Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2017 | Nov. 01, 2017 | |
Document and Entity Information | ||
Entity Registrant Name | Kosmos Energy Ltd. | |
Entity Central Index Key | 1,509,991 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2017 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 389,355,364 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q3 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Sep. 30, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 164,162,000 | $ 194,057,000 |
Restricted cash | 55,852,000 | 24,506,000 |
Receivables: | ||
Joint interest billings, net | 75,373,000 | 63,249,000 |
Oil sales | 51,726,000 | 54,195,000 |
Related party | 6,446,000 | 0 |
Other | 15,756,000 | 25,893,000 |
Inventories | 74,275,000 | 74,380,000 |
Prepaid expenses and other | 9,359,000 | 7,209,000 |
Derivatives | 16,200,000 | 31,698,000 |
Total current assets | 469,149,000 | 475,187,000 |
Property and equipment: | ||
Oil and gas properties, net | 2,251,977,000 | 2,700,889,000 |
Other property, net | 6,424,000 | 8,003,000 |
Property and equipment, net | 2,258,401,000 | 2,708,892,000 |
Other assets: | ||
Equity method investment | 122,664,000 | 0 |
Restricted cash | 15,194,000 | 54,632,000 |
Long-term receivables - joint interest billings | 47,525,000 | 45,663,000 |
Deferred financing costs, net of accumulated amortization of $13,267 and $11,213 at September 30, 2017 and December 31, 2016, respectively | 3,194,000 | 5,248,000 |
Long-term deferred tax assets | 34,546,000 | 37,827,000 |
Derivatives | 2,412,000 | 3,808,000 |
Other | 17,363,000 | 10,208,000 |
Total assets | 2,970,448,000 | 3,341,465,000 |
Current liabilities: | ||
Accounts payable | 100,302,000 | 220,627,000 |
Accrued liabilities | 173,804,000 | 129,706,000 |
Derivatives | 9,016,000 | 19,692,000 |
Total current liabilities | 283,122,000 | 370,025,000 |
Long-term liabilities: | ||
Long-term debt, net | 1,080,352,000 | 1,321,874,000 |
Derivatives | 7,256,000 | 14,123,000 |
Asset retirement obligations | 68,713,000 | 63,574,000 |
Deferred tax liabilities | 511,891,000 | 482,221,000 |
Other long-term liabilities | 9,871,000 | 8,449,000 |
Total long-term liabilities | 1,678,083,000 | 1,890,241,000 |
Shareholders’ equity: | ||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2017 and December 31, 2016 | 0 | 0 |
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,545,540 and 395,859,061 issued at September 30, 2017 and December 31, 2016, respectively | 3,985,000 | 3,959,000 |
Additional paid-in capital | 2,004,578,000 | 1,975,247,000 |
Accumulated deficit | (951,123,000) | (850,410,000) |
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at September 30, 2017 and December 31, 2016, respectively | (48,197,000) | (47,597,000) |
Total shareholders’ equity | 1,009,243,000 | 1,081,199,000 |
Total liabilities and shareholders’ equity | $ 2,970,448,000 | $ 3,341,465,000 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Deferred financing costs, accumulated amortization | $ 13,267 | $ 11,213 |
Preference shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preference shares, authorized shares | 200,000,000 | 200,000,000 |
Preference shares, issued shares | 0 | 0 |
Common shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common shares, authorized shares | 2,000,000,000 | 2,000,000,000 |
Common shares, issued shares | 398,545,540 | 395,859,061 |
Treasury stock shares | 9,188,819 | 9,101,395 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Revenues and other income: | ||||
Oil and gas revenue | $ 151,240 | $ 46,628 | $ 391,035 | $ 154,259 |
Other income, net | 2 | 20,001 | 58,697 | 20,179 |
Total revenues and other income | 151,242 | 66,629 | 449,732 | 174,438 |
Costs and expenses: | ||||
Oil and gas production | 39,187 | 13,574 | 80,677 | 75,647 |
Facilities insurance modifications, net | (3,906) | 5,946 | (1,334) | 5,946 |
Exploration expenses | 36,983 | 66,238 | 162,679 | 126,498 |
General and administrative | 20,029 | 21,914 | 50,555 | 59,672 |
Depletion and depreciation | 73,490 | 17,838 | 180,909 | 66,031 |
Interest and other financing costs, net | 18,478 | 11,066 | 54,729 | 30,268 |
Derivatives, net | 26,864 | (16,891) | (36,404) | 33,752 |
Other expenses, net | 5,037 | (795) | 14,233 | 13,768 |
Total costs and expenses | 216,162 | 118,890 | 506,044 | 411,582 |
Loss before income taxes | (64,920) | (52,261) | (56,312) | (237,144) |
Income tax expense (benefit) | (1,515) | 7,502 | 44,401 | (10,064) |
Net loss | $ (63,405) | $ (59,763) | $ (100,713) | $ (227,080) |
Net loss per share: | ||||
Basic (in dollars per share) | $ (0.16) | $ (0.15) | $ (0.26) | $ (0.59) |
Diluted (in dollars per share) | $ (0.16) | $ (0.15) | $ (0.26) | $ (0.59) |
Weighted average number of shares used to compute net loss per share: | ||||
Basic (in shares) | 389,058,000 | 386,026,000 | 388,114,000 | 385,130,000 |
Diluted (in shares) | 389,058,000 | 386,026,000 | 388,114,000 | 385,130,000 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 9 months ended Sep. 30, 2017 - USD ($) shares in Thousands, $ in Thousands | Total | Common Shares | Additional Paid-in Capital | Accumulated Deficit | Treasury Stock |
Balance at the beginning (in shares) at Dec. 31, 2016 | 395,859 | ||||
Balance at the beginning at Dec. 31, 2016 | $ 1,081,199 | $ 3,959 | $ 1,975,247 | $ (850,410) | $ (47,597) |
Increase (Decrease) in Shareholders' Equity | |||||
Equity-based compensation | 30,873 | 30,873 | |||
Restricted stock awards and units (in shares) | 2,686 | ||||
Restricted stock awards and units | 0 | $ 26 | (26) | ||
Purchase of treasury stock | (2,116) | (1,516) | (600) | ||
Net loss | (100,713) | (100,713) | |||
Balance at the end (in shares) at Sep. 30, 2017 | 398,545 | ||||
Balance at the end at Sep. 30, 2017 | $ 1,009,243 | $ 3,985 | $ 2,004,578 | $ (951,123) | $ (48,197) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Operating activities | ||
Net loss | $ (100,713) | $ (227,080) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||
Depletion, depreciation and amortization | 188,563 | 73,684 |
Deferred income taxes | 32,820 | (16,821) |
Unsuccessful well costs | 24,515 | 2,609 |
Change in fair value of derivatives | (25,924) | 37,179 |
Cash settlements on derivatives, net (including $36.4 million and $146.5 million on commodity hedges during 2017 and 2016) | 25,275 | 144,522 |
Equity-based compensation | 29,945 | 30,391 |
Loss on equity method investment | 11,230 | 0 |
Other | 3,412 | 13,358 |
Changes in assets and liabilities: | ||
Decrease in receivables | 3,232 | 29,833 |
(Increase) decrease in inventories | 58 | (12,066) |
(Increase) decrease in prepaid expenses and other | (19,327) | 15,164 |
Decrease in accounts payable | (120,325) | (122,142) |
Increase (decrease) in accrued liabilities | 41,651 | (34,254) |
Net cash provided by (used in) operating activities | 94,412 | (65,623) |
Investing activities | ||
Oil and gas assets | (100,712) | (506,256) |
Other property | (1,639) | (1,003) |
Proceeds on sale of assets | 222,068 | 210 |
Net cash provided by (used in) investing activities | 119,717 | (507,049) |
Financing activities | ||
Borrowings under long-term debt | 0 | 450,000 |
Payments on long-term debt | (250,000) | 0 |
Purchase of treasury stock | (2,116) | (1,930) |
Net cash provided by (used in) financing activities | (252,116) | 448,070 |
Net decrease in cash, cash equivalents and restricted cash | (37,987) | (124,602) |
Cash, cash equivalents and restricted cash at beginning of period | 273,195 | 310,862 |
Cash, cash equivalents and restricted cash at end of period | 235,208 | 186,260 |
Cash paid for: | ||
Interest | 48,694 | 25,540 |
Income taxes | 27,199 | 6,997 |
Non-cash activity: | ||
Conversion of joint interest billings receivable to long-term note receivable | 0 | 8,124 |
Contribution to equity method investment | $ 133,893 | $ 0 |
CONSOLIDATED STATEMENTS OF CAS7
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Statement of Cash Flows [Abstract] | ||
Cash settlements on derivatives, net (commodity hedges) | $ 36.4 | $ 146.5 |
Organization
Organization | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization | Organization Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS. We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are currently related to production located offshore Ghana. |
Accounting Policies
Accounting Policies | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Accounting Policies | Accounting Policies General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2017 , the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2017 , the consolidated results of operations for the three and nine months ended September 30, 2017 and 2016 , and the consolidated cash flows for the nine months ended September 30, 2017 and 2016 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2016 , included in our annual report on Form 10-K. Investment in Corporate Joint Venture Kosmos held a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercised significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis of assets contributed and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and nine month periods ended September 30, 2017 we recognized $4.8 million and $11.2 million , respectively, related to our share of losses in KBSL. As of September 30, 2017 , our investment in KBSL was $122.7 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $6.4 million as of September 30, 2017 , which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL. In October 2017, upon approval, KBSL transferred a 30% working interest in the Cayar offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and will no longer be accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. Cash, Cash Equivalents and Restricted Cash September 30, December 31, (In thousands) Cash and cash equivalents $ 164,162 $ 194,057 Restricted cash - current 55,852 24,506 Restricted cash - long-term 15,194 54,632 Total cash, cash equivalents and restricted cash $ 235,208 $ 273,195 Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six -month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2017 and December 31, 2016 , we had $24.7 million and $24.5 million , respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of September 30, 2017 and December 31, 2016 , we had $31.1 million and zero , respectively, of current restricted cash and $15.2 million and $54.6 million , respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. Inventories Inventories consisted of $68.9 million and $68.1 million of materials and supplies and $5.4 million and $6.3 million of hydrocarbons as of September 30, 2017 and December 31, 2016 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of nil and $15.2 million during the nine months ended September 30, 2017 and 2016 , respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. Recent Accounting Standards Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 9 Months Ended |
Sep. 30, 2017 | |
Acquisitions and Divestitures | |
Acquisitions and Divestitures | Acquisitions and Divestitures In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in KBSL, our majority owned affiliate company which held a 60% participating interest in the Senegal Blocks. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million . However, we agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Senegal Blocks. The transaction between BP and Timis was completed and KBSL’s participating interest in these blocks remains at 60% . In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive a $228 million exploration and appraisal carry (increased from $221 million upon completion of the transfer of a 30% working interest to BP Senegal Investments Limited), up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discoveries and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date. In November 2015, we entered into a line of credit agreement with Timis, whereby Timis had the right to draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal Blocks petroleum agreements. The line of credit agreement was terminated in April 2017 when Timis entered into an agreement with BP to acquire Timis' 30% participating interest in the Senegal Blocks. As a result of the termination of this credit agreement, Kosmos received $16 million in August 2017 representing payment in full of outstanding amounts drawn on the line of credit. In September 2017, we closed a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we will reimburse a portion of past and interim period costs and partially carry future costs. In October 2017, we entered into an agreement to acquire all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which holds an 85% paying interest ( 80.75% revenue interest) in the Ceiba Field and Okume Complex assets, through a joint venture with an affiliate of Trident Energy ("Trident"). Under the terms of the ag r eement, Kosmos and Trident will each own 50% of Hess International Petroleum Inc. Kosmos will be primarily responsible for exploration and subsurface evaluation while Trident will primarily be responsible for production operations and optimization. The transaction expands our position in the Gulf of Guinea and provides immediate cash flow through existing production with potential to increase existing production and also provides step-out exploration opportunities with potential tie-back through existing infrastructure. The gross acquisition price is $650 million effective as of January 1, 2017 . Kosmos is expected to pay net cash consideration of approximately $240 million at close, subject to post-closing adjustments, with a combination of cash on hand and availability under the Facility. The transaction is expected to close by year end, subject to customary closing conditions, and will be accounted for as an equity method investment. In October 2017, we also entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. Ratification of the petroleum contracts by the President of Equatorial Guinea is expected by the end of the year. We presently have an 80% interest and are the operator in all three blocks, but pursuant to an agreement with Trident we expect to assign a 40% interest in the blocks to an affiliate of Trident after completion of the Hess transaction. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. Upon closing of the Hess transaction and the assignment of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol. |
Joint Interest Billings
Joint Interest Billings | 9 Months Ended |
Sep. 30, 2017 | |
Joint Interest Billings | |
Joint Interest Billings | Joint Interest Billings The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur. In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of September 30, 2017 and December 31, 2016 , the joint interest billing receivables due from GNPC for the TEN development costs were $1.6 million and zero , respectively, which are classified as current and $47.5 million and $44.0 million , respectively, which are classified as long-term on the consolidated balance sheets. |
Property and Equipment
Property and Equipment | 9 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment Property and equipment is stated at cost and consisted of the following: September 30, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,371,641 $ 1,385,331 Unproved properties 651,921 919,056 Support equipment and facilities 1,391,613 1,386,448 Total oil and gas properties 3,415,175 3,690,835 Accumulated depletion (1,163,198 ) (989,946 ) Oil and gas properties, net 2,251,977 2,700,889 Other property 38,124 37,186 Accumulated depreciation (31,700 ) (29,183 ) Other property, net 6,424 8,003 Property and equipment, net $ 2,258,401 $ 2,708,892 We recorded depletion expense of $70.9 million and $15.6 million for the three months ended September 30, 2017 and 2016 , respectively, and $173.3 million and $59.6 million for the nine months ended September 30, 2017 and 2016 , respectively. |
Suspended Well Costs
Suspended Well Costs | 9 Months Ended |
Sep. 30, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Suspended Well Costs | Suspended Well Costs The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2017 . The table excludes $24.5 million in costs that were capitalized and subsequently expensed during the same period. September 30, (In thousands) Beginning balance $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 67,543 Reclassification due to determination of proved reserves — Divestitures(1) (206,400 ) Contribution of oil and gas property to equity method investment (131,764 ) Capitalized exploratory well costs charged to expense — Ending balance $ 463,842 __________________________________ (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP. The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: September 30, 2017 December 31, 2016 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 65,606 $ 279,809 Exploratory well costs capitalized for a period of one to two years 184,486 244,804 Exploratory well costs capitalized for a period of three to eight years 213,750 209,850 Ending balance $ 463,842 $ 734,463 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 6 5 As of September 30, 2017 , the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak (formerly Teak-1 and Teak-2) and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Teranga discovery in the Cayar Offshore Profond block offshore Senegal. Mahogany and Teak Discoveries — In October 2017, the Jubilee Unit was expanded to include the Mahogany and Teak discoveries. As part of the expansion of the Jubilee Unit, the capitalized exploratory well costs will be moved to proved property in the fourth quarter of 2017. Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy. Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation. Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design (FEED) process. Following additional technical and commercial evaluation, a decision regarding commerciality will be made. BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made. Teranga Discovery — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made. |
Debt
Debt | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Debt | Debt September 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 600,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,125,000 1,375,000 Unamortized deferred financing costs and discounts(1) (44,648 ) (53,126 ) Long-term debt, net $ 1,080,352 $ 1,321,874 __________________________________ (1) Includes $25.0 million and $30.3 million of unamortized deferred financing costs related to the Facility and $19.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2017 and December 31, 2016 , respectively. Facility In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. In August 2017 , following the lender’s waiver of the September 30, 2017 semi-annual redetermination, the borrowing base under our Facility will remain at $1.3 billion . The borrowing base calculation includes value related to the Jubilee and TEN fields. As of September 30, 2017 , borrowings under the Facility totaled $600.0 million and the undrawn availability under the Facility was $700.8 million . The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in March 2014, expires on March 31, 2018, however, the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of September 30, 2017 , we had no letters of credit issued under the Facility. We were in compliance with the financial covenants contained in the Facility as of September 30, 2017 (the most recent assessment date). The Facility contains customary cross default provisions. Corporate Revolver In June 2015 , we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million , extending the maturity date to November 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of September 30, 2017 , we have $3.2 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of the consolidated balance sheets. As of September 30, 2017 , there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million . We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility In July 2016 , we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019 . During the first quarter of 2017, the LC Facility size was increased to $115.0 million . In April 2017, we reduced the size of our LC Facility to $70 million . As of September 30, 2017 , there were eight outstanding letters of credit totaling $60.3 million under the LC Facility. The LC Facility contains customary cross default provisions. 7.875% Senior Secured Notes due 2021 During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued. The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. At September 30, 2017 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ 1,125,000 $ — $ — $ 377 $ 404,971 $ 719,652 $ — __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2017 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2017 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period October 1, 2017 through December 31, 2017 . Interest and other financing costs, net Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Interest expense $ 22,961 $ 23,057 $ 68,934 $ 65,829 Amortization—deferred financing costs 2,551 2,551 7,653 7,653 Capitalized interest (8,563 ) (15,545 ) (25,498 ) (49,575 ) Deferred interest 662 663 1,610 406 Interest income (745 ) (485 ) (2,485 ) (1,319 ) Other, net 1,612 825 4,515 7,274 Interest and other financing costs, net $ 18,478 $ 11,066 $ 54,729 $ 30,268 |
Derivative Financial Instrument
Derivative Financial Instruments | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Derivative Financial Instruments We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes. We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures. Oil Derivative Contracts The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 30, 2017 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Deferred Premium Term Type of Contract MBbl Payable, Net Swap Sold Put Floor Ceiling Call 2017: October — December Swap with puts/calls 503 $ 2.13 $ 72.50 $ 55.00 $ — $ — $ 90.00 October — December Swap with puts 503 — 64.95 50.00 — — — October — December Three-way collars 1,006 1.72 — 30.00 45.00 60.00 — October — December Sold calls(1) 500 — — — — 85.00 — 2018: January — December Swap with puts 2,000 $ — $ 54.32 $ 40.00 $ — $ — $ — January — December Three-way collars 2,913 0.74 — 41.57 56.57 65.90 — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December Three-way collars 4,500 $ 0.26 $ — $ 40.00 $ 50.00 $ 62.78 $ — January — December Sold calls(1) 913 — — — — 80.00 — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. In October 2017, we entered into costless swap contracts for 1.0 MMBbl from January 2018 through June 2018 with a fixed price of $57.25 per barrel, and costless swaps and sold put contracts for 2.0 MMBbl from July 2018 through December 2018 with a weighted average fixed price of $57.96 per barrel and a weighted average sold put price of $45.00 per barrel. The contracts are indexed to Dated Brent prices. Interest Rate Derivative Contracts The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of September 30, 2017 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) October 2017 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % The following tables disclose the Company’s derivative instruments as of September 30, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three and nine months ended September 30, 2017 and 2016 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location September 30, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 15,811 $ 31,698 Interest rate Derivatives assets—current 389 — Commodity(2) Derivatives assets—long-term 2,107 3,226 Interest rate Derivatives assets—long-term 305 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (9,016 ) (19,163 ) Interest rate Derivatives liabilities—current — (529 ) Commodity(4) Derivatives liabilities—long-term (7,256 ) (14,123 ) Total derivatives not designated as hedging instruments $ 2,340 $ 1,691 __________________________________ (1) Includes net deferred premiums payable of $2.0 million and $3.9 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (2) Includes net deferred premiums payable of $0.7 million and $2.5 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (3) Includes zero and $30.9 thousand as of September 30, 2017 and December 31, 2016 , respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $4.4 million and $6.2 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (4) Includes net deferred premiums payable of $2.1 million and $0.6 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Nine Months Ended September 30, September 30, Type of Contract Location of Gain/(Loss) 2017 2016 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (6,221 ) $ 344 $ (10,781 ) $ (712 ) Commodity Derivatives, net (26,864 ) 16,891 36,404 (33,752 ) Interest rate Interest expense 64 760 301 (2,715 ) Total derivatives not designated as hedging instruments $ (33,021 ) $ 17,995 $ 25,924 $ (37,179 ) __________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts. Offsetting of Derivative Assets and Derivative Liabilities Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2017 and December 31, 2016 , there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy: • Level 1 — quoted prices for identical assets or liabilities in active markets. • Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) September 30,2017 Assets: Commodity derivatives $ — $ 17,918 $ — $ 17,918 Interest rate derivatives — 694 — 694 Liabilities: Commodity derivatives — (16,272 ) — (16,272 ) Interest rate derivatives — — — — Total $ — $ 2,340 $ — $ 2,340 December 31,2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286 ) — (33,286 ) Interest rate derivatives — (529 ) — (529 ) Total $ — $ 1,691 $ — $ 1,691 The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs. Commodity Derivatives Our commodity derivatives represent crude oil four-way collars, three-way collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap, and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market. Debt The following table presents the carrying values and fair values at September 30, 2017 and December 31, 2016 : September 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 506,594 $ 545,874 $ 503,716 $ 528,938 Facility 600,000 600,000 850,000 850,000 Total $ 1,106,594 $ 1,145,874 $ 1,353,716 $ 1,378,938 The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods. |
Equity-based Compensation
Equity-based Compensation | 9 Months Ended |
Sep. 30, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-based Compensation | Equity-based Compensation Restricted Stock Awards and Restricted Stock Units We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.6 million and $9.2 million during the three months ended September 30, 2017 and 2016 , respectively, and $29.9 million and $30.4 million during the nine months ended September 30, 2017 and 2016, respectively. The total tax benefit for the three months ended September 30, 2017 and 2016 was $3.2 million and $3.0 million , respectively, and $9.9 million and $9.9 million during the nine months ended September 30, 2017 and 2016 , respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of $0.2 million and $1.0 million for the three months ended September 30, 2017 and 2016 , respectively, and $3.1 million and $5.3 million during the nine months ended September 30, 2017 and 2016 , respectively. The fair value of awards vested during the three months ended September 30, 2017 and 2016 was approximately $1.4 million and $2.4 million , respectively, and $20.7 million and $13.4 million during the nine months ended September 30, 2017 and 2016 , respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock. The following table reflects the outstanding restricted stock awards as of September 30, 2017 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2016 488 $ 8.83 Granted — — Forfeited — — Vested (268 ) 8.97 Outstanding at September 30, 2017 220 8.64 The following table reflects the outstanding restricted stock units as of September 30, 2017 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016 4,160 $ 6.91 7,194 $ 12.29 Granted 2,063 6.41 2,170 9.50 Forfeited (123 ) 7.03 (27 ) 7.76 Vested (1,864 ) 7.50 (894 ) 15.44 Outstanding at September 30, 2017 4,236 6.40 8,443 11.26 As of September 30, 2017 , total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $33.5 million over a weighted average period of 1.48 years . At September 30, 2017 , the Company had approximately 3.4 million shares that remain available for issuance under the LTIP. For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value was $9.45 per award for restricted stock awards and ranged from $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and was 55.0% for the restricted stock awards and ranged from 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and was 0.5% for restricted stock awards and ranged from 0.5% to 1.4% for restricted stock units. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets. Income (loss) before income taxes is composed of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Bermuda $ (17,740 ) $ (15,989 ) $ (50,680 ) $ (47,212 ) United States 1,437 1,132 4,231 5,447 Foreign—other (48,617 ) (37,404 ) (9,863 ) (195,379 ) Income (loss) before income taxes $ (64,920 ) $ (52,261 ) $ (56,312 ) $ (237,144 ) Our effective tax rate for the three months ended September 30, 2017 and 2016 is 2% and 14% , respectively. For the nine months ended, September 30, 2017 and 2016 , our effective tax rate was 79% and 4% , respectively. The effective tax rate is impacted by the effect of equity-based compensation tax shortfalls and windfalls equal to the difference between the income tax benefit recognized for financial statement purposes and the income tax benefit realized for tax return purposes and by non-deductible expenditures associated with the damage to the turret bearing, due to the expected recovery from insurance proceeds. Any such insurance recoveries would not be subject to income tax. The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2016 and in the United States, to federal income tax examinations for tax years 2013 through 2016. As of September 30, 2017 , the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense. |
Net Loss Per Share
Net Loss Per Share | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Net Loss Per Share | Net Loss Per Share The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Numerator: Net loss $ (63,405 ) $ (59,763 ) $ (100,713 ) $ (227,080 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (63,405 ) (59,763 ) (100,713 ) (227,080 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (63,405 ) $ (59,763 ) $ (100,713 ) $ (227,080 ) Denominator: Weighted average number of shares outstanding: Basic 389,058 386,026 388,114 385,130 Restricted stock awards and units(1)(2) — — — — Diluted 389,058 386,026 388,114 385,130 Net loss per share: Basic $ (0.16 ) $ (0.15 ) $ (0.26 ) $ (0.59 ) Diluted $ (0.16 ) $ (0.15 ) $ (0.26 ) $ (0.59 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 12.9 million and 12.0 million for the three and nine months ended September 30, 2017 and 2016 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive . |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year. We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $228 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea, Mauritania and Western Sahara, we have 3D seismic requirements of 6,000 square kilometers, 7,600 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required. The Equatorial Guinea block commitments are subject to ratification by the President of Equatorial Guinea. In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the ENSCO DS-12 (formerly the Atwood Achiever) drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. During the first quarter of 2017, KEV made a rate recovery payment of $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election was exercised plus certain administrative costs which was recorded as exploration expense. Future minimum rental commitments under our leases at September 30, 2017 , are as follows: Payments Due By Year(1) Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(3) $ 9,910 $ 1,158 $ 4,736 $ 3,951 $ 65 $ — $ — ENSCO DS-12 drilling rig contract 25,585 25,585 — — — — — __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from October 1, 2017 through December 31, 2017 . (3) Primarily relates to corporate office and foreign office leases. |
Additional Financial Informatio
Additional Financial Information | 9 Months Ended |
Sep. 30, 2017 | |
Additional Financial Information | |
Additional Financial Information | Additional Financial Information Accrued Liabilities Accrued liabilities consisted of the following: September 30, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 130,543 $ 76,194 General and administrative expenses 26,823 31,243 Interest 9,180 17,247 Income taxes 3,145 2,579 Taxes other than income 3,941 1,914 Other 172 529 $ 173,804 $ 129,706 Other Income, Net Other income, net consisted of zero Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended September 30, 2017 and 2016 , and $58.7 million and $20.0 million for the nine months ended September 30, 2017 and 2016 , respectively. Our LOPI coverage for this incident ended in May 2017. Oil and gas production Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero for the three months ended September 30, 2017 and 2016 , and $17.1 million and zero , for the nine months ended September 30, 2017 and 2016 , respectively. Facilities Insurance Modifications, Net Facilities insurance modifications, net consists of costs associated with the conversion of the Jubilee FPSO to a permanently spread moored facility, net of related insurance proceeds. Other Expenses, Net Other expenses, net incurred during the period is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Inventory write-off $ (500 ) $ — $ 47 $ 15,177 (Gain) loss on insurance settlements — (3,047 ) (461 ) (4,003 ) Disputed charges and related costs 821 1,826 3,260 1,826 Loss on equity method investment 4,804 — 11,230 — Other, net (88 ) 426 157 768 Other expenses, net $ 5,037 $ (795 ) $ 14,233 $ 13,768 The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are properly chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement. |
Accounting Policies (Policies)
Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
General | General The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2017 , the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2017 , the consolidated results of operations for the three and nine months ended September 30, 2017 and 2016 , and the consolidated cash flows for the nine months ended September 30, 2017 and 2016 . The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2016 , included in our annual report on Form 10-K. |
Investment in Corporate Joint Venture | Investment in Corporate Joint Venture Kosmos held a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercised significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis of assets contributed and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and nine month periods ended September 30, 2017 we recognized $4.8 million and $11.2 million , respectively, related to our share of losses in KBSL. As of September 30, 2017 , our investment in KBSL was $122.7 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $6.4 million as of September 30, 2017 , which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL. In October 2017, upon approval, KBSL transferred a 30% working interest in the Cayar offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and will no longer be accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. |
Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted Cash September 30, December 31, (In thousands) Cash and cash equivalents $ 164,162 $ 194,057 Restricted cash - current 55,852 24,506 Restricted cash - long-term 15,194 54,632 Total cash, cash equivalents and restricted cash $ 235,208 $ 273,195 Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six -month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2017 and December 31, 2016 , we had $24.7 million and $24.5 million , respectively, in current restricted cash to meet this requirement. In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of September 30, 2017 and December 31, 2016 , we had $31.1 million and zero , respectively, of current restricted cash and $15.2 million and $54.6 million , respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. |
Inventories | Inventories Inventories consisted of $68.9 million and $68.1 million of materials and supplies and $5.4 million and $6.3 million of hydrocarbons as of September 30, 2017 and December 31, 2016 , respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of nil and $15.2 million during the nine months ended September 30, 2017 and 2016 , respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows. Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs. |
Recent Accounting Standards | Recent Accounting Standards Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard. |
Accounting Policies (Tables)
Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Schedule of Cash, Cash Equivalents and Restricted Cash | September 30, December 31, (In thousands) Cash and cash equivalents $ 164,162 $ 194,057 Restricted cash - current 55,852 24,506 Restricted cash - long-term 15,194 54,632 Total cash, cash equivalents and restricted cash $ 235,208 $ 273,195 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property and equipment | Property and equipment is stated at cost and consisted of the following: September 30, December 31, (In thousands) Oil and gas properties: Proved properties $ 1,371,641 $ 1,385,331 Unproved properties 651,921 919,056 Support equipment and facilities 1,391,613 1,386,448 Total oil and gas properties 3,415,175 3,690,835 Accumulated depletion (1,163,198 ) (989,946 ) Oil and gas properties, net 2,251,977 2,700,889 Other property 38,124 37,186 Accumulated depreciation (31,700 ) (29,183 ) Other property, net 6,424 8,003 Property and equipment, net $ 2,258,401 $ 2,708,892 |
Suspended Well Costs (Tables)
Suspended Well Costs (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of capitalized exploratory well costs | The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2017 . The table excludes $24.5 million in costs that were capitalized and subsequently expensed during the same period. September 30, (In thousands) Beginning balance $ 734,463 Additions to capitalized exploratory well costs pending the determination of proved reserves 67,543 Reclassification due to determination of proved reserves — Divestitures(1) (206,400 ) Contribution of oil and gas property to equity method investment (131,764 ) Capitalized exploratory well costs charged to expense — Ending balance $ 463,842 __________________________________ (1) Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP. |
Schedule of aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year | The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling: September 30, 2017 December 31, 2016 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 65,606 $ 279,809 Exploratory well costs capitalized for a period of one to two years 184,486 244,804 Exploratory well costs capitalized for a period of three to eight years 213,750 209,850 Ending balance $ 463,842 $ 734,463 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 6 5 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of debt | September 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 600,000 $ 850,000 Senior Notes 525,000 525,000 Total 1,125,000 1,375,000 Unamortized deferred financing costs and discounts(1) (44,648 ) (53,126 ) Long-term debt, net $ 1,080,352 $ 1,321,874 __________________________________ (1) Includes $25.0 million and $30.3 million of unamortized deferred financing costs related to the Facility and $19.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2017 and December 31, 2016 , respectively. |
Schedule of estimated repayments of debt | At September 30, 2017 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Principal debt repayments(1) $ 1,125,000 $ — $ — $ 377 $ 404,971 $ 719,652 $ — __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2017 , our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2017 , there were no borrowings under the Corporate Revolver. (2) Represents payments for the period October 1, 2017 through December 31, 2017 . |
Schedule of interest and other financing costs, net | Interest and other financing costs, net incurred during the periods is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Interest expense $ 22,961 $ 23,057 $ 68,934 $ 65,829 Amortization—deferred financing costs 2,551 2,551 7,653 7,653 Capitalized interest (8,563 ) (15,545 ) (25,498 ) (49,575 ) Deferred interest 662 663 1,610 406 Interest income (745 ) (485 ) (2,485 ) (1,319 ) Other, net 1,612 825 4,515 7,274 Interest and other financing costs, net $ 18,478 $ 11,066 $ 54,729 $ 30,268 |
Derivative Financial Instrume27
Derivative Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of oil derivative contracts | The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of September 30, 2017 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Dated Brent Price per Bbl Deferred Premium Term Type of Contract MBbl Payable, Net Swap Sold Put Floor Ceiling Call 2017: October — December Swap with puts/calls 503 $ 2.13 $ 72.50 $ 55.00 $ — $ — $ 90.00 October — December Swap with puts 503 — 64.95 50.00 — — — October — December Three-way collars 1,006 1.72 — 30.00 45.00 60.00 — October — December Sold calls(1) 500 — — — — 85.00 — 2018: January — December Swap with puts 2,000 $ — $ 54.32 $ 40.00 $ — $ — $ — January — December Three-way collars 2,913 0.74 — 41.57 56.57 65.90 — January — December Four-way collars 3,000 1.06 — 40.00 50.00 61.33 70.00 January — December Sold calls(1) 2,000 — — — — 65.00 — 2019: January — December Three-way collars 4,500 $ 0.26 $ — $ 40.00 $ 50.00 $ 62.78 $ — January — December Sold calls(1) 913 — — — — 80.00 — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. |
Schedule of interest rate derivative contracts | The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of September 30, 2017 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) October 2017 — December 2018 Capped swap 1-month LIBOR $ 200,000 1.23 % 3.00 % |
Schedule of derivative instruments by balance sheet location | The following tables disclose the Company’s derivative instruments as of September 30, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three and nine months ended September 30, 2017 and 2016 , respectively: Estimated Fair Value Asset (Liability) Type of Contract Balance Sheet Location September 30, December 31, (In thousands) Derivatives not designated as hedging instruments: Derivative assets: Commodity(1) Derivatives assets—current $ 15,811 $ 31,698 Interest rate Derivatives assets—current 389 — Commodity(2) Derivatives assets—long-term 2,107 3,226 Interest rate Derivatives assets—long-term 305 582 Derivative liabilities: Commodity(3) Derivatives liabilities—current (9,016 ) (19,163 ) Interest rate Derivatives liabilities—current — (529 ) Commodity(4) Derivatives liabilities—long-term (7,256 ) (14,123 ) Total derivatives not designated as hedging instruments $ 2,340 $ 1,691 __________________________________ (1) Includes net deferred premiums payable of $2.0 million and $3.9 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (2) Includes net deferred premiums payable of $0.7 million and $2.5 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (3) Includes zero and $30.9 thousand as of September 30, 2017 and December 31, 2016 , respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $4.4 million and $6.2 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. (4) Includes net deferred premiums payable of $2.1 million and $0.6 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016 , respectively. |
Schedule of derivative instruments by location of gain/(loss) | Amount of Gain/(Loss) Amount of Gain/(Loss) Three Months Ended Nine Months Ended September 30, September 30, Type of Contract Location of Gain/(Loss) 2017 2016 2017 2016 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ (6,221 ) $ 344 $ (10,781 ) $ (712 ) Commodity Derivatives, net (26,864 ) 16,891 36,404 (33,752 ) Interest rate Interest expense 64 760 301 (2,715 ) Total derivatives not designated as hedging instruments $ (33,021 ) $ 17,995 $ 25,924 $ (37,179 ) __________________________________ (1) Amounts represent the change in fair value of our provisional oil sales contracts. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Fair Value Disclosures [Abstract] | |
Schedule of Company's assets and liabilities that are measured at fair value on a recurring basis | The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016 , for each fair value hierarchy level: Fair Value Measurements Using: Quoted Prices in Active Markets for Significant Other Significant Identical Assets Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Total (In thousands) September 30,2017 Assets: Commodity derivatives $ — $ 17,918 $ — $ 17,918 Interest rate derivatives — 694 — 694 Liabilities: Commodity derivatives — (16,272 ) — (16,272 ) Interest rate derivatives — — — — Total $ — $ 2,340 $ — $ 2,340 December 31,2016 Assets: Commodity derivatives $ — $ 34,924 $ — $ 34,924 Interest rate derivatives — 582 — 582 Liabilities: Commodity derivatives — (33,286 ) — (33,286 ) Interest rate derivatives — (529 ) — (529 ) Total $ — $ 1,691 $ — $ 1,691 |
Schedule of carrying values and fair values of financial instruments that are not carried at fair value | The following table presents the carrying values and fair values at September 30, 2017 and December 31, 2016 : September 30, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 506,594 $ 545,874 $ 503,716 $ 528,938 Facility 600,000 600,000 850,000 850,000 Total $ 1,106,594 $ 1,145,874 $ 1,353,716 $ 1,378,938 |
Equity-based Compensation (Tabl
Equity-based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Restricted stock awards | |
Equity-based Compensation | |
Schedule of plan activity | The following table reflects the outstanding restricted stock awards as of September 30, 2017 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2016 488 $ 8.83 Granted — — Forfeited — — Vested (268 ) 8.97 Outstanding at September 30, 2017 220 8.64 |
Restricted stock units | |
Equity-based Compensation | |
Schedule of plan activity | The following table reflects the outstanding restricted stock units as of September 30, 2017 : Weighted- Market / Service Weighted- Service Vesting Average Vesting Average Restricted Stock Grant-Date Restricted Stock Grant-Date Units Fair Value Units Fair Value (In thousands) (In thousands) Outstanding at December 31, 2016 4,160 $ 6.91 7,194 $ 12.29 Granted 2,063 6.41 2,170 9.50 Forfeited (123 ) 7.03 (27 ) 7.76 Vested (1,864 ) 7.50 (894 ) 15.44 Outstanding at September 30, 2017 4,236 6.40 8,443 11.26 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of components of income (loss) before income taxes | Income (loss) before income taxes is composed of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Bermuda $ (17,740 ) $ (15,989 ) $ (50,680 ) $ (47,212 ) United States 1,437 1,132 4,231 5,447 Foreign—other (48,617 ) (37,404 ) (9,863 ) (195,379 ) Income (loss) before income taxes $ (64,920 ) $ (52,261 ) $ (56,312 ) $ (237,144 ) |
Net Loss Per Share (Tables)
Net Loss Per Share (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of reconciliation between net income and amounts used to compute basic and diluted EPS | The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 Numerator: Net loss $ (63,405 ) $ (59,763 ) $ (100,713 ) $ (227,080 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (63,405 ) (59,763 ) (100,713 ) (227,080 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (63,405 ) $ (59,763 ) $ (100,713 ) $ (227,080 ) Denominator: Weighted average number of shares outstanding: Basic 389,058 386,026 388,114 385,130 Restricted stock awards and units(1)(2) — — — — Diluted 389,058 386,026 388,114 385,130 Net loss per share: Basic $ (0.16 ) $ (0.15 ) $ (0.26 ) $ (0.59 ) Diluted $ (0.16 ) $ (0.15 ) $ (0.26 ) $ (0.59 ) __________________________________ (1) Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position. (2) We excluded outstanding restricted stock awards and units of 12.9 million and 12.0 million for the three and nine months ended September 30, 2017 and 2016 , respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive . |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of estimated future minimum commitments | Future minimum rental commitments under our leases at September 30, 2017 , are as follows: Payments Due By Year(1) Total 2017(2) 2018 2019 2020 2021 Thereafter (In thousands) Operating leases(3) $ 9,910 $ 1,158 $ 4,736 $ 3,951 $ 65 $ — $ — ENSCO DS-12 drilling rig contract 25,585 25,585 — — — — — __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from October 1, 2017 through December 31, 2017 . (3) Primarily relates to corporate office and foreign office leases. |
Additional Financial Informat33
Additional Financial Information (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Additional Financial Information | |
Schedule of accrued liabilities | Accrued liabilities consisted of the following: September 30, December 31, (In thousands) Accrued liabilities: Exploration, development and production $ 130,543 $ 76,194 General and administrative expenses 26,823 31,243 Interest 9,180 17,247 Income taxes 3,145 2,579 Taxes other than income 3,941 1,914 Other 172 529 $ 173,804 $ 129,706 |
Schedule of Other expenses, net incurred | Other expenses, net incurred during the period is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (In thousands) Inventory write-off $ (500 ) $ — $ 47 $ 15,177 (Gain) loss on insurance settlements — (3,047 ) (461 ) (4,003 ) Disputed charges and related costs 821 1,826 3,260 1,826 Loss on equity method investment 4,804 — 11,230 — Other, net (88 ) 426 157 768 Other expenses, net $ 5,037 $ (795 ) $ 14,233 $ 13,768 |
Organization (Details)
Organization (Details) | 9 Months Ended |
Sep. 30, 2017segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of reportable segments | 1 |
Accounting Policies (Details)
Accounting Policies (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
Oct. 31, 2017 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | |
Investment in Corporate Joint Venture | |||||||
Loss on equity method investment | $ 4,804,000 | $ 0 | $ 11,230,000 | $ 0 | |||
Equity method investment | 122,664,000 | 122,664,000 | $ 0 | ||||
Related party receivables | 6,446,000 | 6,446,000 | 0 | ||||
Cash, Cash Equivalents and Restricted Cash | |||||||
Cash and cash equivalents | 164,162,000 | 164,162,000 | 194,057,000 | ||||
Restricted cash - current | 55,852,000 | 55,852,000 | 24,506,000 | ||||
Restricted cash - long-term | 15,194,000 | 15,194,000 | 54,632,000 | ||||
Total cash, cash equivalents and restricted cash | 235,208,000 | 186,260,000 | 235,208,000 | 186,260,000 | 273,195,000 | $ 310,862,000 | |
Inventories | |||||||
Materials and supplies inventory | 68,900,000 | 68,900,000 | 68,100,000 | ||||
Hydrocarbons inventory | 5,400,000 | 5,400,000 | 6,300,000 | ||||
Write down of materials and supplies | $ (500,000) | $ 0 | $ 47,000 | $ 15,177,000 | |||
Senior Notes | 7.875% senior notes due 2021 | |||||||
Cash, Cash Equivalents and Restricted Cash | |||||||
Interest rate | 7.875% | 7.875% | |||||
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest | |||||||
Cash, Cash Equivalents and Restricted Cash | |||||||
Restricted cash - current | $ 24,700,000 | $ 24,700,000 | 24,500,000 | ||||
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments | 6 months | ||||||
Restricted Cash | Petroleum agreements - performance guarantees | |||||||
Cash, Cash Equivalents and Restricted Cash | |||||||
Restricted cash - current | 31,100,000 | $ 31,100,000 | 0 | ||||
Restricted cash - long-term | $ 15,200,000 | $ 15,200,000 | $ 54,600,000 | ||||
Kosmos BP Senegal Limited | |||||||
Investment in Corporate Joint Venture | |||||||
Ownership percentage | 50.01% | 50.01% | |||||
Loss on equity method investment | $ 4,800,000 | $ 11,200,000 | |||||
Equity method investment | 122,700,000 | 122,700,000 | |||||
Related party receivables | $ 6,400,000 | $ 6,400,000 | |||||
Subsequent Event | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Kosmos BP Senegal Limited | |||||||
Investment in Corporate Joint Venture | |||||||
Working interest | 30.00% | ||||||
Subsequent Event | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | BP Senegal Investments Limited | Kosmos BP Senegal Limited | |||||||
Investment in Corporate Joint Venture | |||||||
Working interest transferred | 30.00% |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) bbl in Billions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||||
Oct. 31, 2017USD ($)km²block | Sep. 30, 2017USD ($)$ / bblbbl | Aug. 31, 2017USD ($) | Jun. 30, 2017 | Feb. 28, 2017 | Jan. 31, 2017instrument | Dec. 31, 2016USD ($) | Mar. 31, 2017USD ($) | Sep. 30, 2017USD ($)$ / bblbbl | Nov. 30, 2015USD ($) | |
Mauritania And Senegal Offshore Block | Maximum | ||||||||||
Acquisitions and Divestitures | ||||||||||
Spending by third party for exploration and appraisal costs | $ 228,000,000 | |||||||||
Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 60.00% | |||||||||
Sales and purchase agreement | Ceiba Field and Okume Complex Assets | Hess | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Gross acquisition price | $ 650,000,000 | |||||||||
Net cash consideration, to be paid | $ 240,000,000 | |||||||||
Sales and purchase agreement | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 60.00% | 65.00% | ||||||||
Percentage increase in equity in each contract area | 5.00% | |||||||||
Sales and purchase agreement | Hess | Ceiba Field and Okume Complex Assets | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Ownership percentage | 50.00% | |||||||||
Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block | ||||||||||
Acquisitions and Divestitures | ||||||||||
Reduction in unproved property | $ 221,900,000 | $ 221,900,000 | ||||||||
Timis | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 30.00% | |||||||||
Petroleum Agreement | Blocks EG-21, S and W | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 80.00% | |||||||||
Number of blocks | block | 3 | |||||||||
Area of petroleum exploration | km² | 6,000 | |||||||||
3D seismic requirements | km² | 6,000 | |||||||||
Assignment Agreement | Blocks EG-21, S and W | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 40.00% | |||||||||
BP | Farm-out agreements | Block C6 Block C8 Block C12 and Block C13 Mauritania | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participation interest acquired | 62.00% | |||||||||
Number of blocks covered by farm-out agreements | instrument | 4 | |||||||||
BP | Farm-out agreements | Mauritania And Senegal Offshore Block | Maximum | ||||||||||
Acquisitions and Divestitures | ||||||||||
Amount of potential and variable consideration per barrel | $ / bbl | 2 | 2 | ||||||||
Number of barrels | bbl | 1 | 1 | ||||||||
BP | Sales and purchase agreement | Kosmos BP Senegal Limited | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participation interest acquired | 49.99% | |||||||||
BP | Sales and purchase agreement and farm-out agreements | Mauritania And Senegal Offshore Block | ||||||||||
Acquisitions and Divestitures | ||||||||||
Upfront amount of cash received | $ 162,000,000 | |||||||||
Spending by third party for exploration and appraisal costs | $ 228,000,000 | |||||||||
Spending by third party for exploration and appraisal costs, initial estimate | 221,000,000 | |||||||||
Spending by third party for Kosmos' development costs | $ 533,000,000 | |||||||||
BP Senegal Investments Limited | Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Working interest transferred | 30.00% | |||||||||
Timis | ||||||||||
Acquisitions and Divestitures | ||||||||||
Line of credit receivable | $ 30,000,000 | |||||||||
Amount received from contract termination | $ 16,000,000 | |||||||||
Timis | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 30.00% | |||||||||
Timis | Farm-in agreement | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | ||||||||||
Acquisitions and Divestitures | ||||||||||
Maximum cost per contingent exploration well | $ 120,000,000 | |||||||||
Tullow | Farm-in agreement | Block C18 offshore Mauritania | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 15.00% | |||||||||
Hess | Ceiba Field and Okume Complex Assets | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Paying interest, percentage | 85.00% | |||||||||
Revenue interest, percentage | 80.75% | |||||||||
Trident | Sales and purchase agreement | Hess | Ceiba Field and Okume Complex Assets | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Ownership percentage | 50.00% | |||||||||
Trident | Assignment Agreement | Blocks EG-21, S and W | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Participating interests | 40.00% | |||||||||
Participating interest to be assigned | 40.00% | |||||||||
GEPetrol | Petroleum Agreement | Blocks EG-21, S and W | Subsequent Event | ||||||||||
Acquisitions and Divestitures | ||||||||||
Carried participating interest percentage | 20.00% | |||||||||
Percentage Converted From Carried To Participating | 20.00% |
Joint Interest Billings (Detail
Joint Interest Billings (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2014 | Sep. 30, 2017 | Dec. 31, 2016 | |
Joint interest billings | |||
Joint interest billings, net | $ 75,373,000 | $ 63,249,000 | |
Long-term receivables - joint interest billings | 47,525,000 | 45,663,000 | |
TEN Discoveries | GNPC | |||
Joint interest billings | |||
Joint interest billings, net | 1,600,000 | 0 | |
Long-term receivables - joint interest billings | $ 47,500,000 | $ 44,000,000 | |
TEN Discoveries | GNPC | |||
Joint interest billings | |||
GNPC's paying interest | 5.00% |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Oil and gas properties: | |||||
Proved properties | $ 1,371,641 | $ 1,371,641 | $ 1,385,331 | ||
Unproved properties | 651,921 | 651,921 | 919,056 | ||
Support equipment and facilities | 1,391,613 | 1,391,613 | 1,386,448 | ||
Total oil and gas properties | 3,415,175 | 3,415,175 | 3,690,835 | ||
Accumulated depletion | (1,163,198) | (1,163,198) | (989,946) | ||
Oil and gas properties, net | 2,251,977 | 2,251,977 | 2,700,889 | ||
Other property | 38,124 | 38,124 | 37,186 | ||
Accumulated depreciation | (31,700) | (31,700) | (29,183) | ||
Other property, net | 6,424 | 6,424 | 8,003 | ||
Property and equipment, net | 2,258,401 | 2,258,401 | $ 2,708,892 | ||
Depletion expense | $ 70,900 | $ 15,600 | $ 173,300 | $ 59,600 |
Suspended Well Costs (Details)
Suspended Well Costs (Details) $ in Thousands | 9 Months Ended | |||
Sep. 30, 2017USD ($) | Sep. 30, 2017USD ($)project | Dec. 31, 2016USD ($)project | May 31, 2015project | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Capitalized exploratory well costs subsequently expensed in the same period | $ 24,500 | |||
Reconciliation of capitalized exploratory well costs on completed wells | ||||
Beginning balance | 734,463 | |||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 67,543 | |||
Reclassification due to determination of proved reserves | 0 | |||
Divestitures | (206,400) | |||
Contribution of oil and gas property to equity method investment | (131,764) | |||
Capitalized exploratory well costs charged to expense | 0 | |||
Ending balance | 463,842 | |||
Aging of capitalized exploratory well costs and number of projects for which exploratory well costs were capitalized for more than one year | ||||
Exploratory well costs capitalized for a period of one year or less | $ 65,606 | $ 279,809 | ||
Exploratory well costs capitalized for a period of one to two years | 184,486 | 244,804 | ||
Exploratory well costs capitalized for a period of three to eight years | 213,750 | 209,850 | ||
Ending balance | $ 734,463 | $ 463,842 | $ 734,463 | |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project | 6 | 5 | ||
Greater Tortue Discovery | ||||
Projects with exploratory well costs capitalized for more than one year | ||||
Number of additional appraisal wells drilled | project | 2 |
Debt - Schedule of Instruments
Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Debt | ||
Outstanding debt principal | $ 1,125,000 | $ 1,375,000 |
Unamortized issuance costs and discount | (44,648) | (53,126) |
Long-term debt, net | 1,080,352 | 1,321,874 |
Facility | ||
Debt | ||
Outstanding debt principal | 600,000 | 850,000 |
Unamortized issuance costs and discount | (25,000) | (30,300) |
Senior Notes | ||
Debt | ||
Outstanding debt principal | 525,000 | 525,000 |
Unamortized issuance costs and discount | $ (19,600) | $ (22,800) |
Debt - Facility (Details)
Debt - Facility (Details) - Facility - USD ($) | 9 Months Ended | |
Sep. 30, 2017 | Mar. 31, 2014 | |
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 1,500,000,000 | |
Current borrowing capacity | $ 1,300,000,000 | |
Amount outstanding | 600,000,000 | |
Undrawn availability | 700,800,000 | |
Revolving-credit sublimit amount after March 31, 2018 | $ 500,000,000 | |
Availability period of revolving-credit sublimit | 1 month | |
Amount outstanding under letters of credit | $ 0 |
Debt - Corporate Revolver (Deta
Debt - Corporate Revolver (Details) - USD ($) | 1 Months Ended | ||
Jun. 30, 2015 | Sep. 30, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||
Net deferred financing costs | $ 3,194,000 | $ 5,248,000 | |
Corporate Revolver | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 400,000,000 | ||
Percentage of the margin used to calculate commitment fees | 30.00% | ||
Net deferred financing costs | 3,200,000 | ||
Amount outstanding | 0 | ||
Undrawn availability | $ 400,000,000 |
Debt - Revolving Letter of Cred
Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility | Sep. 30, 2017USD ($)instrument | Apr. 30, 2017USD ($) | Mar. 31, 2017USD ($) |
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 70,000,000 | $ 115,000,000 | |
Number of letters of credit | instrument | 8 | ||
Amount outstanding | $ 60,300,000 |
Debt - 7.875% Senior Secured No
Debt - 7.875% Senior Secured Notes due 2021 (Details) - Senior Notes - 7.875% senior notes due 2021 - USD ($) | 1 Months Ended | |
Apr. 30, 2015 | Aug. 31, 2014 | |
Debt Instrument [Line Items] | ||
Senior notes offering face amount | $ 225,000,000 | $ 300,000,000 |
Proceeds, net of offering discounts and deferred financing costs | $ 206,800,000 | $ 292,500,000 |
Debt - Maturities (Details)
Debt - Maturities (Details) - USD ($) | Sep. 30, 2017 | Dec. 31, 2016 |
Scheduled maturities of debt during the five year period and thereafter | ||
Total | $ 1,125,000,000 | $ 1,375,000,000 |
2,017 | 0 | |
2,018 | 0 | |
2,019 | 377,000 | |
2,020 | 404,971,000 | |
2,021 | 719,652,000 | |
Thereafter | 0 | |
Senior Notes | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Total | 525,000,000 | $ 525,000,000 |
Corporate Revolver | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Amount outstanding | 0 | |
7.875% senior notes due 2021 | Senior Notes | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Total | $ 525,000,000 |
Debt - Interest and other finan
Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Debt Disclosure [Abstract] | ||||
Interest expense | $ 22,961 | $ 23,057 | $ 68,934 | $ 65,829 |
Amortization—deferred financing costs | 2,551 | 2,551 | 7,653 | 7,653 |
Capitalized interest | (8,563) | (15,545) | (25,498) | (49,575) |
Deferred interest | 662 | 663 | 1,610 | 406 |
Interest income | (745) | (485) | (2,485) | (1,319) |
Other, net | 1,612 | 825 | 4,515 | 7,274 |
Interest and other financing costs, net | $ 18,478 | $ 11,066 | $ 54,729 | $ 30,268 |
Derivative Financial Instrume47
Derivative Financial Instruments - Schedule of oil derivative contracts (Details) | 1 Months Ended | 9 Months Ended |
Oct. 31, 2017$ / bblbbl | Sep. 30, 2017$ / bblbbl | |
Term Oct 2017 To December 2017 | Swap with puts/calls | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 503,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 2.13 | |
Swap (usd per bbl) | 72.50 | |
Sold Put (usd per bbl) | 55 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 0 | |
Call (usd per bbl) | 90 | |
Term Oct 2017 To December 2017 | Swap with puts | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 503,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0 | |
Swap (usd per bbl) | 64.95 | |
Sold Put (usd per bbl) | 50 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 0 | |
Call (usd per bbl) | 0 | |
Term Oct 2017 To December 2017 | Three-way collars | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 1,006,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 1.72 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 30 | |
Floor (usd per bbl) | 45 | |
Ceiling (usd per bbl) | 60 | |
Call (usd per bbl) | 0 | |
Term Oct 2017 To December 2017 | Sold calls | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 500,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 0 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 85 | |
Call (usd per bbl) | 0 | |
Term January 2018 to December 2018 | Swap with puts | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 2,000,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0 | |
Swap (usd per bbl) | 54.32 | |
Sold Put (usd per bbl) | 40 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 0 | |
Call (usd per bbl) | 0 | |
Term January 2018 to December 2018 | Three-way collars | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 2,913,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0.74 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 41.57 | |
Floor (usd per bbl) | 56.57 | |
Ceiling (usd per bbl) | 65.90 | |
Call (usd per bbl) | 0 | |
Term January 2018 to December 2018 | Four-way collars | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 3,000,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 1.06 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 40 | |
Floor (usd per bbl) | 50 | |
Ceiling (usd per bbl) | 61.33 | |
Call (usd per bbl) | 70 | |
Term January 2018 to December 2018 | Sold calls | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 2,000,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 0 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 65 | |
Call (usd per bbl) | 0 | |
Term January 2019 to December 2019 | Three-way collars | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 4,500,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0.26 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 40 | |
Floor (usd per bbl) | 50 | |
Ceiling (usd per bbl) | 62.78 | |
Call (usd per bbl) | 0 | |
Term January 2019 to December 2019 | Sold calls | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 913,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Deferred Premium Payable, Net (usd per bbl) | 0 | |
Swap (usd per bbl) | 0 | |
Sold Put (usd per bbl) | 0 | |
Floor (usd per bbl) | 0 | |
Ceiling (usd per bbl) | 80 | |
Call (usd per bbl) | 0 | |
Term January 2018 o June 2018 | Costless swap | Subsequent Event | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 1,000,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Swap (usd per bbl) | 57.25 | |
Term July 2018 to December 2018 | Swap with puts | Subsequent Event | ||
Derivative Financial Instruments | ||
Volume (mbbls) | bbl | 2,000,000 | |
Weighted Average Dated Brent Price Per Bbl [Abstract] | ||
Sold Put (usd per bbl) | 45 | |
Swap (usd per bbl) | 57.96 |
Derivative Financial Instrume48
Derivative Financial Instruments - Schedule of interest rate derivative contracts (Details) - 1-month LIBOR - Interest Rate Cap Swap - October 2017 — December 2018 $ in Thousands | Sep. 30, 2017USD ($) |
Derivative Financial Instruments | |
Notional | $ 200,000 |
Swap | 1.23% |
Sold Call | 3.00% |
Derivative Financial Instrume49
Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($) | Sep. 30, 2017 | Dec. 31, 2016 |
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | $ 16,200,000 | $ 31,698,000 |
Derivatives assets—long-term | 2,412,000 | 3,808,000 |
Derivatives liabilities—current | (9,016,000) | (19,692,000) |
Derivatives liabilities—long-term | (7,256,000) | (14,123,000) |
Derivatives not designated as hedging instruments: | ||
Derivative instruments, Balance Sheet Location | ||
Total derivatives not designated as hedging instruments | 2,340,000 | 1,691,000 |
Derivatives not designated as hedging instruments: | Commodity | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | 15,811,000 | 31,698,000 |
Derivatives assets—long-term | 2,107,000 | 3,226,000 |
Derivatives liabilities—current | (9,016,000) | (19,163,000) |
Derivatives liabilities—long-term | (7,256,000) | (14,123,000) |
Net deferred premiums payable related to commodity derivative contracts - current assets | 2,000,000 | 3,900,000 |
Net deferred premiums payable related to commodity derivative contracts - non current assets | 700,000 | 2,500,000 |
Net deferred premiums payable related to commodity derivative contracts - current liabilities | 4,400,000 | 6,200,000 |
Net deferred premiums payable related to commodity derivative contracts - non current liabilities | 2,100,000 | 600,000 |
Derivatives not designated as hedging instruments: | Commodity | Oil and gas revenue | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives liabilities—current | 0 | (30,900) |
Derivatives not designated as hedging instruments: | Interest rate | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | 389,000 | 0 |
Derivatives assets—long-term | 305,000 | 582,000 |
Derivatives liabilities—current | $ 0 | $ (529,000) |
Derivative Financial Instrume50
Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | $ (33,021) | $ 17,995 | $ 25,924 | $ (37,179) |
Commodity | Oil and gas revenue | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | (6,221) | 344 | (10,781) | (712) |
Commodity | Derivatives, net | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | (26,864) | 16,891 | 36,404 | (33,752) |
Interest rate | Interest expense | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | $ 64 | $ 760 | $ 301 | $ (2,715) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2017 | Dec. 31, 2016 |
Carrying Value | ||
Liabilities: | ||
Long-term debt | $ 1,106,594 | $ 1,353,716 |
Fair Value | ||
Liabilities: | ||
Long-term debt | 1,145,874 | 1,378,938 |
Senior Notes | Carrying Value | ||
Liabilities: | ||
Long-term debt | 506,594 | 503,716 |
Senior Notes | Fair Value | ||
Liabilities: | ||
Long-term debt | 545,874 | 528,938 |
Facility | Carrying Value | ||
Liabilities: | ||
Long-term debt | 600,000 | 850,000 |
Facility | Fair Value | ||
Liabilities: | ||
Long-term debt | 600,000 | 850,000 |
Recurring basis | ||
Liabilities: | ||
Total fair value, net | 2,340 | 1,691 |
Recurring basis | Commodity | ||
Assets: | ||
Derivative asset, fair value | 17,918 | 34,924 |
Liabilities: | ||
Derivative liability, fair value | (16,272) | (33,286) |
Recurring basis | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 694 | 582 |
Liabilities: | ||
Derivative liability, fair value | 0 | (529) |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Liabilities: | ||
Total fair value, net | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity | ||
Assets: | ||
Derivative asset, fair value | 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | 0 | 0 |
Recurring basis | Significant Other Observable Inputs (Level 2) | ||
Liabilities: | ||
Total fair value, net | 2,340 | 1,691 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Commodity | ||
Assets: | ||
Derivative asset, fair value | 17,918 | 34,924 |
Liabilities: | ||
Derivative liability, fair value | (16,272) | (33,286) |
Recurring basis | Significant Other Observable Inputs (Level 2) | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 694 | 582 |
Liabilities: | ||
Derivative liability, fair value | 0 | (529) |
Recurring basis | Significant Unobservable Inputs (Level 3) | ||
Liabilities: | ||
Total fair value, net | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Commodity | ||
Assets: | ||
Derivative asset, fair value | 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 0 | 0 |
Liabilities: | ||
Derivative liability, fair value | $ 0 | $ 0 |
Equity-based Compensation - Add
Equity-based Compensation - Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 4 years | |||
Restricted Stock Awards and Restricted Stock Units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense not yet recognized | $ 33.5 | $ 33.5 | ||
Weighted average period over which compensation expense is to be recognized | 1 year 5 months 23 days | |||
LTIP | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expense recognized | 9.6 | $ 9.2 | $ 29.9 | $ 30.4 |
Tax benefit | 3.2 | 3 | 9.9 | 9.9 |
Net tax shortfall related to equity-based compensation | 0.2 | 1 | 3.1 | 5.3 |
Fair value of awards vested | $ 1.4 | $ 2.4 | $ 20.7 | $ 13.4 |
Number of shares remaining available for grant | 3.4 | 3.4 | ||
LTIP | Market/Service Vesting Restricted Stock Units | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Grant date fair value of awards granted (in dollars per share) | $ 9.50 | |||
LTIP | Market/Service Vesting Restricted Stock Units | Minimum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Grant date fair value of awards granted (in dollars per share) | $ 4.83 | |||
Expected volatility | 44.00% | |||
Risk-free interest rate | 0.50% | |||
LTIP | Market/Service Vesting Restricted Stock Units | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percentage of the awards granted (up to) | 200.00% | |||
Grant date fair value of awards granted (in dollars per share) | $ 15.81 | |||
Expected volatility | 54.00% | |||
Risk-free interest rate | 1.40% | |||
LTIP | Market/Service Vesting Restricted Stock Awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Grant date fair value of awards granted (in dollars per share) | $ 9.45 | |||
Expected volatility | 55.00% | |||
Risk-free interest rate | 0.50% | |||
LTIP | Market/Service Vesting Restricted Stock Awards | Maximum | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting percentage of the awards granted (up to) | 100.00% |
Equity-based Compensation - Sch
Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands | 9 Months Ended |
Sep. 30, 2017$ / sharesshares | |
Service Vesting Restricted Stock Awards | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | shares | 488 |
Granted (in shares) | shares | 0 |
Forfeited (in shares) | shares | 0 |
Vested (in shares) | shares | (268) |
Outstanding at the end of the period (in shares) | shares | 220 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ 8.83 |
Granted (in dollars per share) | 0 |
Forfeited (in dollars per share) | 0 |
Vested (in dollars per share) | 8.97 |
Outstanding at the end of the period (in dollars per share) | $ 8.64 |
Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | shares | 4,160 |
Granted (in shares) | shares | 2,063 |
Forfeited (in shares) | shares | (123) |
Vested (in shares) | shares | (1,864) |
Outstanding at the end of the period (in shares) | shares | 4,236 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ 6.91 |
Granted (in dollars per share) | 6.41 |
Forfeited (in dollars per share) | 7.03 |
Vested (in dollars per share) | 7.50 |
Outstanding at the end of the period (in dollars per share) | $ 6.40 |
Market/Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | shares | 7,194 |
Granted (in shares) | shares | 2,170 |
Forfeited (in shares) | shares | (27) |
Vested (in shares) | shares | (894) |
Outstanding at the end of the period (in shares) | shares | 8,443 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ 12.29 |
Granted (in dollars per share) | 9.50 |
Forfeited (in dollars per share) | 7.76 |
Vested (in dollars per share) | 15.44 |
Outstanding at the end of the period (in dollars per share) | 11.26 |
Market/Service Vesting Restricted Stock Units | Maximum | |
Weighted-Average Grant-Date Fair Value | |
Granted (in dollars per share) | $ 15.81 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Income Taxes | ||||
Effective tax rate (as a percent) | 2.00% | 14.00% | 79.00% | 4.00% |
Income (loss) before income taxes | $ (64,920) | $ (52,261) | $ (56,312) | $ (237,144) |
Bermuda | ||||
Income Taxes | ||||
Income (loss) before income taxes | (17,740) | (15,989) | (50,680) | (47,212) |
United States | ||||
Income Taxes | ||||
Income (loss) before income taxes | 1,437 | 1,132 | $ 4,231 | 5,447 |
Foreign—other | ||||
Income Taxes | ||||
Effective tax rate (as a percent) | 0.00% | |||
Statutory tax rate (as a percent) | 0.00% | |||
Income (loss) before income taxes | $ (48,617) | $ (37,404) | $ (9,863) | $ (195,379) |
Net Loss Per Share (Details)
Net Loss Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Numerator: | ||||
Net loss | $ (63,405) | $ (59,763) | $ (100,713) | $ (227,080) |
Basic income allocable to participating securities | 0 | 0 | 0 | 0 |
Basic net loss allocable to common shareholders | (63,405) | (59,763) | (100,713) | (227,080) |
Diluted adjustments to income allocable to participating securities | 0 | 0 | 0 | 0 |
Diluted net loss allocable to common shareholders | $ (63,405) | $ (59,763) | $ (100,713) | $ (227,080) |
Weighted average number of shares outstanding: | ||||
Basic (in shares) | 389,058,000 | 386,026,000 | 388,114,000 | 385,130,000 |
Restricted stock awards and units (in shares) | 0 | 0 | 0 | 0 |
Diluted (in shares) | 389,058,000 | 386,026,000 | 388,114,000 | 385,130,000 |
Net loss per share: | ||||
Basic (in dollars per share) | $ (0.16) | $ (0.15) | $ (0.26) | $ (0.59) |
Diluted (in dollars per share) | $ (0.16) | $ (0.15) | $ (0.26) | $ (0.59) |
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares) | 12,900,000 | 12,000,000 | 12,900,000 | 12,000,000 |
Commitments and Contingencies56
Commitments and Contingencies (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended |
Jan. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Sep. 30, 2017USD ($)km²exploration_well | |
Operating leases | |||
Future minimum rental commitments | |||
Total | $ 9,910 | ||
2,017 | 1,158 | ||
2,018 | 4,736 | ||
2,019 | 3,951 | ||
2,020 | 65 | ||
2,021 | 0 | ||
Thereafter | 0 | ||
ENSCO DS-12 drilling rig contract | |||
Future minimum rental commitments | |||
Total | 25,585 | ||
2,017 | 25,585 | ||
2,018 | 0 | ||
2,019 | 0 | ||
2,020 | 0 | ||
2,021 | 0 | ||
Thereafter | 0 | ||
Kosmos Energy Ventures | ENSCO DS-12 drilling rig contract | |||
Commitments and contingencies | |||
Rig rate per day - subsidiary's revert option | $ 600 | ||
Recovery payment for reverting the rig rate back to original day rate | $ 48,100 | ||
Mauritania And Senegal Offshore Block | Maximum | |||
Commitments and contingencies | |||
Spending by third party for exploration and appraisal costs | $ 228,000 | ||
Equatorial Guinea | |||
Commitments and contingencies | |||
3 D seismic requirements (in square kilometers) | km² | 6,000 | ||
Mauritania | |||
Commitments and contingencies | |||
Number of exploration wells | exploration_well | 2 | ||
3 D seismic requirements (in square kilometers) | km² | 7,600 | ||
Western Sahara | |||
Commitments and contingencies | |||
3 D seismic requirements (in square kilometers) | km² | 5,000 |
Additional Financial Informat57
Additional Financial Information (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Accrued liabilities: | |||||
Exploration, development and production | $ 130,543,000 | $ 130,543,000 | $ 76,194,000 | ||
General and administrative expenses | 26,823,000 | 26,823,000 | 31,243,000 | ||
Interest | 9,180,000 | 9,180,000 | 17,247,000 | ||
Income taxes | 3,145,000 | 3,145,000 | 2,579,000 | ||
Taxes other than income | 3,941,000 | 3,941,000 | 1,914,000 | ||
Other | 172,000 | 172,000 | 529,000 | ||
Accrued liabilities | 173,804,000 | 173,804,000 | $ 129,706,000 | ||
Other income, net | 0 | $ 0 | 58,700,000 | $ 20,000,000 | |
Other Expenses, Net | |||||
Inventory write-off | (500,000) | 0 | 47,000 | 15,177,000 | |
(Gain) loss on insurance settlements | 0 | (3,047,000) | (461,000) | (4,003,000) | |
Disputed charges and related costs | 821,000 | 1,826,000 | 3,260,000 | 1,826,000 | |
Loss on equity method investment | 4,804,000 | 0 | 11,230,000 | 0 | |
Other, net | (88,000) | 426,000 | 157,000 | 768,000 | |
Other expenses, net | 5,037,000 | (795,000) | 14,233,000 | 13,768,000 | |
Oil and gas production expense | |||||
Accrued liabilities: | |||||
Insurance recoveries | $ 0 | $ 0 | $ 17,100,000 | $ 0 |