of an interest in oil and gas assets, oil and gas production, oil and gas leases, mineral interests, oil and gas wells or other such oil and gas exploration, development or production activities within any spacing unit in which the Company owns an oil and gas interest on the date of the resignation or termination of the Executive. |
8. | Non-Solicitation. The Executive agrees that during his/her employment hereunder, and for the one (1) year period immediately following the termination of employment for any reason, the Executive shall not solicit or contact any established client or customer of the Company with a view to inducing or encouraging such established client or customer to discontinue or curtail any business relationship with the Company. The Executive further agrees that the Executive will not request or advise any established clients, customers or suppliers of the Company to withdraw, curtail or cancel its business with the Company. |
9. | Non-Solicitation of Employees. The Executive covenants that during the term of employment and for the one (1) year period immediately following the termination of employment for any reason, Executive will neither directly nor indirectly induce nor attempt to induce any executive or employee of the Company to terminate his or her employment with the Company to go to work for any other company. |
10. | Reasonableness. The Company and the Executive have attempted to specify a reasonable period of time and reasonable restrictions to which this Agreement shall apply. The Company and Executive agree that if a court or administrative body should subsequently determine that the terms of this Agreement are greater than reasonably necessary to protect the Company's interest, the Company agrees to waive those terms which are found by a court or administrative body to be greater than reasonably necessary to protect the Company's interest and to request that the court or administrative body reform this Agreement specifying a reasonable period of time and such other reasonable restrictions as the court or administrative body deems necessary. |
11. | Equitable Relief. The Executive acknowledges that the services to be rendered by Executive are of a special, unique, unusual, extraordinary, and intellectual character, which gives them a peculiar value, and the loss of which cannot reasonably or adequately be compensated in damages in an action at law; and that a breach by the Executive of any of the provisions contained in this Agreement will cause the Company irreparable injury and damage. The Executive further acknowledges that the Executive possesses unique skills, knowledge and ability |
12. | Continued Litigation Assistance. The Executive will cooperate with and assist the Company and its representatives and attorneys as requested, during and after the Term, with respect to any litigation, arbitration or other dispute resolutions by being available for interviews, depositions and/or testimony in regard to any matters in which the Executive is or has been involved or with respect to which the Executive has relevant information. The Company will reimburse the Executive for any reasonable business expenses the Executive may have incurred in connection with this obligation. |
13. | Arbitration. Any disputes, claims or controversies between the Company and Executive including, but not limited to those arising out of or related to this Agreement or out of the parties' employment relationship (together, “Employment Matter”), shall be settled by arbitration as provided herein. This agreement shall survive the termination or rescission of this Agreement. All arbitration shall be in accordance with Rules of the American Arbitration Association, including discovery, and shall be undertaken pursuant to the Federal Arbitration Act. Arbitration will be held in Oklahoma City, Oklahoma unless the parties mutually agree to another location. The decision of the arbitrator will be enforceable in any court of competent jurisdiction. The parties, however, agree that the Company shall be entitled to obtain injunctive or other equitable relief to enforce the provisions of this Agreement in a court of competent jurisdiction. The parties further agree that this arbitration provision is not only applicable to the Company but its affiliates, officers, directors, employees and related parties. Executive agrees that he/she shall have no right or authority for any dispute to be brought, heard or arbitrated as a class or collective action, or in a representative or a private attorney general capacity on behalf of a class of persons or the general public. No class, collective or representative actions are thus allowed to be arbitrated and Executive agrees that he/she must pursue any claims that he/she may have solely on an individual basis through arbitration. The Company will reimburse the Executive for all legal fees and expenses reasonably incurred (provided such legal fees are calculated on an hourly, and not on a contingency fee basis), as well as costs and expenses reasonably incurred in connection with an Employment Matter. Reimbursement by the Company shall be made as soon as practicable following final resolution of the Employment Matter to the extent the Company receives appropriate documentation of such attorney’s fees, costs and expenses which shall be provided no later than December 31 of the year in which the Employment Matter is resolved, provided, however, the Executive will only be entitled to reimbursement if the Executive is successful in respect of one or more material claims or defenses brought, raised or pursued in connection with such Employment Matter. Payment of reimbursement for such fees and expenses |
14 | Miscellaneous. The parties further agree as follows: |
14.1 | Time. Time is of the essence of each provision of this Agreement. |
14.2 | Notices. Any notice, payment, demand or communication required or permitted to be given by any provision of this Agreement will be in writing and will be deemed to have been given when delivered personally or by express mail to the party designated to receive such notice, or on the date following the day sent by overnight courier, or on the third business day after the same is sent by certified mail, postage and charges prepaid, directed to the following address or to such other or additional addresses as any party might designate by written notice to the other party: |
To the Company: | Chesapeake Energy Corporation |
6100 N. Western Ave. | |
Oklahoma City, OK 73118 | |
Attn: Lisa M. Phelps | |
To the Executive: | James R. Webb |
516 Meadow Run Court | |
Yukon, OK 73099 |
14.3 | Assignment. Neither this Agreement nor any of the parties' rights or obligations hereunder can be transferred or assigned without the prior written consent of the other parties to this Agreement; provided, however, the Company may assign this Agreement to any wholly owned affiliate or subsidiary of Chesapeake Energy Corporation without Executive's consent as well as to any purchaser of the Company. |
14.4 | Construction. If any provision of this Agreement or the application thereof to any person or circumstances is determined, to any extent, to be invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which the same is held invalid or unenforceable, will not be affected thereby, and each term and provision of this Agreement will be valid and enforceable to the fullest extent permitted by law. Except as provided for in Section 13, this Agreement is intended to be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma. |
14.5 | Entire Agreement. This Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual constitute the entire agreement between the parties hereto with respect to the subject matter |
14.6 | Binding Effect. This Agreement will be binding on the parties and their respective successors, legal representatives and permitted assigns. In the event of a merger, consolidation, combination, dissolution or liquidation of the Company, the performance of this Agreement will be assumed by any entity which succeeds to or is transferred the business of the Company as a result thereof, and the Executive waives the consent requirement of Section 14.3 to effect such assumption. |
14.7 | Supersession. On execution of this Agreement by the Company and the Executive, the relationship between the Company and the Executive will be bound by the terms of this Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual. In the event of a conflict between the Employment Policies Manual and this Agreement, this Agreement will control in all respects. |
14.8 | Third-Party Beneficiary. The Company's affiliated entities and partnerships are beneficiaries of all terms and provisions of this Agreement and entitled to all rights hereunder. |
14.9 | Section 409A. This Agreement is intended to be exempt from Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and related U.S. Treasury regulations or official pronouncements (“Section 409A”) and any ambiguous provision will be construed in a manner that is compliant with such exemption; provided, however, if and to the extent that any compensation payable pursuant to this Agreement is determined to be subject to Section 409A, this Agreement will be construed in a manner that will comply with Section 409A. Notwithstanding any provision to the contrary in this Agreement, if the Executive is deemed on his/her Termination Date to be a “specified employee” within the meaning of that term under Section 409A, then any payments and benefits under this Agreement that are subject to Section 409A and paid by reason of a termination of employment shall be made or provided on the later of (a) the payment date set forth in this Agreement or (b) the date that is the earliest of (i) the expiration of the six-month period measured from the date of the Executive’s termination of employment or (ii) the date of the Executive’s death (the “Delay Period”). Payments and benefits subject to the Delay Period shall be paid or provided to the Executive without interest for such delay. Termination of employment as used throughout this Agreement shall refer to a separation from service within the meaning of Section 409A. To the extent required to comply with Section 409A, references to a “resignation,” “termination,” “termination of employment” or like terms |
14.10 | Dodd-Frank Act. Notwithstanding anything in this Agreement or any other agreement between the Company and/or its related entities and Executive to the contrary, Executive acknowledges that the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Act”) may have the effect of requiring certain executives of the Company and/or its related entities to repay the Company, and for the Company to recoup from such executives, erroneously awarded amounts of incentive-based compensation. If, and only to the extent, the Act, any rules and regulations promulgated by thereunder by the Securities and Exchange Commission or any similar federal or state law requires the Company to recoup any erroneously awarded incentive-based compensation that the Company has paid or granted to Executive, Executive hereby agrees, even if Executive has terminated his employment with the Company, to promptly repay such erroneously awarded incentive compensation to the Company upon its written request. This Section shall survive the termination of this Agreement. |
14.11 | Maximum Payments by the Company. |
(a) | It is the objective of this Agreement to maximize Executive’s Net After-Tax Benefit (as defined herein) if payments or benefits provided under this Agreement are subject to excise tax under Section 4999 of the Code. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit by the Company or otherwise to or for the benefit of Executive, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, including, by example and not by way of limitation, acceleration by the Company or otherwise of the date of vesting or payment or rate of payment under any plan, program, arrangement or agreement of the Company (all such payments and benefits, including the payments and benefits under Section 6 hereof, being hereinafter referred to as the “Total Payments”), would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code (the “Excise Tax”), then the cash severance payments shall first be reduced, and the non-cash severance payments shall thereafter be reduced, to the extent necessary so that no portion of the Total Payments shall be subject to the Excise Tax, but only if (i) the net amount of such Total Payments, as so reduced (and after subtracting the net amount of federal, state and local income taxes on such reduced Total Payments and after taking into account the phase out of itemized deductions and personal exemptions attributable to such reduced Total Payments), is greater than or equal to (ii) the net amount of such Total Payments without such reduction (but after subtracting the net amount of federal, state and local income taxes on such Total Payments and the amount of Excise Tax |
(b) | The Total Payments shall be reduced by the Company in the following order: (i) reduction of any cash severance payments otherwise payable to Executive that are exempt from Section 409A of the Code, (ii) reduction of any other cash payments or benefits otherwise payable to Executive that are exempt from Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting or payments with respect to any equity award with respect to the Company’s common stock that is exempt from Section 409A of the Code, (iii) reduction of any other payments or benefits otherwise payable to Executive on a pro-rata basis or such other manner that complies with Section 409A of the Code, but excluding any payments attributable to the acceleration of vesting and payments with respect to any equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code, and (iv) reduction of any payments attributable to the acceleration of vesting or payments with respect to any other equity award with respect to the Company’s common stock that are exempt from Section 409A of the Code. |
(c) | For purposes of determining whether and the extent to which the Total Payments will be subject to the Excise Tax, (i) no portion of the Total Payments the receipt or enjoyment of which Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Total Payments shall be taken into account which, in the written opinion of independent auditors of nationally recognized standing (“Independent Advisors”) selected by the Company, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Total Payments shall be taken into account which, in the opinion of Independent Advisors, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the “base amount” (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Total Payments shall be determined by the Independent Advisors in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. The costs of obtaining such determination shall be borne by the Company. |
CHESAPEAKE ENERGY CORPORATION, an | ||
Oklahoma corporation | ||
By: | /s/ Aubrey K. McClendon | |
Aubrey K. McClendon, Chief Executive Officer | ||
(the "Company") | ||
By: | /s/ James R. Webb | |
James R. Webb, Individually | ||
(the "Executive") | ||
Executive Vice President | ||||
Service Yrs | <55 | 55-59 | 60-64 | >=65 |
0-5 | 0% | 0% | 0% | 0% |
5-10 | 0% | 60% | 80% | 100% |
10-15 | 0% | 80% | 100% | 100% |
15-20 | 0% | 100% | 100% | 100% |
20+ | 0% | 100% | 100% | 100% |
Years Ended December 31, | ||||||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | ||||||||||||||||
($ in millions) | ||||||||||||||||||||
EARNINGS: | ||||||||||||||||||||
Income (loss) before income taxes and cumulative effect of accounting change | $ | 2,884 | $ | 2,880 | $ | (974 | ) | $ | 1,442 | $ | 3,200 | |||||||||
Interest expense(a) | 122 | 94 | 142 | 207 | 172 | |||||||||||||||
(Gain)/loss on investment in equity investees in excess of distributed earnings | (232 | ) | (154 | ) | 108 | 219 | 75 | |||||||||||||
Amortization of capitalized interest | 212 | 297 | 402 | 440 | 438 | |||||||||||||||
Loan cost amortization | 25 | 28 | 43 | 37 | 32 | |||||||||||||||
Earnings | $ | 3,011 | $ | 3,145 | $ | (279 | ) | $ | 2,345 | $ | 3,917 | |||||||||
FIXED CHARGES: | ||||||||||||||||||||
Interest Expense | $ | 122 | $ | 94 | $ | 142 | $ | 207 | $ | 172 | ||||||||||
Capitalized interest | 711 | 727 | 976 | 815 | 604 | |||||||||||||||
Loan cost amortization | 25 | 28 | 43 | 37 | 32 | |||||||||||||||
Fixed Charges | $ | 858 | $ | 849 | $ | 1,161 | $ | 1,059 | $ | 808 | ||||||||||
PREFERRED STOCK DIVIDENDS: | ||||||||||||||||||||
Preferred dividend requirements | $ | 111 | $ | 172 | $ | 171 | $ | 171 | $ | 171 | ||||||||||
Ratio of income (loss) before provision for taxes to net income (loss)(b) | 1.63 | 1.65 | 1.64 | 1.61 | 1.56 | |||||||||||||||
Preferred Dividends | $ | 181 | $ | 284 | $ | 280 | $ | 275 | $ | 266 | ||||||||||
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS | $ | 1,039 | $ | 1,131 | $ | 1,441 | $ | 1,334 | $ | 1,074 | ||||||||||
RATIO OF EARNINGS TO FIXED CHARGES | 3.5 | 3.7 | (0.2 | ) | 2.2 | 4.8 | ||||||||||||||
INSUFFICIENT COVERAGE | $ | — | $ | — | $ | 1,440 | $ | — | $ | — | ||||||||||
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS | 2.9 | 2.8 | (0.2 | ) | 1.8 | 3.6 | ||||||||||||||
INSUFFICIENT COVERAGE | $ | — | $ | — | $ | 1,720 | $ | — | $ | — |
(a) | Excludes the effect of unrealized gains or losses on interest rate derivatives and includes amortization of bond discount. |
(b) | Amounts of income (loss) before provision for taxes and of net income (loss) exclude the cumulative effect of accounting change. |
Corporations | State of Organization | |
Chesapeake E&P Holding Corporation | Oklahoma | |
Chesapeake Energy Louisiana Corporation | Oklahoma | |
Limited Liability Companies | State of Organization | |
Chesapeake Appalachia, L.L.C. | Oklahoma | |
Chesapeake Energy Marketing, L.L.C. | Oklahoma | |
Chesapeake Exploration, L.L.C. | Oklahoma | |
Chesapeake Land Development Company, L.L.C. | Oklahoma | |
Chesapeake Operating, L.L.C. | Oklahoma | |
CHK Utica, L.L.C. | Delaware | |
MidCon Compression, L.L.C. | Oklahoma | |
Partnerships | State of Organization | |
Chesapeake Lousiana, L.P. | Oklahoma | |
* In accordance with Regulation S-K Item 601(b)(21), the names of particular subsidiaries that, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary (as that term is defined in Rule 1-02(w) of Regulation S-X) as of the end of the year covered by this report have been omitted. |
1. | I have reviewed this annual report on Form 10-K of Chesapeake Energy Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made know to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
February 27, 2015 | By: | /s/ ROBERT D. LAWLER |
Robert D. Lawler | ||
President and Chief Executive Officer |
1. | I have reviewed this annual report on Form 10-K of Chesapeake Energy Corporation; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made know to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
February 27, 2015 | By: | /s/ DOMENIC J. DELL’OSSO, JR. |
Domenic J. Dell’Osso, Jr. | ||
Executive Vice President and Chief Financial Officer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
February 27, 2015 | By: | /s/ ROBERT D. LAWLER |
Robert D. Lawler President and Chief Executive Officer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
February 27, 2015 | By: | /s/ DOMENIC J. DELL’OSSO, JR. |
Domenic J. Dell’Osso, Jr. | ||
Executive Vice President and Chief Financial Officer |
PetroTechnical Services | |
Division of Schlumberger Technology Corporation | |
4600 J. Barry Court | |
Suite 200 | |
Canonsburg, PA 15317 USA | |
Tel: 724-416-9700 | |
Fax: 724-416-9705 |
Proved Developed Reserves | Proved Undeveloped Reserves | Total Proved Reserves | |
Remaining Net Reserves Oil – Mbbls NGL - Mbbls Gas – MMscf Oil Equiv. – Mbbls | 22,998.21 51,444.93 2,354,869.75 466,921.44 | 6,845.29 13,097.82 737,364.06 142,837.12 | 29,843.50 64,542.75 3,092,233.50 609,758.44 |
Income Data (M$) Future Net Revenue Deductions Operating Expense Production Taxes Investment Future Net Cashflow (FNC) | 10,378,187.24 1,591,295.00 371,640.77 439,202.97 7,976,046.50 | 3,125,823.94 210,932.09 61,352.54 667,938.69 2,185,600.50 | 13,504,011.00 1,802,227.00 432,993.28 1,107,141.75 10,161,648.00 |
Discounted PV @ 10% (M$) | 4,479,868.50 | 1,107,491.50 | 5,587,357.00 |
PetroTechnical Services | |
Division of Schlumberger Technology Corporation | |
January 26, 2015 | |
Page 2 |
Proved Producing Reserves | Proved Behind Pipe Reserves | Proved Non-producing Reserves | Proved Shut-In Reserves | Proved Undeveloped Reserves | Total Proved Reserves | |
Remaining Net Reserves Oil – Mbbls NGL - Mbbls Gas – MMscf Oil Equiv. – Mbbls | 20,485.49 49,472.07 2,165,803.00 430,924.75 | 0.00 0.00 10,980.09 1,830.02 | 2,512.72 1,972.85 178,086.36 34,166.63 | 0.00 0.00 0.00 0.00 | 6,845.29 13,097.82 737,364.06 142,837.12 | 29,843.50 64,542.75 3,092,233.50 609,758.44 |
Income Data (M$) Future Net Revenue Deductions Operating Expense Production Taxes Investment Future Net Cashflow (FNC) | 9,571,083.50 1,507,111.88 336,494.03 351,209.88 7,376,266.00 | 34,002.66 4,811.43 787.61 8,221.17 20,182.45 | 773,100.65 78,730.56 34,359.07 75,482.80 584,528.12 | 0.00 640.96 0.00 4,289.14 (4,930.10) | 3,125,823.94 210,932.09 61,352.54 667,938.69 2,185,600.50 | 13,504,011.00 1,802,227.00 432,993.28 1,107,141.75 10,161,648.00 |
Discounted PV @ 10% (M$) | 4,107,597.75 | 8,519.94 | 368,291.69 | (4,541.670) | 1,107,491.50 | 5,587,357.00 |
PetroTechnical Services | |
Division of Schlumberger Technology Corporation | |
January 26, 2015 | |
Page 3 |
Product | Reference Point | Year End 2014 Reference Price | Average Price |
Oil | West Texas Intermediate | $94.984/Bbl | $82.320/Bbl |
NGL | West Texas Intermediate | $94.984/Bbl | $23.191/Bbl |
Natural Gas | Henry Hub | $4.350/MMBtu | $3.089/Mscf |
PetroTechnical Services | |
Division of Schlumberger Technology Corporation | |
January 26, 2015 | |
Page 4 |
Sincerely yours, | |
/s/ Denise L. Delozier | /s/ Charles M. Boyer II |
Denise L. Delozier | Charles M. Boyer II, PG, CPG |
Senior Engineer | Northeast Basin Business Manager |
Advisor - Unconventional Reservoirs | |
/s/ Walker K. Sawyer | |
Walker K. Sawyer, PE | |
Principal Consultant |
\s\ Don P. Griffin |
Don P. Griffin, P.E. |
TBPE License No. 64150 |
Senior Vice President |
As of December 31, 2014 |
Proved | ||||||||||||||||
Developed | Total | |||||||||||||||
Producing | Non-Producing | Undeveloped | Proved | |||||||||||||
Net Remaining Reserves | ||||||||||||||||
Oil/Condensate – MBarrels | 158,446 | 5,790 | 124,673 | 288,909 | ||||||||||||
Plant Products – MBarrels | 116,071 | 5,367 | 31,855 | 153,293 | ||||||||||||
Gas – MMCF | 4,541,273 | 193,396 | 648,225 | 5,382,894 | ||||||||||||
MBOE | 1,031,396 | 43,389 | 264,566 | 1,339,351 | ||||||||||||
Income Data (M$) | ||||||||||||||||
Future Gross Revenue | $27,358,076 | $1,186,093 | $12,206,031 | $40,750,200 | ||||||||||||
Deductions | 6,154,879 | 328,982 | 4,965,463 | 11,449,324 | ||||||||||||
Future Net Income (FNI) | $21,203,197 | $ | 857,111 | $ | 7,240,568 | $29,300,876 | ||||||||||
Discounted FNI @ 10% | $10,680,345 | $ | 428,357 | $ | 2,488,373 | $13,597,075 |
Discounted Future Net Income (M$) | ||||
As of December 31, 2014 | ||||
Discount Rate | Total | |||
Percent | Proved | |||
5 | $18,418,128 | |||
8 | $15,156,650 | |||
12 | $12,353,876 | |||
14 | $11,338,637 |
Geographic Area | Product | Price Reference | Average Benchmark Prices* | Average Realized Prices |
United States | Oil/Condensate | WTI Cushing | $94.98/Bbl | $89.91/Bbl |
NGLs | WTI Cushing | $94.98/Bbl | $24.76/Bbl | |
Gas | Henry Hub | $4.35/MMBTU | $2.45/MCF |
* | Benchmark prices were provided by Chesapeake. |
Very truly yours, | |
RYDER SCOTT COMPANY, L.P. | |
TBPE Firm Registration No. F-1580 | |
\s\ Don P. Griffin | |
Don P. Griffin, P.E. | |
TBPE License No. 64150 | |
Senior Vice President | |
[SEAL] |
(1) | completion intervals which are open at the time of the estimate, but which have not started producing; |
(2) | wells which were shut-in for market conditions or pipeline connections; or |
(3) | wells not capable of production for mechanical reasons. |
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
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