Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2018 | Nov. 01, 2018 | |
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, 2018 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Common Stock, Shares Outstanding | 433,617,302 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q3 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 192,646 | $ 233,412 |
Restricted cash | 5,376 | 56,380 |
Receivables: | ||
Joint interest billings, net | 84,209 | 134,565 |
Oil sales | 131,546 | 0 |
Related party | 20,834 | 780 |
Other | 15,750 | 25,616 |
Inventories | 90,003 | 71,861 |
Prepaid expenses and other | 58,949 | 9,306 |
Derivatives | 41,466 | 1,682 |
Total current assets | 640,779 | 533,602 |
Property and equipment: | ||
Oil and gas properties, net | 3,498,855 | 2,310,973 |
Other property, net | 10,682 | 6,855 |
Property and equipment, net | 3,509,537 | 2,317,828 |
Other assets: | ||
Equity method investment | 88,652 | 236,514 |
Restricted cash | 9,473 | 15,194 |
Long-term receivables - joint interest billings | 21,861 | 34,941 |
Deferred financing costs, net of accumulated amortization of $11,411 and $13,951 at September 30, 2018 and December 31, 2017, respectively | 9,582 | 2,510 |
Deferred tax assets | 31,890 | 22,517 |
Derivatives | 14,486 | 39 |
Other | 3,204 | 29,458 |
Total assets | 4,329,464 | 3,192,603 |
Current liabilities: | ||
Accounts payable | 153,922 | 141,787 |
Accrued liabilities | 262,310 | 219,412 |
Derivatives | 212,217 | 67,531 |
Total current liabilities | 628,449 | 428,730 |
Long-term liabilities: | ||
Long-term debt, net | 2,094,534 | 1,282,797 |
Derivatives | 110,245 | 30,209 |
Asset retirement obligations | 150,200 | 66,595 |
Deferred tax liabilities | 401,826 | 476,548 |
Other long-term liabilities | 9,277 | 10,612 |
Total long-term liabilities | 2,766,082 | 1,866,761 |
Shareholders’ equity: | ||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2018 and December 31, 2017 | 0 | 0 |
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 442,856,360 and 398,599,457 issued at September 30, 2018 and December 31, 2017, respectively | 4,429 | 3,986 |
Additional paid-in capital | 2,331,969 | 2,014,525 |
Accumulated deficit | (1,352,758) | (1,073,202) |
Treasury stock, at cost, 9,263,269 and 9,188,819 shares at September 30, 2018 and December 31, 2017, respectively | (48,707) | (48,197) |
Total shareholders’ equity | 934,933 | 897,112 |
Total liabilities and shareholders’ equity | $ 4,329,464 | $ 3,192,603 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Deferred financing costs, accumulated amortization | $ 11,411 | $ 13,951 |
Preference shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preference shares, authorized shares (in shares) | 200,000,000 | 200,000,000 |
Preference shares, issued shares (in shares) | 0 | 0 |
Common shares, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common shares, authorized shares (in shares) | 2,000,000,000 | 2,000,000,000 |
Common shares, issued shares (in shares) | 442,856,360 | 398,599,457 |
Treasury stock shares (in shares) | 9,263,269 | 9,188,819 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues and other income: | ||||
Oil and gas revenue | $ 242,833 | $ 151,240 | $ 585,220 | $ 391,035 |
Gain on sale of assets | 7,666 | 0 | 7,666 | 0 |
Other income, net | (280) | 2 | (17) | 58,697 |
Total revenues and other income | 250,219 | 151,242 | 592,869 | 449,732 |
Costs and expenses: | ||||
Oil and gas production | 55,078 | 39,187 | 151,661 | 80,677 |
Facilities insurance modifications, net | 12,334 | (3,906) | 21,812 | (1,334) |
Exploration expenses | 148,238 | 36,983 | 246,912 | 162,679 |
General and administrative | 25,963 | 20,029 | 65,343 | 50,555 |
Depletion and depreciation | 80,041 | 73,490 | 208,607 | 180,909 |
Interest and other financing costs, net | 23,549 | 18,478 | 68,113 | 54,729 |
Derivatives, net | 57,357 | 26,864 | 236,107 | (36,404) |
(Gain) loss on equity method investments, net | (24,841) | 4,804 | (59,637) | 11,230 |
Other expenses, net | (12,807) | 233 | (8,164) | 3,003 |
Total costs and expenses | 364,912 | 216,162 | 930,754 | 506,044 |
Loss before income taxes | (114,693) | (64,920) | (337,885) | (56,312) |
Income tax expense (benefit) | 11,364 | (1,515) | (58,329) | 44,401 |
Net loss | $ (126,057) | $ (63,405) | $ (279,556) | $ (100,713) |
Net loss per share: | ||||
Basic (in dollars per share) | $ (0.31) | $ (0.16) | $ (0.70) | $ (0.26) |
Diluted (in dollars per share) | $ (0.31) | $ (0.16) | $ (0.70) | $ (0.26) |
Weighted average number of shares used to compute net loss per share: | ||||
Basic (in shares) | 404,536 | 389,058 | 399,026 | 388,114 |
Diluted (in shares) | 404,536 | 389,058 | 399,026 | 388,114 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - 9 months ended Sep. 30, 2018 - 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, 2017 | 398,599 | ||||
Balance at the beginning at Dec. 31, 2017 | $ 897,112 | $ 3,986 | $ 2,014,525 | $ (1,073,202) | $ (48,197) |
Increase (Decrease) in Shareholders' Equity | |||||
Acquisition of oil and gas properties (in shares) | 34,994 | ||||
Acquisition of oil and gas properties | 307,944 | $ 350 | 307,594 | ||
Equity-based compensation | 27,128 | 27,128 | |||
Restricted stock awards and units (in shares) | 9,263 | ||||
Restricted stock awards and units | 0 | $ 93 | (93) | ||
Purchase of treasury stock / tax withholdings | (17,695) | (17,185) | (510) | ||
Net loss | (279,556) | (279,556) | |||
Balance at the end (in shares) at Sep. 30, 2018 | 442,856 | ||||
Balance at the end at Sep. 30, 2018 | $ 934,933 | $ 4,429 | $ 2,331,969 | $ (1,352,758) | $ (48,707) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Operating activities | ||
Net loss | $ (279,556) | $ (100,713) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depletion, depreciation and amortization | 215,676 | 188,563 |
Deferred income taxes | (84,095) | 32,820 |
Unsuccessful well costs | 114,948 | 24,515 |
Change in fair value of derivatives | 232,057 | (25,924) |
Cash settlements on derivatives, net (including $(107.3) million and $36.4 million on commodity hedges during 2018 and 2017) | (102,705) | 25,275 |
Equity-based compensation | 25,975 | 29,945 |
Gain on sale of assets | (7,666) | 0 |
Loss on extinguishment of debt | 4,324 | 0 |
Distributions in excess of equity in earnings | 5,235 | 11,230 |
Other | 1,237 | 3,412 |
Changes in assets and liabilities: | ||
Decrease in receivables | 59,318 | 3,232 |
Decrease in inventories | 3,978 | 58 |
Increase in prepaid expenses and other | (9,732) | (19,327) |
Decrease in accounts payable | (15,178) | (120,325) |
Increase (decrease) in accrued liabilities | (73,569) | 41,651 |
Net cash provided by operating activities | 90,247 | 94,412 |
Investing activities | ||
Oil and gas assets | (149,305) | (100,712) |
Other property | (3,560) | (1,639) |
Acquisition of oil and gas properties, net of cash acquired | (961,764) | 0 |
Return of investment from KTIPI | 142,628 | 0 |
Proceeds on sale of assets | 13,703 | 222,068 |
Net cash provided by (used in) investing activities | (958,298) | 119,717 |
Financing activities | ||
Borrowings under long-term debt | 1,000,000 | 0 |
Payments on long-term debt | (175,000) | (250,000) |
Purchase of treasury stock / tax withholdings | (17,695) | (2,116) |
Deferred financing costs | (36,745) | 0 |
Net cash provided by (used in) financing activities | 770,560 | (252,116) |
Net decrease in cash, cash equivalents and restricted cash | (97,491) | (37,987) |
Cash, cash equivalents and restricted cash at beginning of period | 304,986 | 273,195 |
Cash, cash equivalents and restricted cash at end of period | 207,495 | 235,208 |
Cash paid for: | ||
Interest | 86,981 | 48,694 |
Income taxes | 25,601 | 27,199 |
Non-cash activity: | ||
Contribution to equity method investment | 0 | 133,893 |
Common stock issued for acquisition of oil and gas properties | $ 307,944 | $ 0 |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Statement of Cash Flows [Abstract] | ||
Cash settlements on derivatives, net (commodity hedges) | $ (107.3) | $ 36.4 |
Organization
Organization | 9 Months Ended |
Sep. 30, 2018 | |
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 corporate 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 full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margin. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin short-cycle exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia and Sao Tome and Principe). 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 related to production located offshore Ghana and U.S. Gulf of Mexico. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea. |
Accounting Policies
Accounting Policies | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 , the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2018 , the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017 , and the consolidated cash flows for the nine months ended September 30, 2018 and 2017 . 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, 2017 , included in our annual report on Form 10-K. Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net 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 $ 192,646 $ 233,412 Restricted cash - current 5,376 56,380 Restricted cash - long-term 9,473 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows $ 207,495 $ 304,986 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 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, 2018 and December 31, 2017 , we had $5.4 million and $31.6 million , respectively, of current restricted cash and $9.2 million and $15.2 million , respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. As of September 30, 2018 , we also had $0.2 million in other long-term restricted cash. In addition, prior to our reserves based debt facility (the "Facility") being amended and restated in February 2018, we were required to maintain a restricted cash balance that was 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 was greater. As of December 31, 2017 , we had $24.8 million in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios. Inventories Inventories consisted of $86.8 million (including $22.1 million acquired through the Deep Gulf Energy (together with its subsidiaries "DGE") acquisition) and $63.5 million of materials and supplies and $3.2 million and $8.4 million of hydrocarbons as of September 30, 2018 and December 31, 2017 , 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. 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. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of September 30, 2018 and December 31, 2017 , we had no oil and gas imbalances recorded in our consolidated financial statements. Our oil and gas revenues are recognized when production has been sold to a purchaser at a fixed or determinable price, title has transferred and collectability is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Oil and gas revenue is composed of the following: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 215,581 $ 157,461 $ 557,459 $ 401,816 Revenue from contracts with customers - U.S. Gulf of Mexico 24,177 — 24,177 — Provisional oil sales contracts 3,075 (6,221 ) 3,584 (10,781 ) Oil and gas revenue $ 242,833 $ 151,240 585,220 391,035 Recent Accounting Standards Recently 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. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted 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. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures 2018 Transactions In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. The petroleum contracts cover approximately 13,600 square kilometers, with a first exploration period of four years from the effective date (March 2018). The exploration periods can be extended an additional four years at our election subject to fulfilling specific work obligations. The first exploration period work programs include a 13,500 square kilometer 3D seismic acquisition requirement across the two blocks. In June 2018, we completed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement. In September 2018, we completed the acquisition of DGE, a deepwater company operating in the U.S. Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of $1.275 billion , comprised of $952.6 million in cash and $307.9 million in Kosmos common stock and $14.9 million of transaction related costs. We funded the cash portion of the purchase price using cash on hand and drawings under our existing credit facilities. We also received $200.0 million of additional firm commitments under the Facility, which provides further liquidity to the Company. The DGE acquisition was accounted for under the asset acquisition method and the purchase price allocation is shown below. The purchase price allocation was based on the estimated relative fair value of identifiable assets acquired and liabilities assumed. The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate. Purchase Price Allocation (in thousands) Fair value of assets acquired: Proved oil and gas properties $ 1,045,509 Unproved oil and gas properties 300,420 Accounts receivable and other 179,332 Total assets acquired $ 1,525,261 Fair value of liabilities assumed: Accrued liabilities and other $ 123,034 Asset retirement obligations 86,580 Derivative liabilities 40,265 Total liabilities assumed $ 249,879 Cash consideration paid $ 952,586 Fair value of common stock(1) 307,944 Transaction related costs 14,852 Total purchase price $ 1,275,382 (1) Based on 34,993,585 common shares issued at a price of $8.80 per share, which is the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition. As a result of the DGE acquisition, we have included $24.2 million of revenues and $4.4 million of direct operating expenses in our consolidated statements of operations for the period from September 14, 2018 to September 30, 2018. In October 2018, Kosmos entered into a strategic exploration alliance with Shell Exploration Company B.V. (“Shell”) to jointly explore in Southern West Africa. Initially the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39. 2017 Transactions In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which held an 85% paying interest ( 80.75% revenue interest) in the Ceiba Field and Okume Complex assets located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was $650 million effective as of January 1, 2017 . After purchase price adjustments, Kosmos paid net cash consideration of approximately $231 million at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment. In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. In August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and are the operator in all three blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), 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 effective date (March 2018). 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. In December 2017 , as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks. |
Joint Interest Billings and Rel
Joint Interest Billings and Related Party Receivables | 9 Months Ended |
Sep. 30, 2018 | |
Joint Interest Billings | |
Joint Interest Billings and Related Party Receivables | Joint Interest Billings and Related Party Receivables 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 are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of September 30, 2018 and December 31, 2017 , the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $15.2 million , respectively, and the long-term portions were $21.9 million and $31.6 million , respectively. The Company's related party receivables consists primarily of receivables from Trident who owns a 50% interest in KTIPI. As of September 30, 2018 the balance due from Trident consists of $ 13.7 million related to the farm-out of Blocks EG-21, S, and W, and $ 7.1 million related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations. |
Property and Equipment
Property and Equipment | 9 Months Ended |
Sep. 30, 2018 | |
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 $ 2,749,163 $ 1,653,616 Unproved properties 733,274 465,109 Support equipment and facilities 1,450,907 1,427,054 Total oil and gas properties 4,933,344 3,545,779 Accumulated depletion (1,434,489 ) (1,234,806 ) Oil and gas properties, net 3,498,855 2,310,973 Other property 46,513 39,405 Accumulated depreciation (35,831 ) (32,550 ) Other property, net 10,682 6,855 Property and equipment, net $ 3,509,537 $ 2,317,828 We recorded depletion expense of $76.8 million and $70.9 million for the three months ended September 30, 2018 and 2017 , respectively, and $199.7 million and $173.3 million for the nine months ended September 30, 2018 and 2017 , respectively. |
Suspended Well Costs
Suspended Well Costs | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 . The table excludes $48.0 million in costs that were capitalized and subsequently expensed during the same period. September 30, (In thousands) Beginning balance $ 410,113 Additions associated with the acquisition of DGE 26,426 Additions to capitalized exploratory well costs pending the determination of proved reserves 7,658 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense (52,498 ) Ending balance $ 391,699 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, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 26,426 $ 67,159 Exploratory well costs capitalized for a period of one to two years 296,866 291,252 Exploratory well costs capitalized for a period of three years 68,407 51,702 Ending balance $ 391,699 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 3 5 As of September 30, 2018 , the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to 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 Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal. Akasa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Akasa discovery. As a result, we wrote off $39.8 million of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Akasa discovery area, and the acreage is not currently being relinquished. Wawa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Wawa discovery. As a result, we wrote off $17.9 million of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Wawa discovery area, and the acreage is not currently being relinquished. 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. The partnership has made significant progress towards a final investment decision for phase one. Led by BP, the FEED work for phase one is substantially complete. The Unit Development Plan has been submitted to both governments, and we have reached agreement with the Governments of Mauritania and Senegal on the non-PSA fiscal terms for this cross border project. 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 is expected to be made. Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. An appraisal well is scheduled in 2019 to further evaluate the discovery. Following additional evaluation, a decision regarding commerciality is expected to be made. Nearly Headless Nick Discovery — In September 2018, the Nearly Headless Nick exploration well ( 22.0% WI) was successfully drilled to a total depth of approximately 5,800 meters ( 19,050 feet) and encountered approximately 26 meters ( 85 feet) of net pay in the Middle Miocene objective within the Mississippi Canyon 387 block offshore U.S. Gulf of Mexico. Nearly Headless Nick will be developed as a subsea tie back, which is expected to be brought online through the Delta House facility by 2020. |
Equity Method Investments
Equity Method Investments | 9 Months Ended |
Sep. 30, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | Equity Method Investments Kosmos BP Senegal Limited ("KBSL") As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture entity in which we owned a 50.01% interest which was accounted for under the equity method of accounting. In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% participating interest in the Senegal Blocks. During the three and nine months ended September 30, 2017 we recognized $4.8 million and $11.2 million , respectively, related to our share of losses in KBSL. Our initial contribution to KBSL was $133.9 million , which was recorded at our carrying costs. Equatorial Guinea As part of our acquisition of KTIPI, a corporate joint venture entity in which we own a 50% interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a 100% basis. September 30, December 31, 2018 2017 (In thousands) Assets Total current assets $ 158,140 $ 179,070 Property and equipment, net 291,960 345,611 Other assets 487 567 Total assets $ 450,587 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 196,338 $ 106,769 Total long-term liabilities 541,881 565,591 Shareholders' equity: Total shareholders' equity (287,632 ) (147,112 ) Total liabilities and shareholders' equity $ 450,587 $ 525,248 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 215,408 $ 600,158 Other income (72 ) 44 Total revenues and other income 215,336 600,202 Costs and expenses: Oil and gas production 40,334 115,366 Depletion and depreciation 33,044 108,996 Other expenses, net (58 ) (211 ) Total costs and expenses 73,320 224,151 Income before income taxes 142,016 376,051 Income tax expense 50,796 134,047 Net income $ 91,220 $ 242,004 Kosmos' share of net income $ 45,610 $ 121,002 Basis difference amortization(1) 20,769 61,365 Equity in earnings - KTIPI $ 24,841 $ 59,637 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method. When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of September 30, 2018 , we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such, no impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the nine months ended September 30, 2018 , we received $207.5 million of cash dividends from KTIPI, and we received an additional $32.5 million of cash dividends in October 2018. |
Debt
Debt | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Debt September 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 1,325,000 $ 800,000 Corporate Revolver 300,000 — Senior Notes 525,000 525,000 Total 2,150,000 1,325,000 Unamortized deferred financing costs and discounts(1) (55,466 ) (42,203 ) Long-term debt, net $ 2,094,534 $ 1,282,797 __________________________________ (1) Includes $40.3 million and $23.6 million of unamortized deferred financing costs related to the Facility and $15.2 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2018 and December 31, 2017 , respectively. Facility In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with two existing financial institutions, which obligate the two financial institutions to provide the Company, upon the Company's election, with an additional commitment of $200 million in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of September 30, 2018 , we have $40.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of September 30, 2018 , borrowings under the Facility totaled $1,325.0 million and the undrawn availability under the Facility was $375.0 million , which includes the $200 million in additional commitments referenced above. The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires 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, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of September 30, 2018 , 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, 2018 (the most recent assessment date). The Facility contains customary cross default provisions. Corporate Revolver In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million , extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5% . This results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of September 30, 2018 , borrowings under the Corporate Revolver totaled $300 million and the undrawn availability under the Corporate Revolver was $100 million . As of September 30, 2018, we have $9.6 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2018 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. Revolving Letter of Credit Facility We have a revolving letter of credit facility agreement (“LC Facility”), which matures in July 2019 . In July 2018, the LC Facility size was voluntarily reduced to $40.0 million based on the expiration of several large outstanding letters of credit. As of September 30, 2018 , there were eight outstanding letters of credit totaling $16.9 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 both 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, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 2,150,000 $ — $ — $ — $ 685,600 $ 589,100 $ 875,300 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2018 , 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. (2) Represents payments for the period October 1, 2018 through December 31, 2018 . 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, 2018 2017 2018 2017 (In thousands) Interest expense $ 27,317 $ 22,961 $ 77,121 $ 68,934 Amortization—deferred financing costs 2,346 2,551 7,069 7,653 Loss on extinguishment of debt 268 — 4,324 — Capitalized interest (7,097 ) (8,563 ) (21,209 ) (25,498 ) Deferred interest (194 ) 662 (1,284 ) 1,610 Interest income (788 ) (745 ) (2,579 ) (2,485 ) Other, net 1,697 1,612 4,671 4,515 Interest and other financing costs, net $ 23,549 $ 18,478 $ 68,113 $ 54,729 |
Derivative Financial Instrument
Derivative Financial Instruments | 9 Months Ended |
Sep. 30, 2018 | |
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 prices per Bbl for those contracts as of September 30, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Price per Bbl Net Deferred Premium Term Type of Contract Index MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: Oct — Dec Swap with puts Dated Brent 1,500 $ — $ 56.75 $ 43.33 $ — $ — $ — Oct — Dec Three-way collars Dated Brent 733 0.74 — 41.57 56.57 65.91 — Oct — Dec Four-way collars Dated Brent 751 1.06 — 40.00 50.00 61.33 70.00 Oct — Dec Sold calls(1) Dated Brent 503 — — — — 65.00 — Oct — Dec Purchased Calls Dated Brent 500 1.88 — — — — 70.00 Oct — Dec Purchased Puts NYMEX WTI 141 2.70 — — 53.00 — — Oct — Dec Collars NYMEX WTI 35 — — — 62.29 66.35 — Oct — Dec Swaps NYMEX WTI 698 — 54.69 — — — — 2019: Jan — Dec Three-way collars Dated Brent 10,500 $ 1.17 $ — $ 43.81 $ 53.33 $ 73.58 $ — Jan — Dec Sold calls(1) Dated Brent 913 — — — — 80.00 — Jan — Dec Swaps NYMEX WTI 1,747 — 52.31 — — — — Jan — Jun Collars NYMEX WTI 339 — — — 57.77 63.70 — Jan — Dec Collars Argus LLS 1,000 — — — 60.00 88.75 — 2020: Jan — Dec Three-way collars Dated Brent 2,000 $ — $ — $ 50.00 $ 60.00 $ 90.54 $ — Jan — Dec Sold calls(1) Dated Brent 8,000 $ — $ — $ — $ — $ 80.00 $ — __________________________________ (1) Represents call option contracts sold to counterparties to enhance other derivative positions. 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, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) October 2018 — 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, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three months ended September 30, 2018 and 2017 , 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 $ 40,953 $ 665 Interest rate Derivatives assets—current 513 1,017 Commodity(2) Derivatives assets—long-term 14,486 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (212,217 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (110,245 ) (30,209 ) Total derivatives not designated as hedging instruments $ (266,510 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $4.7 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums payable of $2.4 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $6.0 million and $5.6 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $1.6 million and $4.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , 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) 2018 2017 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 3,075 $ (6,221 ) $ 3,584 $ (10,781 ) Commodity Derivatives, net (57,357 ) (26,864 ) (236,107 ) 36,404 Interest rate Interest expense 15 64 466 301 Total derivatives not designated as hedging instruments $ (54,267 ) $ (33,021 ) $ (232,057 ) $ 25,924 __________________________________ (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, 2018 and December 31, 2017 , 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, 2018 | |
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, 2018 and December 31, 2017 , 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, 2018 Assets: Commodity derivatives $ — $ 55,439 $ — $ 55,439 Interest rate derivatives — 513 — 513 Liabilities: Commodity derivatives — (322,462 ) — (322,462 ) Total $ — $ (266,510 ) $ — $ (266,510 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 ) 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 collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (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 respective index. 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 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments. Provisional Oil Sales The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date. Interest Rate Derivatives Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and 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, 2018 and December 31, 2017 : September 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 510,766 $ 535,941 $ 507,600 $ 542,472 Corporate Revolver 300,000 300,000 — — Facility 1,325,000 1,325,000 800,000 800,000 Total $ 2,135,766 $ 2,160,941 $ 1,307,600 $ 1,342,472 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, 2018 | |
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 $8.9 million and $9.6 million during the three months ended September 30, 2018 and 2017 , respectively, and $26.0 million and $29.9 million during the nine months ended September 30, 2018 and 2017 , respectively. The total tax benefit for the three months ended September 30, 2018 and 2017 was $1.6 million and $3.2 million , respectively, and $5.0 million and $9.9 million during the nine months ended September 30, 2018 and 2017 , respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.1 million and $0.2 million for the three months ended September 30, 2018 and 2017 , respectively, and $(0.3) million and $3.1 million during the nine months ended September 30, 2018 and 2017 , respectively. The fair value of awards vested during the three months ended September 30, 2018 and 2017 was approximately $1.1 million and $1.4 million , respectively, and $83.1 million and $20.7 million during the nine months ended September 30, 2018 and 2017 , 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 grants vest over three years. 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, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at September 30, 2018 — — The following table reflects the outstanding restricted stock units as of September 30, 2018 : 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, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1)(2) 2,360 7.03 8,140 12.39 Forfeited (116 ) 6.49 (46 ) 9.74 Vested (2,173 ) 6.93 (9,545 ) 13.75 Outstanding at September 30, 2018 4,254 6.41 7,001 9.17 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions. (2) The restricted stock units with a combination of market and service vesting criteria include 0.7 million shares granted to DGE employees as part of a new hire grant upon becoming employees of Kosmos. These shares were valued at $12.93 per share based on the Monte Carlo simulation model. As of September 30, 2018 , total equity-based compensation to be recognized on unvested restricted stock units is $36.2 million over a weighted average period of 2.05 years . In January 2018, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan which was approved by our shareholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At September 30, 2018 , the Company had approximately 15.8 million shares that remain available for issuance under the LTIP. For 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 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. 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 ranged from 44.0% to 53.0% . 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 ranged from 0.7% to 2.2% . |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2018 | |
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. On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances. 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, 2018 2017 2018 2017 (In thousands) Bermuda $ (15,513 ) $ (17,740 ) $ (47,474 ) $ (50,680 ) United States (53,136 ) 1,437 (49,967 ) 4,231 Foreign—other (46,044 ) (48,617 ) (240,444 ) (9,863 ) Income (loss) before income taxes $ (114,693 ) $ (64,920 ) $ (337,885 ) $ (56,312 ) Our effective tax rate for the three months ended September 30, 2018 and 2017 is 10% and 2% , respectively. For the nine months ended , September 30, 2018 and 2017 , our effective tax rate was 17% and 79% , respectively. For the periods ended September 30, 2018 and 2017 our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses. 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 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017. As of September 30, 2018 , 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, 2018 | |
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, 2018 2017 2018 2017 Numerator: Net loss $ (126,057 ) $ (63,405 ) $ (279,556 ) $ (100,713 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (126,057 ) (63,405 ) (279,556 ) (100,713 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (126,057 ) $ (63,405 ) $ (279,556 ) $ (100,713 ) Denominator: Weighted average number of shares outstanding: Basic 404,536 389,058 399,026 388,114 Restricted stock awards and units(1)(2) — — — — Diluted 404,536 389,058 399,026 388,114 Net loss per share: Basic $ (0.31 ) $ (0.16 ) $ (0.70 ) $ (0.26 ) Diluted $ (0.31 ) $ (0.16 ) $ (0.70 ) $ (0.26 ) __________________________________ (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 13.1 million and 12.9 million for the three months ended September 30, 2018 and 2017 , respectively, and 14.5 million and 12.9 million for the nine months ended September 30, 2018 and 2017 , 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, 2018 | |
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 one exploration well in Mauritania and two exploration wells in Senegal. Our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately 9,000 square kilometers and 13,500 square kilometers, respectively. Future minimum rental commitments under our leases at September 30, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 37,971 $ 1,463 $ 2,775 $ 4,173 $ 3,276 $ 3,326 $ 22,958 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator or discrete purchases of long lead items purchased through normal operations and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from October 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases. Performance Obligations As of September 30, 2018 , the Company had secured performance bonds totaling $214 million for our supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management ("BOEM") and $4 million to another operator related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its U.S. Gulf of Mexico fields. As of September 30, 2018 , we had $0.6 million of cash collateral against these secured performance bonds which is classified as Other long term assets in our consolidated balance sheet. |
Additional Financial Informatio
Additional Financial Information | 9 Months Ended |
Sep. 30, 2018 | |
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 $ 101,767 $ 144,717 Current asset retirement obligations 11,161 — General and administrative expenses 27,902 31,124 Interest 7,430 20,457 Income taxes 7,618 17,423 Taxes other than income 3,457 3,270 Derivatives 21,704 825 Acquired liabilities 80,783 — Other 488 1,596 $ 262,310 $ 219,412 Gain on sale of assets During the three and nine months ended September 30, 2018 , we recognized a $7.7 million gain related to the farm-out of Blocks EG-21, S and W to Trident. Other Income, Net Other income, net which includes Loss of Production Income ("LOPI") payments in 2017, consisted of zero and $58.7 million for the nine months ended September 30, 2018 and 2017 , respectively. Our LOPI coverage for the turret bearing issue on the Jubilee FPSO 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 and $17.1 million for the nine months ended September 30, 2018 and 2017 , respectively. Facilities Insurance Modifications, Net Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility which we expect to recover from our insurance policy net of any insurance reimbursements. 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, 2018 2017 2018 2017 (In thousands) (Gain) loss on disposal of inventory $ (2 ) $ (500 ) $ (26 ) $ 47 Gain on insurance settlements — — — (461 ) Disputed charges and related costs, net of recoveries (12,682 ) 821 (9,721 ) 3,260 Other, net (123 ) (88 ) 1,583 157 Other expenses, net $ (12,807 ) $ 233 $ (8,164 ) $ 3,003 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 charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were 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. In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we recovered from Tullow Ghana Limited disputed charges in the amount of $12.9 million in the form of cash payments and offsets against other unrelated joint venture costs, which include amounts previously paid under protest as well as certain costs and fees incurred pursuing the arbitration. |
Accounting Policies (Policies)
Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 , the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2018 , the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017 , and the consolidated cash flows for the nine months ended September 30, 2018 and 2017 . 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, 2017 , included in our annual report on Form 10-K. |
Reclassifications | Reclassifications Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net 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 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 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. |
Inventories | 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. 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. Inventories |
Revenue Recognition | Our oil and gas revenues are recognized when production has been sold to a purchaser at a fixed or determinable price, title has transferred and collectability is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Revenue Recognition We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. |
Recent Accounting Standards | Recent Accounting Standards Recently 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. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted 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. In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued. Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements. |
Accounting Policies (Tables)
Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Schedule of cash and cash equivalents | September 30, December 31, (In thousands) Cash and cash equivalents $ 192,646 $ 233,412 Restricted cash - current 5,376 56,380 Restricted cash - long-term 9,473 15,194 Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows $ 207,495 $ 304,986 |
Schedule of oil and gas revenue | Oil and gas revenue is composed of the following: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (In thousands) Revenue from contracts with customers - Ghana $ 215,581 $ 157,461 $ 557,459 $ 401,816 Revenue from contracts with customers - U.S. Gulf of Mexico 24,177 — 24,177 — Provisional oil sales contracts 3,075 (6,221 ) 3,584 (10,781 ) Oil and gas revenue $ 242,833 $ 151,240 585,220 391,035 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | Purchase Price Allocation (in thousands) Fair value of assets acquired: Proved oil and gas properties $ 1,045,509 Unproved oil and gas properties 300,420 Accounts receivable and other 179,332 Total assets acquired $ 1,525,261 Fair value of liabilities assumed: Accrued liabilities and other $ 123,034 Asset retirement obligations 86,580 Derivative liabilities 40,265 Total liabilities assumed $ 249,879 Cash consideration paid $ 952,586 Fair value of common stock(1) 307,944 Transaction related costs 14,852 Total purchase price $ 1,275,382 (1) Based on 34,993,585 common shares issued at a price of $8.80 per share, which is the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 $ 2,749,163 $ 1,653,616 Unproved properties 733,274 465,109 Support equipment and facilities 1,450,907 1,427,054 Total oil and gas properties 4,933,344 3,545,779 Accumulated depletion (1,434,489 ) (1,234,806 ) Oil and gas properties, net 3,498,855 2,310,973 Other property 46,513 39,405 Accumulated depreciation (35,831 ) (32,550 ) Other property, net 10,682 6,855 Property and equipment, net $ 3,509,537 $ 2,317,828 |
Suspended Well Costs (Tables)
Suspended Well Costs (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 . The table excludes $48.0 million in costs that were capitalized and subsequently expensed during the same period. September 30, (In thousands) Beginning balance $ 410,113 Additions associated with the acquisition of DGE 26,426 Additions to capitalized exploratory well costs pending the determination of proved reserves 7,658 Reclassification due to determination of proved reserves — Capitalized exploratory well costs charged to expense (52,498 ) Ending balance $ 391,699 |
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, 2018 December 31, 2017 (In thousands, except well counts) Exploratory well costs capitalized for a period of one year or less $ 26,426 $ 67,159 Exploratory well costs capitalized for a period of one to two years 296,866 291,252 Exploratory well costs capitalized for a period of three years 68,407 51,702 Ending balance $ 391,699 $ 410,113 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 3 5 |
Equity Method Investments (Tabl
Equity Method Investments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Summary of financial information of KTIPI | Below is a summary of financial information for KTIPI presented on a 100% basis. September 30, December 31, 2018 2017 (In thousands) Assets Total current assets $ 158,140 $ 179,070 Property and equipment, net 291,960 345,611 Other assets 487 567 Total assets $ 450,587 $ 525,248 Liabilities and shareholders' equity Total current liabilities $ 196,338 $ 106,769 Total long-term liabilities 541,881 565,591 Shareholders' equity: Total shareholders' equity (287,632 ) (147,112 ) Total liabilities and shareholders' equity $ 450,587 $ 525,248 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 (In thousands) Revenues and other income: Oil and gas revenue $ 215,408 $ 600,158 Other income (72 ) 44 Total revenues and other income 215,336 600,202 Costs and expenses: Oil and gas production 40,334 115,366 Depletion and depreciation 33,044 108,996 Other expenses, net (58 ) (211 ) Total costs and expenses 73,320 224,151 Income before income taxes 142,016 376,051 Income tax expense 50,796 134,047 Net income $ 91,220 $ 242,004 Kosmos' share of net income $ 45,610 $ 121,002 Basis difference amortization(1) 20,769 61,365 Equity in earnings - KTIPI $ 24,841 $ 59,637 ______________________________________ (1) The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method. |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of debt | September 30, December 31, (In thousands) Outstanding debt principal balances: Facility $ 1,325,000 $ 800,000 Corporate Revolver 300,000 — Senior Notes 525,000 525,000 Total 2,150,000 1,325,000 Unamortized deferred financing costs and discounts(1) (55,466 ) (42,203 ) Long-term debt, net $ 2,094,534 $ 1,282,797 __________________________________ (1) Includes $40.3 million and $23.6 million of unamortized deferred financing costs related to the Facility and $15.2 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2018 and December 31, 2017 , respectively. |
Schedule of estimated repayments of debt | At September 30, 2018 , the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: Payments Due by Year Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Principal debt repayments(1) $ 2,150,000 $ — $ — $ — $ 685,600 $ 589,100 $ 875,300 __________________________________ (1) Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2018 , 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. (2) Represents payments for the period October 1, 2018 through December 31, 2018 . |
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, 2018 2017 2018 2017 (In thousands) Interest expense $ 27,317 $ 22,961 $ 77,121 $ 68,934 Amortization—deferred financing costs 2,346 2,551 7,069 7,653 Loss on extinguishment of debt 268 — 4,324 — Capitalized interest (7,097 ) (8,563 ) (21,209 ) (25,498 ) Deferred interest (194 ) 662 (1,284 ) 1,610 Interest income (788 ) (745 ) (2,579 ) (2,485 ) Other, net 1,697 1,612 4,671 4,515 Interest and other financing costs, net $ 23,549 $ 18,478 $ 68,113 $ 54,729 |
Derivative Financial Instrume_2
Derivative Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 prices per Bbl for those contracts as of September 30, 2018 . Volumes and weighted average prices are net of any offsetting derivative contracts entered into. Weighted Average Price per Bbl Net Deferred Premium Term Type of Contract Index MBbl Payable/(Receivable) Swap Sold Put Floor Ceiling Call 2018: Oct — Dec Swap with puts Dated Brent 1,500 $ — $ 56.75 $ 43.33 $ — $ — $ — Oct — Dec Three-way collars Dated Brent 733 0.74 — 41.57 56.57 65.91 — Oct — Dec Four-way collars Dated Brent 751 1.06 — 40.00 50.00 61.33 70.00 Oct — Dec Sold calls(1) Dated Brent 503 — — — — 65.00 — Oct — Dec Purchased Calls Dated Brent 500 1.88 — — — — 70.00 Oct — Dec Purchased Puts NYMEX WTI 141 2.70 — — 53.00 — — Oct — Dec Collars NYMEX WTI 35 — — — 62.29 66.35 — Oct — Dec Swaps NYMEX WTI 698 — 54.69 — — — — 2019: Jan — Dec Three-way collars Dated Brent 10,500 $ 1.17 $ — $ 43.81 $ 53.33 $ 73.58 $ — Jan — Dec Sold calls(1) Dated Brent 913 — — — — 80.00 — Jan — Dec Swaps NYMEX WTI 1,747 — 52.31 — — — — Jan — Jun Collars NYMEX WTI 339 — — — 57.77 63.70 — Jan — Dec Collars Argus LLS 1,000 — — — 60.00 88.75 — 2020: Jan — Dec Three-way collars Dated Brent 2,000 $ — $ — $ 50.00 $ 60.00 $ 90.54 $ — Jan — Dec Sold calls(1) Dated Brent 8,000 $ — $ — $ — $ — $ 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, 2018 : Weighted Average Term Type of Contract Floating Rate Notional Swap Sold Call (In thousands) October 2018 — 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, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three months ended September 30, 2018 and 2017 , 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 $ 40,953 $ 665 Interest rate Derivatives assets—current 513 1,017 Commodity(2) Derivatives assets—long-term 14,486 39 Derivative liabilities: Commodity(3) Derivatives liabilities—current (212,217 ) (67,531 ) Commodity(4) Derivatives liabilities—long-term (110,245 ) (30,209 ) Total derivatives not designated as hedging instruments $ (266,510 ) $ (96,019 ) __________________________________ (1) Includes net deferred premiums payable of $4.7 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (2) Includes net deferred premiums payable of $2.4 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (3) Includes net deferred premiums payable of $6.0 million and $5.6 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , respectively. (4) Includes net deferred premiums payable of $1.6 million and $4.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017 , 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) 2018 2017 2018 2017 (In thousands) Derivatives not designated as hedging instruments: Commodity(1) Oil and gas revenue $ 3,075 $ (6,221 ) $ 3,584 $ (10,781 ) Commodity Derivatives, net (57,357 ) (26,864 ) (236,107 ) 36,404 Interest rate Interest expense 15 64 466 301 Total derivatives not designated as hedging instruments $ (54,267 ) $ (33,021 ) $ (232,057 ) $ 25,924 __________________________________ (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, 2018 | |
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, 2018 and December 31, 2017 , 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, 2018 Assets: Commodity derivatives $ — $ 55,439 $ — $ 55,439 Interest rate derivatives — 513 — 513 Liabilities: Commodity derivatives — (322,462 ) — (322,462 ) Total $ — $ (266,510 ) $ — $ (266,510 ) December 31, 2017 Assets: Commodity derivatives $ — $ 704 $ — $ 704 Interest rate derivatives — 1,017 — 1,017 Liabilities: Commodity derivatives — (97,740 ) — (97,740 ) Total $ — $ (96,019 ) $ — $ (96,019 ) |
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, 2018 and December 31, 2017 : September 30, 2018 December 31, 2017 Carrying Value Fair Value Carrying Value Fair Value (In thousands) Senior Notes $ 510,766 $ 535,941 $ 507,600 $ 542,472 Corporate Revolver 300,000 300,000 — — Facility 1,325,000 1,325,000 800,000 800,000 Total $ 2,135,766 $ 2,160,941 $ 1,307,600 $ 1,342,472 |
Equity-based Compensation (Tabl
Equity-based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of plan activity | The following table reflects the outstanding restricted stock awards as of September 30, 2018 : Weighted- Service Vesting Average Restricted Stock Grant-Date Awards Fair Value (In thousands) Outstanding at December 31, 2017 220 $ 8.64 Granted — — Forfeited — — Vested (220 ) 8.64 Outstanding at September 30, 2018 — — The following table reflects the outstanding restricted stock units as of September 30, 2018 : 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, 2017 4,183 $ 6.39 8,452 $ 11.26 Granted(1)(2) 2,360 7.03 8,140 12.39 Forfeited (116 ) 6.49 (46 ) 9.74 Vested (2,173 ) 6.93 (9,545 ) 13.75 Outstanding at September 30, 2018 4,254 6.41 7,001 9.17 __________________________________ (1) The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions. (2) The restricted stock units with a combination of market and service vesting criteria include 0.7 million shares granted to DGE employees as part of a new hire grant upon becoming employees of Kosmos. These shares were valued at $12.93 per share based on the Monte Carlo simulation model. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 2017 2018 2017 (In thousands) Bermuda $ (15,513 ) $ (17,740 ) $ (47,474 ) $ (50,680 ) United States (53,136 ) 1,437 (49,967 ) 4,231 Foreign—other (46,044 ) (48,617 ) (240,444 ) (9,863 ) Income (loss) before income taxes $ (114,693 ) $ (64,920 ) $ (337,885 ) $ (56,312 ) |
Net Loss Per Share (Tables)
Net Loss Per Share (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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, 2018 2017 2018 2017 Numerator: Net loss $ (126,057 ) $ (63,405 ) $ (279,556 ) $ (100,713 ) Basic income allocable to participating securities(1) — — — — Basic net loss allocable to common shareholders (126,057 ) (63,405 ) (279,556 ) (100,713 ) Diluted adjustments to income allocable to participating securities(1) — — — — Diluted net loss allocable to common shareholders $ (126,057 ) $ (63,405 ) $ (279,556 ) $ (100,713 ) Denominator: Weighted average number of shares outstanding: Basic 404,536 389,058 399,026 388,114 Restricted stock awards and units(1)(2) — — — — Diluted 404,536 389,058 399,026 388,114 Net loss per share: Basic $ (0.31 ) $ (0.16 ) $ (0.70 ) $ (0.26 ) Diluted $ (0.31 ) $ (0.16 ) $ (0.70 ) $ (0.26 ) __________________________________ (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 13.1 million and 12.9 million for the three months ended September 30, 2018 and 2017 , respectively, and 14.5 million and 12.9 million for the nine months ended September 30, 2018 and 2017 , 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, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of estimated future minimum commitments | Future minimum rental commitments under our leases at September 30, 2018 , are as follows: Payments Due By Year(1) Total 2018(2) 2019 2020 2021 2022 Thereafter (In thousands) Operating leases(3) $ 37,971 $ 1,463 $ 2,775 $ 4,173 $ 3,276 $ 3,326 $ 22,958 __________________________________ (1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator or discrete purchases of long lead items purchased through normal operations and excludes commitments for exploration activities, including well commitments, in our petroleum contracts. (2) Represents payments for the period from October 1, 2018 through December 31, 2018 . (3) Primarily relates to corporate office and foreign office leases. |
Additional Financial Informat_2
Additional Financial Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
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 $ 101,767 $ 144,717 Current asset retirement obligations 11,161 — General and administrative expenses 27,902 31,124 Interest 7,430 20,457 Income taxes 7,618 17,423 Taxes other than income 3,457 3,270 Derivatives 21,704 825 Acquired liabilities 80,783 — Other 488 1,596 $ 262,310 $ 219,412 |
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, 2018 2017 2018 2017 (In thousands) (Gain) loss on disposal of inventory $ (2 ) $ (500 ) $ (26 ) $ 47 Gain on insurance settlements — — — (461 ) Disputed charges and related costs, net of recoveries (12,682 ) 821 (9,721 ) 3,260 Other, net (123 ) (88 ) 1,583 157 Other expenses, net $ (12,807 ) $ 233 $ (8,164 ) $ 3,003 |
Organization (Details)
Organization (Details) | 9 Months Ended |
Sep. 30, 2018segment | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of reportable segments | 1 |
Accounting Policies (Details)
Accounting Policies (Details) - USD ($) $ in Thousands | 9 Months Ended | ||||
Sep. 30, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Dec. 31, 2016 | Aug. 31, 2014 | |
Cash, Cash Equivalents and Restricted Cash | |||||
Cash and cash equivalents | $ 192,646 | $ 233,412 | |||
Restricted cash - current | 5,376 | 56,380 | |||
Restricted cash - long-term | 9,473 | 15,194 | |||
Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows | 207,495 | 304,986 | $ 235,208 | $ 273,195 | |
Inventories | |||||
Materials and supplies inventory | 86,800 | 63,500 | |||
Hydrocarbons inventory | $ 3,200 | 8,400 | |||
Senior Notes | 7.875% senior notes due 2021 | |||||
Cash, Cash Equivalents and Restricted Cash | |||||
Interest rate | 7.875% | 7.875% | |||
Restricted Cash | Petroleum agreements - performance guarantees | |||||
Cash, Cash Equivalents and Restricted Cash | |||||
Restricted cash - current | $ 5,400 | 31,600 | |||
Restricted cash - long-term | 9,200 | 15,200 | |||
Restricted Cash | Non Petroleum agreements | |||||
Cash, Cash Equivalents and Restricted Cash | |||||
Restricted cash - long-term | $ 200 | ||||
Restricted Cash | Facility interest or the Senior Notes plus the Corporate Revolver interest | |||||
Cash, Cash Equivalents and Restricted Cash | |||||
Restricted cash - current | $ 24,800 | ||||
Restricted cash period required as per commercial debt facility to meet interest and commitment fee payments | 6 months | ||||
DGE Acquisition | |||||
Inventories | |||||
Inventory acquired | $ 22,100 |
Accounting Policies Summary of
Accounting Policies Summary of Oil and Gas Revenue (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Provisional oil sales contracts | $ (54,267) | $ (33,021) | $ (232,057) | $ 25,924 |
Oil and gas revenue | 242,833 | 151,240 | 585,220 | 391,035 |
Oil and gas revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Provisional oil sales contracts | 3,075 | (6,221) | 3,584 | (10,781) |
Oil and gas revenue | 242,833 | 151,240 | 585,220 | 391,035 |
Ghana | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | 215,581 | 157,461 | 557,459 | 401,816 |
Gulf of Mexico | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from contracts with customers | $ 24,177 | $ 0 | $ 24,177 | $ 0 |
Acquisitions and Divestitures_2
Acquisitions and Divestitures (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||
Sep. 30, 2018USD ($) | Sep. 30, 2018USD ($) | Aug. 31, 2018USD ($)km²sub_periodblock | Jun. 30, 2018km² | Mar. 31, 2018km²block | Dec. 31, 2017km²block | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($)km² | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Feb. 28, 2018USD ($) | |
Acquisitions and Divestitures | ||||||||||||
Gain on sale of assets | $ 7,666,000 | $ 0 | $ 7,666,000 | $ 0 | ||||||||
Deep Gulf Energy, LP | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Total purchase price | $ 1,275,382,000 | |||||||||||
Cash consideration | 952,586,000 | |||||||||||
Equity consideration | 307,944,000 | |||||||||||
Transaction related costs | $ 14,852,000 | |||||||||||
Revenue of acquiree since acquisition date | $ 24,200,000 | |||||||||||
Operating expenses of acquiree since acquisition date | $ 4,400,000 | |||||||||||
Petroleum Agreement | Blocks 10 and 13 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participating interests | 35.00% | |||||||||||
Area of petroleum exploration | km² | 13,600 | |||||||||||
Exploration period | 4 years | |||||||||||
First sub exploration period | 4 years | |||||||||||
3D seismic requirements | km² | 13,500 | |||||||||||
Number of blocks | block | 2 | |||||||||||
Petroleum Agreement | Blocks EG-21, S and W | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Area of petroleum exploration | km² | 6,000 | |||||||||||
Exploration period | 5 years | |||||||||||
First sub exploration period | 3 years | |||||||||||
3D seismic requirements | km² | 6,000 | |||||||||||
Number of blocks | block | 3 | |||||||||||
Number of sub-periods | sub_period | 2 | |||||||||||
Second sub exploration period | 2 years | |||||||||||
Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participating interests | 45.00% | |||||||||||
Area of petroleum exploration | km² | 17,000 | 17,000 | ||||||||||
Exploration period | 3 years | |||||||||||
3D seismic requirements | km² | 12,000 | |||||||||||
Number of blocks | block | 5 | |||||||||||
Farm-in agreement | Block EG-24 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Area of petroleum exploration | km² | 3,500 | |||||||||||
Exploration period | 3 years | |||||||||||
First sub exploration period | 4 years | |||||||||||
3D seismic requirements | km² | 3,000 | |||||||||||
Participation interest acquired | 40.00% | |||||||||||
Sales and purchase agreement | Ceiba Field and Okume Complex Assets | Hess | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Total purchase price | $ 650,000,000 | |||||||||||
Cash consideration | $ 231,000,000 | |||||||||||
Farm out agreement | Blocks EG-21, S and W | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participating interests | 40.00% | |||||||||||
Gain on sale of assets | $ 7,700,000 | $ 7,700,000 | $ 7,700,000 | |||||||||
BP | Petroleum Agreement | Blocks 10 and 13 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participating interests | 50.00% | |||||||||||
BP | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participating interests | 45.00% | |||||||||||
ANP STP | Petroleum Agreement | Blocks 10 and 13 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Carried participating interest percentage | 15.00% | |||||||||||
Hess | Ceiba Field and Okume Complex Assets | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Paying interest, percentage | 85.00% | |||||||||||
Revenue interest, percentage | 80.75% | |||||||||||
Trident | Farm out agreement | Blocks EG-21, S and W | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Participation interest acquired | 40.00% | |||||||||||
GEPetrol | Petroleum Agreement | Blocks EG-21, S and W | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Carried participating interest percentage | 20.00% | |||||||||||
Percentage converted from carried to participating | 20.00% | |||||||||||
PETROCI Holding | Petroleum Agreement | Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Carried participating interest percentage | 10.00% | 10.00% | ||||||||||
Hess | Sales and purchase agreement | Ceiba Field and Okume Complex Assets | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Ownership percentage | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||
Hess | Trident | Sales and purchase agreement | Ceiba Field and Okume Complex Assets | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Ownership percentage | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||
The Facility | Revolving Credit Facility | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Additional commitments | $ 200,000,000 | $ 200,000,000 | $ 200,000,000 | $ 200,000,000 | $ 200,000,000 | $ 500,000,000 | ||||||
Common Shares | Deep Gulf Energy, LP | ||||||||||||
Acquisitions and Divestitures | ||||||||||||
Equity consideration | $ 307,900,000 |
Acquisitions and Divestitures S
Acquisitions and Divestitures Schedule of Acquisition (Details) - Deep Gulf Energy, LP - USD ($) $ / shares in Units, $ in Thousands | Sep. 14, 2018 | Sep. 30, 2018 |
Fair value of assets acquired: | ||
Unproved oil and gas properties | $ 300,420 | |
Proved oil and gas properties | 1,045,509 | |
Accounts receivable and other | 179,332 | |
Total assets acquired | 1,525,261 | |
Fair value of liabilities assumed: | ||
Accrued liabilities and other | 123,034 | |
Asset retirement obligations | 86,580 | |
Derivative liabilities | 40,265 | |
Total liabilities assumed | 249,879 | |
Cash consideration paid | 952,586 | |
Fair value of common stock | 307,944 | |
Transaction related costs | 14,852 | |
Total purchase price | 1,275,382 | |
Share price (in dollars per share) | $ 8.80 | |
Common Shares | ||
Fair value of liabilities assumed: | ||
Fair value of common stock | $ 307,900 | |
Common shares issued (in shares) | 34,993,585 |
Joint Interest Billings and R_2
Joint Interest Billings and Related Party Receivables (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2014 | Sep. 30, 2018 | Dec. 31, 2017 | |
Joint interest billings | |||
Joint interest billings, net | $ 84,209 | $ 134,565 | |
Long-term receivables - joint interest billings | 21,861 | 34,941 | |
Related party receivable | 20,834 | 780 | |
TEN Discoveries | GNPC | |||
Joint interest billings | |||
Joint interest billings, net | 14,000 | 15,200 | |
Long-term receivables - joint interest billings | 21,900 | $ 31,600 | |
TEN Discoveries | GNPC | |||
Joint interest billings | |||
GNPC's paying interest | 5.00% | ||
Kosmos-Trident International Petroleum Inc. | |||
Joint interest billings | |||
Related party receivable | 7,100 | ||
Farm out agreement | Blocks EG-21, S and W | Trident | |||
Joint interest billings | |||
Related party receivable | $ 13,700 | ||
Kosmos-Trident International Petroleum Inc. | Trident | |||
Joint interest billings | |||
Ownership percentage | 50.00% |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Oil and gas properties: | |||||
Proved properties | $ 2,749,163 | $ 2,749,163 | $ 1,653,616 | ||
Unproved properties | 733,274 | 733,274 | 465,109 | ||
Support equipment and facilities | 1,450,907 | 1,450,907 | 1,427,054 | ||
Total oil and gas properties | 4,933,344 | 4,933,344 | 3,545,779 | ||
Accumulated depletion | (1,434,489) | (1,434,489) | (1,234,806) | ||
Oil and gas properties, net | 3,498,855 | 3,498,855 | 2,310,973 | ||
Other property | 46,513 | 46,513 | 39,405 | ||
Accumulated depreciation | (35,831) | (35,831) | (32,550) | ||
Other property, net | 10,682 | 10,682 | 6,855 | ||
Property and equipment, net | 3,509,537 | 3,509,537 | $ 2,317,828 | ||
Depletion expense | $ 76,800 | $ 70,900 | $ 199,700 | $ 173,300 |
Suspended Well Costs - Summary
Suspended Well Costs - Summary of Suspended Well Costs (Details) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2018USD ($) | Sep. 30, 2018USD ($)project | Dec. 31, 2017USD ($)project | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||
Capitalized exploratory well costs subsequently expensed in the same period | $ 48,000 | ||
Reconciliation of capitalized exploratory well costs on completed wells | |||
Beginning balance | 410,113 | ||
Additions associated with the acquisition of DGE | 26,426 | ||
Additions to capitalized exploratory well costs pending the determination of proved reserves | 7,658 | ||
Reclassification due to determination of proved reserves | 0 | ||
Capitalized exploratory well costs charged to expense | (52,498) | ||
Ending balance | 391,699 | ||
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 | $ 26,426 | $ 67,159 | |
Exploratory well costs capitalized for a period of one to two years | 296,866 | 291,252 | |
Exploratory well costs capitalized for a period of three years | 68,407 | 51,702 | |
Ending balance | $ 410,113 | $ 391,699 | $ 410,113 |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | project | 3 | 5 |
Suspended Well Costs - Narrativ
Suspended Well Costs - Narrative (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018ft | Sep. 30, 2018m | Sep. 30, 2018USD ($) | Sep. 30, 2018USD ($) | May 31, 2015project | |
Capitalized Contract Cost [Line Items] | |||||
Capitalized exploratory well cost, charged to expense | $ 52,498 | ||||
Akasa Discovery | |||||
Capitalized Contract Cost [Line Items] | |||||
Capitalized exploratory well cost, charged to expense | $ 39,800 | ||||
Wawa Discovery | |||||
Capitalized Contract Cost [Line Items] | |||||
Capitalized exploratory well cost, charged to expense | $ 17,900 | ||||
Greater Tortue Discovery | |||||
Capitalized Contract Cost [Line Items] | |||||
Number of additional appraisal wells drilled | project | 2 | ||||
Nearly Headless Nick Discovery [Member] | |||||
Capitalized Contract Cost [Line Items] | |||||
Working interest percentage | 22.00% | 22.00% | 22.00% | 22.00% | |
Suspended well depth | 19,050 | 5,800 | |||
Suspended well net pay | 85 | 26 |
Equity Method Investments - Nar
Equity Method Investments - Narrative (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
Oct. 31, 2018 | Oct. 31, 2017 | Feb. 28, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Gain (loss) on equity method investments, net | $ 24,841,000 | $ (4,804,000) | $ 59,637,000 | $ (11,230,000) | |||
Contribution to equity method investment | $ 0 | 133,893,000 | |||||
Kosmos BP Senegal Limited | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Ownership percentage | 50.01% | ||||||
Gain (loss) on equity method investments, net | $ (4,800,000) | $ (11,200,000) | |||||
Contribution to equity method investment | $ 133,900,000 | ||||||
Kosmos-Trident International Petroleum Inc. | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Ownership percentage | 50.00% | 50.00% | |||||
Gain (loss) on equity method investments, net | $ 24,841,000 | $ 59,637,000 | |||||
Impairment of equity method investment | 0 | ||||||
Cash dividends from KTIPI | $ 207,500,000 | ||||||
Kosmos BP Senegal Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Participating interests | 30.00% | ||||||
BP Senegal Investments Limited | Cayar Offshore Profond And Saint Louis Offshore Profond Blocks | Kosmos BP Senegal Limited | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Participating interest transferred | 30.00% | ||||||
Subsequent Event | Kosmos-Trident International Petroleum Inc. | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Cash dividends from KTIPI | $ 32,500,000 |
Equity Method Investments - Sum
Equity Method Investments - Summary of Financial Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Costs and expenses: | |||||
Equity in earnings - KTIPI | $ 24,841 | $ (4,804) | $ 59,637 | $ (11,230) | |
Kosmos-Trident International Petroleum Inc. | |||||
Schedule of Equity Method Investments [Line Items] | |||||
Ownership percentage | 50.00% | 50.00% | |||
Basis presented | 100.00% | 100.00% | |||
Assets | |||||
Total current assets | $ 158,140 | $ 158,140 | $ 179,070 | ||
Property and equipment, net | 291,960 | 291,960 | 345,611 | ||
Other assets | 487 | 487 | 567 | ||
Total assets | 450,587 | 450,587 | 525,248 | ||
Liabilities and shareholders' equity | |||||
Total current liabilities | 196,338 | 196,338 | 106,769 | ||
Total long-term liabilities | 541,881 | 541,881 | 565,591 | ||
Shareholders' equity: | |||||
Total shareholders' equity | (287,632) | (287,632) | (147,112) | ||
Total liabilities and shareholders' equity | 450,587 | 450,587 | $ 525,248 | ||
Revenues and other income: | |||||
Oil and gas revenue | 215,408 | 600,158 | |||
Other income | (72) | 44 | |||
Total revenues and other income | 215,336 | 600,202 | |||
Costs and expenses: | |||||
Oil and gas production | 40,334 | 115,366 | |||
Depletion and depreciation | 33,044 | 108,996 | |||
Other expenses, net | (58) | (211) | |||
Total costs and expenses | 73,320 | 224,151 | |||
Income before income taxes | 142,016 | 376,051 | |||
Income tax expense | 50,796 | 134,047 | |||
Net income | 91,220 | 242,004 | |||
Kosmos' share of net income | 45,610 | 121,002 | |||
Basis difference amortization | 20,769 | 61,365 | |||
Equity in earnings - KTIPI | $ 24,841 | $ 59,637 |
Debt - Schedule of Instruments
Debt - Schedule of Instruments (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Debt | ||
Outstanding debt principal | $ 2,150,000 | $ 1,325,000 |
Unamortized issuance costs and discount | (55,466) | (42,203) |
Long-term debt, net | 2,094,534 | 1,282,797 |
Senior Notes | ||
Debt | ||
Outstanding debt principal | 525,000 | 525,000 |
Unamortized issuance costs and discount | (15,200) | (18,600) |
The Facility | Revolving Credit Facility | ||
Debt | ||
Outstanding debt principal | 1,325,000 | 800,000 |
Unamortized issuance costs and discount | (40,300) | (23,600) |
Corporate Revolver | Revolving Credit Facility | ||
Debt | ||
Outstanding debt principal | $ 300,000 | $ 0 |
Debt - Facility (Details)
Debt - Facility (Details) | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Feb. 28, 2018USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Aug. 31, 2018USD ($)financial_institution | |
Debt Instrument [Line Items] | ||||||
Loss on extinguishment of debt | $ 268,000 | $ 0 | $ 4,324,000 | $ 0 | ||
The Facility | Revolving Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Total commitment | $ 1,500,000,000 | |||||
Additional commitments | 500,000,000 | 200,000,000 | 200,000,000 | $ 200,000,000 | ||
Number of financial institutions | financial_institution | 2 | |||||
Loss on extinguishment of debt | $ 4,100,000 | |||||
Net deferred financing costs | 40,300,000 | 40,300,000 | ||||
Amount outstanding | 1,325,000,000 | 1,325,000,000 | ||||
Undrawn availability | 375,000,000 | 375,000,000 | ||||
Availability period of revolving-credit | 1 month | |||||
Amount outstanding under letters of credit | $ 0 | $ 0 |
Debt - Corporate Revolver (Deta
Debt - Corporate Revolver (Details) - USD ($) | 1 Months Ended | ||
Aug. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | |||
Net deferred financing costs | $ 9,582,000 | $ 2,510,000 | |
Corporate Revolver | Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 400,000,000 | ||
Change in basis points | (1.00%) | ||
Applicable margin | 5.00% | ||
Commitment fee percentage | 30.00% | ||
Amount outstanding | 300,000,000 | ||
Undrawn availability | 100,000,000 | ||
Net deferred financing costs | $ 9,600,000 |
Debt - Revolving Letter of Cred
Debt - Revolving Letter of Credit Facility (Details) - Revolving Letter of Credit Facility | Sep. 30, 2018USD ($)letter_of_credit | Jul. 31, 2018USD ($) |
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 40,000,000 | |
Number of letters of credit | letter_of_credit | 8 | |
Amount outstanding | $ 16,900,000 |
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 | Sep. 30, 2018 | |
Debt Instrument [Line Items] | |||
Interest rate | 7.875% | 7.875% | |
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 ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Scheduled maturities of debt during the five year period and thereafter | ||
Total | $ 2,150,000 | $ 1,325,000 |
2,018 | 0 | |
2,019 | 0 | |
2,020 | 0 | |
2,021 | 685,600 | |
2,022 | 589,100 | |
Thereafter | 875,300 | |
Senior Notes | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Total | 525,000 | 525,000 |
7.875% senior notes due 2021 | Senior Notes | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Total | 525,000 | |
Corporate Revolver | Revolving Credit Facility | ||
Scheduled maturities of debt during the five year period and thereafter | ||
Total | 300,000 | $ 0 |
Amount outstanding | $ 300,000 |
Debt - Interest and other finan
Debt - Interest and other financing costs, net (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Debt Disclosure [Abstract] | ||||
Interest expense | $ 27,317 | $ 22,961 | $ 77,121 | $ 68,934 |
Amortization—deferred financing costs | 2,346 | 2,551 | 7,069 | 7,653 |
Loss on extinguishment of debt | 268 | 0 | 4,324 | 0 |
Capitalized interest | (7,097) | (8,563) | (21,209) | (25,498) |
Deferred interest | (194) | 662 | (1,284) | 1,610 |
Interest income | (788) | (745) | (2,579) | (2,485) |
Other, net | 1,697 | 1,612 | 4,671 | 4,515 |
Interest and other financing costs, net | $ 23,549 | $ 18,478 | $ 68,113 | $ 54,729 |
Derivative Financial Instrume_3
Derivative Financial Instruments - Schedule of oil derivative contracts (Details) | 9 Months Ended |
Sep. 30, 2018$ / bblMBbls | |
Dated Brent | Term October 2018 to December 2018 | Swap with puts | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 1,500 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 56.75 |
Sold Put (usd per bbl) | 43.33 |
Floor (usd per bbl) | 0 |
Ceiling (usd per bbl) | 0 |
Call (usd per bbl) | 0 |
Dated Brent | Term October 2018 to December 2018 | Three-way collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 733 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (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) | 65.91 |
Call (usd per bbl) | 0 |
Dated Brent | Term October 2018 to December 2018 | Four-way collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 751 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (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 |
Dated Brent | Term October 2018 to December 2018 | Sold calls | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 503 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (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 |
Dated Brent | Term October 2018 to December 2018 | Purchased Calls | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 500 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 1.88 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 0 |
Ceiling (usd per bbl) | 0 |
Call (usd per bbl) | 70 |
Dated Brent | Term January 2019 to December 2019 | Three-way collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 10,500 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 1.17 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 43.81 |
Floor (usd per bbl) | 53.33 |
Ceiling (usd per bbl) | 73.58 |
Call (usd per bbl) | 0 |
Dated Brent | Term January 2019 to December 2019 | Sold calls | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 913 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (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 |
Dated Brent | Term January 2020 To December 2020 | Three-way collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 2,000 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 50 |
Floor (usd per bbl) | 60 |
Ceiling (usd per bbl) | 90.54 |
Call (usd per bbl) | 0 |
Dated Brent | Term January 2020 To December 2020 | Sold calls | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 8,000 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (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 |
NYMEX WTI | Term October 2018 to December 2018 | Purchased Puts | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 141 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 2.70 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 53 |
Ceiling (usd per bbl) | 0 |
Call (usd per bbl) | 0 |
NYMEX WTI | Term October 2018 to December 2018 | Collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 35 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 62.29 |
Ceiling (usd per bbl) | 66.35 |
Call (usd per bbl) | 0 |
NYMEX WTI | Term October 2018 to December 2018 | Swaps | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 698 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 54.69 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 0 |
Ceiling (usd per bbl) | 0 |
Call (usd per bbl) | 0 |
NYMEX WTI | Term January 2019 to December 2019 | Swaps | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 1,747 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 52.31 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 0 |
Ceiling (usd per bbl) | 0 |
Call (usd per bbl) | 0 |
NYMEX WTI | Term January 2019 to June 2019 | Collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 339 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 57.77 |
Ceiling (usd per bbl) | 63.70 |
Call (usd per bbl) | 0 |
Argus LLS | Term January 2019 to December 2019 | Collars | |
Derivative Financial Instruments | |
Volume (mbbls) | MBbls | 1,000 |
Weighted Average Price Per Bbl [Abstract] | |
Net Deferred Premium Payable/ (Receivable) (usd per bbl) | 0 |
Swap (usd per bbl) | 0 |
Sold Put (usd per bbl) | 0 |
Floor (usd per bbl) | 60 |
Ceiling (usd per bbl) | 88.75 |
Call (usd per bbl) | 0 |
Derivative Financial Instrume_4
Derivative Financial Instruments - Schedule of interest rate derivative contracts (Details) - 1-month LIBOR - Interest Rate Cap Swap - Term October 2018 to December 2018 $ in Thousands | Sep. 30, 2018USD ($) |
Derivative Financial Instruments | |
Weighted average notional amount | $ 200,000 |
Weighted average swap | 1.23% |
Weighted average sold call | 3.00% |
Derivative Financial Instrume_5
Derivative Financial Instruments - Derivatives instrument and gain/loss from derivatives (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | $ 41,466 | $ 1,682 |
Derivatives assets—long-term | 14,486 | 39 |
Derivatives liabilities—current | (212,217) | (67,531) |
Derivatives liabilities—long-term | (110,245) | (30,209) |
Derivatives not designated as hedging instruments: | ||
Derivative instruments, Balance Sheet Location | ||
Total derivatives not designated as hedging instruments | (266,510) | (96,019) |
Derivatives not designated as hedging instruments: | Commodity | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | 40,953 | 665 |
Derivatives assets—long-term | 14,486 | 39 |
Derivatives liabilities—current | (212,217) | (67,531) |
Derivatives liabilities—long-term | (110,245) | (30,209) |
Net deferred premiums payable related to commodity derivative contracts - current assets | 4,700 | |
Net deferred premiums receivable related to commodity derivative contracts - current assets | 800 | |
Net deferred premiums payable related to commodity derivative contracts - non-current assets | 2,400 | |
Net deferred premiums receivable related to commodity derivative contracts - non-current assets | 100 | |
Net deferred premiums payable related to commodity derivative contracts - current liabilities | 6,000 | 5,600 |
Net deferred premiums payable related to commodity derivative contracts - non-current liabilities | 1,600 | 4,800 |
Derivatives not designated as hedging instruments: | Interest rate | ||
Derivative instruments, Balance Sheet Location | ||
Derivatives assets—current | $ 513 | $ 1,017 |
Derivative Financial Instrume_6
Derivative Financial Instruments - Schedule of derivative instruments by location of gain/(loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | $ (54,267) | $ (33,021) | $ (232,057) | $ 25,924 |
Commodity | Oil and gas revenue | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | 3,075 | (6,221) | 3,584 | (10,781) |
Commodity | Derivatives, net | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | (57,357) | (26,864) | (236,107) | 36,404 |
Interest rate | Interest expense | ||||
Derivative instruments, Location of Gain/(Loss) | ||||
Amount of Gain/(Loss) | $ 15 | $ 64 | $ 466 | $ 301 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2018 | Dec. 31, 2017 |
Carrying Value | ||
Liabilities: | ||
Long-term debt | $ 2,135,766 | $ 1,307,600 |
Fair Value | ||
Liabilities: | ||
Long-term debt | 2,160,941 | 1,342,472 |
Senior Notes | Carrying Value | ||
Liabilities: | ||
Long-term debt | 510,766 | 507,600 |
Senior Notes | Fair Value | ||
Liabilities: | ||
Long-term debt | 535,941 | 542,472 |
Recurring basis | ||
Liabilities: | ||
Total fair value, net | (266,510) | (96,019) |
Recurring basis | Commodity | ||
Assets: | ||
Derivative asset, fair value | 55,439 | 704 |
Liabilities: | ||
Derivative liability, fair value | (322,462) | (97,740) |
Recurring basis | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 513 | 1,017 |
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 |
Recurring basis | Significant Other Observable Inputs (Level 2) | ||
Liabilities: | ||
Total fair value, net | (266,510) | (96,019) |
Recurring basis | Significant Other Observable Inputs (Level 2) | Commodity | ||
Assets: | ||
Derivative asset, fair value | 55,439 | 704 |
Liabilities: | ||
Derivative liability, fair value | (322,462) | (97,740) |
Recurring basis | Significant Other Observable Inputs (Level 2) | Interest rate | ||
Assets: | ||
Derivative asset, fair value | 513 | 1,017 |
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 |
Corporate Revolver | Facility | Carrying Value | ||
Liabilities: | ||
Long-term debt | 300,000 | 0 |
Corporate Revolver | Facility | Fair Value | ||
Liabilities: | ||
Long-term debt | 300,000 | 0 |
The Facility | Facility | Carrying Value | ||
Liabilities: | ||
Long-term debt | 1,325,000 | 800,000 |
The Facility | Facility | Fair Value | ||
Liabilities: | ||
Long-term debt | $ 1,325,000 | $ 800,000 |
Equity-based Compensation - Add
Equity-based Compensation - Additional Information (Details) - LTIP - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jan. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Compensation expense recognized | $ 8.9 | $ 9.6 | $ 26 | $ 29.9 | |
Tax benefit | 1.6 | 3.2 | 5 | 9.9 | |
Net tax shortfall (windfall) related to equity-based compensation | 0.1 | 0.2 | (0.3) | 3.1 | |
Fair value of awards vested | $ 1.1 | $ 1.4 | $ 83.1 | $ 20.7 | |
Vesting period | 3 years | ||||
Number of additional shares authorized (in shares) | 11,000,000 | ||||
Number of shares authorized (in shares) | 50,500,000 | 50,500,000 | |||
Number of shares remaining available for grant (in shares) | 15,800,000 | 15,800,000 | |||
Restricted Stock Units (RSUs) | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Compensation expense not yet recognized | $ 36.2 | $ 36.2 | |||
Weighted average period over which compensation expense is to be recognized | 2 years 18 days | ||||
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) | $ 12.39 | ||||
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 | 0.70% | ||||
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) | $ 15.71 | ||||
Expected volatility | 53.00% | ||||
Risk-free interest rate | 2.20% |
Equity-based Compensation - Sch
Equity-based Compensation - Schedule of awards (Details) - LTIP shares in Thousands | 9 Months Ended |
Sep. 30, 2018$ / sharesshares | |
Service Vesting Restricted Stock Awards | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | 220 |
Granted (in shares) | 0 |
Forfeited (in shares) | 0 |
Vested (in shares) | (220) |
Outstanding at the end of the period (in shares) | 0 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ / shares | $ 8.64 |
Granted (in dollars per share) | $ / shares | 0 |
Forfeited (in dollars per share) | $ / shares | 0 |
Vested (in dollars per share) | $ / shares | 8.64 |
Outstanding at the end of the period (in dollars per share) | $ / shares | $ 0 |
Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | 4,183 |
Granted (in shares) | 2,360 |
Forfeited (in shares) | (116) |
Vested (in shares) | (2,173) |
Outstanding at the end of the period (in shares) | 4,254 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ / shares | $ 6.39 |
Granted (in dollars per share) | $ / shares | 7.03 |
Forfeited (in dollars per share) | $ / shares | 6.49 |
Vested (in dollars per share) | $ / shares | 6.93 |
Outstanding at the end of the period (in dollars per share) | $ / shares | $ 6.41 |
Market/Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Outstanding at the beginning of the period (in shares) | 8,452 |
Granted (in shares) | 8,140 |
Forfeited (in shares) | (46) |
Vested (in shares) | (9,545) |
Outstanding at the end of the period (in shares) | 7,001 |
Weighted-Average Grant-Date Fair Value | |
Outstanding at beginning of the period (in dollars per share) | $ / shares | $ 11.26 |
Granted (in dollars per share) | $ / shares | 12.39 |
Forfeited (in dollars per share) | $ / shares | 9.74 |
Vested (in dollars per share) | $ / shares | 13.75 |
Outstanding at the end of the period (in dollars per share) | $ / shares | $ 9.17 |
2014 and 2015 | Market/Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Granted (in shares) | 4,900 |
Weighted-Average Grant-Date Fair Value | |
Vesting percentage of the awards granted | 200.00% |
DGE Employees | Market/Service Vesting Restricted Stock Units | |
Outstanding unvested awards activity | |
Granted (in shares) | 700 |
Weighted-Average Grant-Date Fair Value | |
Granted (in dollars per share) | $ / shares | $ 12.93 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Income Taxes | ||||
Effective tax rate (as a percent) | 10.00% | 2.00% | 17.00% | 79.00% |
Income (loss) before income taxes | $ (114,693) | $ (64,920) | $ (337,885) | $ (56,312) |
Uncertain tax positions | 0 | 0 | ||
Bermuda | ||||
Income Taxes | ||||
Income (loss) before income taxes | (15,513) | (17,740) | (47,474) | (50,680) |
United States | ||||
Income Taxes | ||||
Income (loss) before income taxes | (53,136) | 1,437 | $ (49,967) | 4,231 |
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 | $ (46,044) | $ (48,617) | $ (240,444) | $ (9,863) |
Net Loss Per Share (Details)
Net Loss Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Numerator: | ||||
Net loss | $ (126,057) | $ (63,405) | $ (279,556) | $ (100,713) |
Basic income allocable to participating securities | 0 | 0 | 0 | 0 |
Basic net loss allocable to common shareholders | (126,057) | (63,405) | (279,556) | (100,713) |
Diluted adjustments to income allocable to participating securities | 0 | 0 | 0 | 0 |
Diluted net loss allocable to common shareholders | $ (126,057) | $ (63,405) | $ (279,556) | $ (100,713) |
Weighted average number of shares outstanding: | ||||
Basic (in shares) | 404,536 | 389,058 | 399,026 | 388,114 |
Restricted stock awards and units (in shares) | 0 | 0 | 0 | 0 |
Diluted (in shares) | 404,536 | 389,058 | 399,026 | 388,114 |
Net loss per share: | ||||
Basic (in dollars per share) | $ (0.31) | $ (0.16) | $ (0.70) | $ (0.26) |
Diluted (in dollars per share) | $ (0.31) | $ (0.16) | $ (0.70) | $ (0.26) |
Outstanding restricted stock awards and units excluded from the computations of diluted net income per share (in shares) | 13,100 | 12,900 | 14,500 | 12,900 |
Commitments and Contingencies_2
Commitments and Contingencies (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2018USD ($)km²exploration_well | |
Future minimum rental commitments | |
Total | $ 37,971 |
2,018 | 1,463 |
2,019 | 2,775 |
2,020 | 4,173 |
2,021 | 3,276 |
2,022 | 3,326 |
Thereafter | $ 22,958 |
Mauritania | |
Commitments and contingencies | |
Number of exploration wells | exploration_well | 1 |
Senegal | |
Commitments and contingencies | |
Number of exploration wells | exploration_well | 2 |
Equatorial Guinea | |
Commitments and contingencies | |
3D seismic requirements | km² | 9,000 |
Sao Tome and Principe | |
Commitments and contingencies | |
3D seismic requirements | km² | 13,500 |
Surety Bond | Gulf of Mexico | |
Future minimum rental commitments | |
Cash collateral | $ 600 |
Bureau Of Ocean Energy Management | Surety Bond | Gulf of Mexico | |
Future minimum rental commitments | |
Required performance bonds | 214,000 |
Third Party | Surety Bond | Gulf of Mexico | |
Future minimum rental commitments | |
Required performance bonds | $ 4,000 |
Additional Financial Informat_3
Additional Financial Information (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||||
Aug. 31, 2018 | Jul. 31, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | |
Accrued liabilities: | |||||||
Exploration, development and production | $ 101,767,000 | $ 101,767,000 | $ 144,717,000 | ||||
Current asset retirement obligations | 11,161,000 | 11,161,000 | 0 | ||||
General and administrative expenses | 27,902,000 | 27,902,000 | 31,124,000 | ||||
Interest | 7,430,000 | 7,430,000 | 20,457,000 | ||||
Income taxes | 7,618,000 | 7,618,000 | 17,423,000 | ||||
Taxes other than income | 3,457,000 | 3,457,000 | 3,270,000 | ||||
Derivatives | 21,704,000 | 21,704,000 | 825,000 | ||||
Acquired liabilities | 80,783,000 | 80,783,000 | 0 | ||||
Other | 488,000 | 488,000 | 1,596,000 | ||||
Accrued liabilities | 262,310,000 | 262,310,000 | $ 219,412,000 | ||||
Other income, net | 0 | $ 58,700,000 | |||||
Other Expenses, Net | |||||||
Gain on sale of assets | 7,666,000 | $ 0 | 7,666,000 | 0 | |||
(Gain) loss on disposal of inventory | (2,000) | (500,000) | (26,000) | 47,000 | |||
Gain on insurance settlements | 0 | 0 | 0 | (461,000) | |||
Disputed charges and related costs, net of recoveries | (12,682,000) | 821,000 | (9,721,000) | 3,260,000 | |||
Other, net | (123,000) | (88,000) | 1,583,000 | 157,000 | |||
Other expenses, net | (12,807,000) | $ 233,000 | (8,164,000) | 3,003,000 | |||
Recoveries | $ 12,900,000 | ||||||
Oil and gas production expense | |||||||
Accrued liabilities: | |||||||
Insurance recoveries | 0 | $ 17,100,000 | |||||
Farm out agreement | Blocks EG-21, S and W | |||||||
Other Expenses, Net | |||||||
Gain on sale of assets | $ 7,700,000 | $ 7,700,000 | $ 7,700,000 |