Notes to Consolidated Financial Statements
(Unaudited)
1. Organization
Kosmos Energy Ltd. was originally incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018 and transferred all of our equity interests in Kosmos Energy Holdings to a new, wholly-owned subsidiary, Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.
Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. 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 proven basin exploration program in Equatorial Guinea, Ghana and U.S. Gulf of Mexico. Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.
Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico.
2. Accounting Policies
General
The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. 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 interim consolidated financial statements were prepared in accordance with the requirements of the SEC for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim consolidated financial statements. These interim consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2020, 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 significant impact on our reported net loss, current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
$
|
149,550
|
|
|
$
|
149,027
|
|
|
Restricted cash - current
|
43,208
|
|
|
195
|
|
|
Restricted cash - long-term
|
305
|
|
|
542
|
|
|
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows
|
$
|
193,063
|
|
|
$
|
149,764
|
|
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. When our net leverage ratio exceeds 2.50x, we are required under the
Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of June 30, 2021 we have restricted cash of approximately $42.9 million to meet our requirements. In February 2021, we amended certain terms of the GoM Term Loan agreement, and as a result we restricted cash of $20.0 million as of March 31, 2021. In the second quarter of 2021 this restriction was released under the terms of the GoM Term Loan agreement, and as a result we released the restriction on the $20.0 million as of June 30, 2021.
In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. Certain of 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 respective 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
Inventories consisted of $133.1 million and $127.5 million of materials and supplies and $1.8 million and $1.5 million of hydrocarbons as of June 30, 2021 and December 31, 2020, 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
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection 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 June 30,
|
|
Six Months Ended June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
(In thousands)
|
|
Revenues from contract with customer - Equatorial Guinea
|
$
|
84,699
|
|
|
$
|
28,147
|
|
|
$
|
111,131
|
|
|
$
|
52,518
|
|
|
Revenues from contract with customer - Ghana
|
196,536
|
|
|
64,577
|
|
|
255,886
|
|
|
114,250
|
|
|
Revenues from contract with customers - U.S. Gulf of Mexico
|
107,890
|
|
|
39,222
|
|
|
202,279
|
|
|
142,674
|
|
|
Provisional oil sales contracts
|
(5,080)
|
|
|
(4,632)
|
|
|
(8,777)
|
|
|
(4,348)
|
|
|
Oil and gas revenue
|
$
|
384,045
|
|
|
$
|
127,314
|
|
|
$
|
560,519
|
|
|
$
|
305,094
|
|
Concentration of Credit Risk
Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are available, we believe that the loss of our marketing agents and/or any of the purchasers identified by our marketing agents would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption resulting from the COVID-19 pandemic could materially impact the Company’s business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.
Recent Accounting Standards
In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes”. Our adoption of ASU 2019-12 on January 1, 2021, did not have a material impact on our income tax expense.
3. Acquisitions and Divestitures
During the third quarter of 2020, Kosmos entered into an agreement with Shell to farm down interests in a portfolio of frontier exploration assets for cash consideration of $96.0 million and future contingent consideration of up to $100.0 million. Under the terms of the agreement, Shell acquired Kosmos' participating interest in blocks offshore Sao Tome and Principe, (excluding Block 5 offshore Sao Tome and Principe), Suriname and Namibia, and will acquire our participating interest in South Africa. Kosmos received proceeds totaling $95.0 million during the fourth quarter of 2020 resulting in gain on sale of assets of $92.1 million, with the remaining proceeds of $1.0 million related to Kosmos' participating interest in South Africa expected to be received in 2021 upon customary approval by the government of The Republic of South Africa. The future contingent consideration is payable by Shell upon approval of the relevant operating committee of an appraisal plan for submission to the relevant governmental authority for any of the first four exploration wells it elects to drill in the purchased assets, excluding South Africa. Shell will pay us $50.0 million for each appraisal plan approved by the relevant operating committee to be submitted, subject to an aggregate cap of $100.0 million, or two $50.0 million payments.
4. Joint Interest Billings and Notes Receivables
Joint Interest Billings
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. 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 Ghana, the foreign contractor group funded GNPC’s 5% share of the TEN development costs. The foreign contractor group is being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of June 30, 2021 and December 31, 2020, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $5.8 million and $5.8 million, respectively, and the long-term portions were $24.0 million and $21.2 million, respectively.
Notes Receivables
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us separately to finance the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently projected in 2023. Kosmos’ share for the two agreements combined is up to $239.7 million, which is to be repaid with interest through the national oil companies’ share of future revenues. As of June 30, 2021 and December 31, 2020, the balance due from the national oil companies was $136.0 million and $96.3 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets.
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
(In thousands)
|
|
Oil and gas properties:
|
|
|
|
|
Proved properties
|
$
|
5,624,584
|
|
|
$
|
5,369,737
|
|
|
Unproved properties
|
512,821
|
|
|
495,390
|
|
|
Total oil and gas properties
|
6,137,405
|
|
|
5,865,127
|
|
|
Accumulated depletion
|
(2,770,605)
|
|
|
(2,554,851)
|
|
|
Oil and gas properties, net
|
3,366,800
|
|
|
3,310,276
|
|
|
|
|
|
|
|
Other property
|
58,684
|
|
|
59,949
|
|
|
Accumulated depreciation
|
(50,841)
|
|
|
(49,312)
|
|
|
Other property, net
|
7,843
|
|
|
10,637
|
|
|
|
|
|
|
|
Property and equipment, net
|
$
|
3,374,643
|
|
|
$
|
3,320,913
|
|
We recorded depletion expense of $145.1 million and $115.7 million for the three months ended June 30, 2021 and 2020, respectively, and $215.8 million and $202.9 million for the six months ended June 30, 2021 and 2020, respectively. During the three months ended June 30, 2021 and 2020, no oil and gas asset impairments were recorded. During the six months ended June 30, 2021 and 2020, we recorded asset impairments totaling zero and $150.8 million, respectively, in our consolidated statement of operations in connection with fair value assessments for oil and gas proved properties.
6. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2021.
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
|
(In thousands)
|
|
Beginning balance
|
$
|
186,289
|
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
15,105
|
|
|
Reclassification due to determination of proved reserves
|
(201)
|
|
|
Capitalized exploratory well costs charged to expense
|
—
|
|
|
Ending balance
|
$
|
201,193
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
(In thousands, except well counts)
|
|
Exploratory well costs capitalized for a period of one year or less
|
$
|
9,755
|
|
|
$
|
—
|
|
|
Exploratory well costs capitalized for a period of one to two years
|
29,591
|
|
|
28,692
|
|
|
Exploratory well costs capitalized for a period of three to five years
|
161,847
|
|
|
157,597
|
|
|
Ending balance
|
$
|
201,193
|
|
|
$
|
186,289
|
|
|
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
|
3
|
|
|
3
|
|
As of June 30, 2021, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania, the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal and the Asam discovery in Block S offshore Equatorial Guinea.
BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well 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. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. The BirAllah and Orca discoveries are being analyzed as a joint development.
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 to the government of Senegal. In September 2019, we completed the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. Following additional evaluation, a decision regarding commerciality is expected to be made. The Yakaar and Teranga discoveries are being analyzed as a joint development.
Asam Discovery — In October 2019, we completed the S-5 exploration well offshore Equatorial Guinea, which encountered hydrocarbon pay. In July 2020, an appraisal plan was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and work is currently ongoing to integrate all available data into models to establish the scale of the discovered resource. Additionally, engineering is progressing concepts around required subsea infrastructure necessary for a subsea tieback. Once the appraisal plan involving this work is complete, a decision regarding commerciality will be made.
7. Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
(In thousands)
|
|
Outstanding debt principal balances:
|
|
|
|
|
Facility
|
$
|
1,000,000
|
|
|
$
|
1,200,000
|
|
|
Corporate Revolver
|
—
|
|
|
100,000
|
|
|
7.125% Senior Notes
|
650,000
|
|
|
650,000
|
|
|
7.500% Senior Notes
|
450,000
|
|
|
—
|
|
|
GoM Term Loan
|
200,000
|
|
|
200,000
|
|
|
Total
|
2,300,000
|
|
|
2,150,000
|
|
|
Unamortized deferred financing costs and discounts
|
(53,588)
|
|
|
(38,569)
|
|
|
Total debt, net
|
2,246,412
|
|
|
2,111,431
|
|
|
Less: Current maturities of long-term debt
|
(22,500)
|
|
|
(7,500)
|
|
|
Long-term debt, net
|
$
|
2,223,912
|
|
|
$
|
2,103,931
|
|
__________________________________
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2021, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the facility was $235.2 million. In May 2021, the Company entered into an amended and restated facility agreement and certain ancillary documents. The amendments to the terms of the Facility included the following:
•the extension of the maturity date by two years (final maturity date now occurs on March 31, 2027),
•the extension of the amortization schedule such that amortization of principal is to commence on March 31, 2024 and continue in equal amounts every six months thereafter until the maturity date,
•an increase in the interest margin by 0.5% (applicable interest margin for the first three years is now LIBOR +3.75%),
•the incorporation of a mechanism for two ESG key performance indicators (“KPIs”) to impact the interest margin either positively or negatively based upon delivering emissions targets and achieving certain third party ESG ratings,
•an increase in the Loan Life Coverage Ratio from 1.10x to 1.30x after March 31, 2024,
•the removal of Kosmos Energy Investments Senegal Limited, Kosmos Energy Senegal and Kosmos Energy Mauritania as borrowers, guarantors and pledged subsidiaries, and
•a reduction in the Facility size to $1.25 billion (from $1.5 billion).
As amended, the Facility has an available borrowing base of approximately $1.24 billion. As part of the amendment, the Company incurred $15.2 million for loss on extinguishment of debt during the second quarter of 2021. The Facility amendment contains other customary representations and warranties, covenants and informational undertakings, in each case, subject to certain exceptions and conditions. The Facility amendment also provides for certain customary events of default, including, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults to certain indebtedness, certain events of insolvency, judgment defaults, and repudiation or rescission of certain documents supporting the amendment. If such an event of default occurs, the agents under such amendment are entitled to take various actions, including the cancellation of any outstanding commitments, acceleration of amounts due thereunder and taking certain permitted enforcement actions under the ancillary security documents, subject in each case to the terms of the Facility amendment and such security documents.
When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes and the 7.500%
Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of June 30, 2021 we have restricted cash of approximately $42.9 million to meet our requirements.
As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Facility, as amended, contains customary cross default provisions.
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 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 June 30, 2021, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $400.0 million.
As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.
7.125% Senior Notes due 2026
In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting fees and other expenses. We used the net proceeds to redeem all of the previously issued 7.875% Senior Secured Notes due 2021, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the 7.125% Senior Notes.
The 7.125% Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 7.125% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility. We were in compliance with the financial covenants contained in the 7.125% Senior Notes as of June 30, 2021. The 7.125% Senior Notes contain customary cross default provisions.
7.500% Senior Notes due 2028
In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general corporate purposes.
The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.125% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico
assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and, on a subordinated basis, guarantee the Corporate Revolver and the 7.125% Senior Notes.
At any time prior to March 1, 2024, and subject to certain conditions, the Company may, on one or more occasions, redeem up to 40% of the original principal amount of the 7.500% Senior Notes with an amount not to exceed the net cash proceeds of certain equity offerings at a redemption price of 107.500% of the outstanding principal amount of the 7.500% Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption. Additionally, at any time prior to March 1, 2024 the Company may, on any one or more occasions, redeem all or a part of the 7.500% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole” premium. On or after March 1, 2024, the Company may redeem all or a part of the 7.500% Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Percentage
|
|
On or after March 1, 2024, but before February 28, 2025
|
|
103.750
|
%
|
|
On or after March 1, 2025, but before February 28, 2026
|
|
101.875
|
%
|
|
On or after March 1, 2026 and thereafter
|
|
100.000
|
%
|
We may also redeem the 7.500% Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the 7.500% Senior Notes at a price equal to the principal amount of the 7.500% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 7.500% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.
Upon the occurrence of a change of control triggering event as defined under the 7.500% Senior Notes indenture, the Company will be required to make an offer to repurchase the 7.500% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.
If we sell assets, under certain circumstances outlined in the 7.500% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 7.500% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 7.500% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred. We were in compliance with the financial covenants contained in the 7.500% Senior Notes as of June 30, 2021. The 7.500% Senior Notes contain customary cross default provisions.
Production Prepayment Agreement
In June 2020, the Company received $50.0 million from Trafigura under a Production Prepayment Agreement of crude oil sales related to a portion of our U.S. Gulf of Mexico production primarily in 2022 and 2023. The Company terminated the Production Prepayment Agreement and the initial prepayment of $50.0 million advanced under the Production Prepayment Agreement by Trafigura in the second quarter of 2020 was extinguished and converted into the GoM Term Loan as of September 30, 2020.
GoM Term Loan
In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. The GoM Term Loan bears interest at an effective rate of approximately 6% per annum and matures in 2025, with principal repayments beginning in the fourth quarter of 2021. We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of as of June 30, 2021 (the most recent assessment date). The GoM Term Loan contains customary cross default provisions.
Principal Debt Repayments
At June 30, 2021, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
|
Total
|
|
2021(2)
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
Thereafter
|
|
|
(In thousands)
|
|
Principal debt repayments(1)
|
$
|
2,300,000
|
|
|
$
|
7,500
|
|
|
$
|
30,000
|
|
|
$
|
30,000
|
|
|
$
|
200,455
|
|
|
$
|
402,692
|
|
|
$
|
1,629,353
|
|
__________________________________
(1)Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of the 7.125% Senior Notes, the $450.0 million aggregate principal amount of the 7.500% Senior Notes and borrowings under the Facility, Corporate Revolver and GoM Term Loan. The scheduled maturities of debt related to the Facility as of June 30, 2021 are based on 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 July 1, 2021 through December 31, 2021.
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
(In thousands)
|
|
Interest expense
|
$
|
35,740
|
|
|
$
|
28,504
|
|
|
$
|
67,175
|
|
|
$
|
60,270
|
|
|
Amortization—deferred financing costs
|
2,620
|
|
|
2,192
|
|
|
5,191
|
|
|
4,475
|
|
|
Loss on extinguishment of debt
|
15,223
|
|
|
2,215
|
|
|
15,223
|
|
|
2,215
|
|
|
Capitalized interest
|
(11,063)
|
|
|
(5,729)
|
|
|
(19,704)
|
|
|
(12,256)
|
|
|
Deferred interest
|
70
|
|
|
1,182
|
|
|
(124)
|
|
|
1,496
|
|
|
Interest income
|
(4,247)
|
|
|
(1,023)
|
|
|
(6,072)
|
|
|
(2,102)
|
|
|
Other, net
|
983
|
|
|
933
|
|
|
2,165
|
|
|
2,011
|
|
|
Interest and other financing costs, net
|
$
|
39,326
|
|
|
$
|
28,274
|
|
|
$
|
63,854
|
|
|
$
|
56,109
|
|
8. 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 Measurement.
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 June 30, 2021. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|
|
|
|
|
|
|
|
|
Net Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Premium
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payable/
|
|
|
|
Sold
|
|
|
|
|
|
|
Term
|
|
Type of Contract
|
|
Index
|
|
MBbl
|
|
(Receivable)
|
|
Swap
|
|
Put
|
|
Floor
|
|
Ceiling
|
|
|
2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jul — Dec
|
|
Swaps with sold puts
|
|
Dated Brent
|
|
3,000
|
|
|
$
|
—
|
|
|
$
|
53.96
|
|
|
$
|
42.92
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
Jul — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
1,500
|
|
|
0.45
|
|
|
—
|
|
|
32.50
|
|
|
40.00
|
|
|
53.47
|
|
|
|
Jul — Dec
|
|
Three-way collars
|
|
NYMEX WTI
|
|
500
|
|
|
1.00
|
|
|
—
|
|
|
37.50
|
|
|
45.00
|
|
|
55.00
|
|
|
|
Jul — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
3,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70.09
|
|
|
|
2022:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
1,500
|
|
|
1.05
|
|
|
—
|
|
|
40.00
|
|
|
50.00
|
|
|
70.00
|
|
|
|
Jan — Dec
|
|
Two-way collars
|
|
Dated Brent
|
|
3,000
|
|
|
1.26
|
|
|
—
|
|
|
—
|
|
|
55.00
|
|
|
76.67
|
|
|
|
Jan — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
1,581
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.00
|
|
|
__________________________________
(1)Represents call option contracts sold to counterparties to enhance other derivative positions
In July 2021, we entered into Dated Brent three-way collar contracts for 1.0 MMBbl from January 2022 through December 2022 with a sold put price of $45.00 per barrel, a floor price of $60.00 per barrel and a ceiling price of $80.00 per barrel.
The following tables disclose the Company’s derivative instruments as of June 30, 2021 and December 31, 2020, and gain/(loss) from derivatives during the three and six months ended June 30, 2021 and 2020, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
|
|
|
|
Asset (Liability)
|
|
Type of Contract
|
|
Balance Sheet Location
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
|
|
|
(In thousands)
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Derivative assets:
|
|
|
|
|
|
|
|
Commodity
|
|
Derivatives assets—current
|
|
$
|
—
|
|
|
$
|
15,414
|
|
|
Provisional oil sales
|
|
Receivables: Oil Sales
|
|
(287)
|
|
|
(677)
|
|
|
Commodity
|
|
Derivatives assets—long-term
|
|
—
|
|
|
964
|
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
Commodity
|
|
Derivatives liabilities—current
|
|
(127,255)
|
|
|
(28,009)
|
|
|
Commodity
|
|
Derivatives liabilities—long-term
|
|
(19,379)
|
|
|
(8,069)
|
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(146,921)
|
|
|
$
|
(20,377)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss)
|
|
Amount of Gain/(Loss)
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
Type of Contract
|
|
Location of Gain/(Loss)
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
|
|
|
(In thousands)
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Provisional oil sales
|
|
Oil and gas revenue
|
|
$
|
(5,080)
|
|
|
$
|
(4,632)
|
|
|
$
|
(8,777)
|
|
|
$
|
(4,348)
|
|
|
Commodity
|
|
Derivatives, net
|
|
(111,921)
|
|
|
(100,075)
|
|
|
(214,382)
|
|
|
35,963
|
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(117,001)
|
|
|
$
|
(104,707)
|
|
|
$
|
(223,159)
|
|
|
$
|
31,615
|
|
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 June 30, 2021 and December 31, 2020, 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.
9. Fair Value Measurements
In accordance with ASC 820 — Fair Value Measurement, 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 June 30, 2021 and December 31, 2020, 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)
|
|
June 30, 2021
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Provisional oil sales
|
—
|
|
|
(287)
|
|
|
—
|
|
|
(287)
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(146,634)
|
|
|
—
|
|
|
(146,634)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
—
|
|
|
$
|
(146,921)
|
|
|
$
|
—
|
|
|
$
|
(146,921)
|
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
16,378
|
|
|
$
|
—
|
|
|
$
|
16,378
|
|
|
Provisional oil sales
|
—
|
|
|
(677)
|
|
|
—
|
|
|
(677)
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(36,078)
|
|
|
—
|
|
|
(36,078)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
—
|
|
|
$
|
(20,377)
|
|
|
$
|
—
|
|
|
$
|
(20,377)
|
|
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 credit losses, 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 the 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 8 — 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.
Debt
The following table presents the carrying values and fair values at June 30, 2021 and December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
December 31, 2020
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
|
(In thousands)
|
|
7.125% Senior Notes
|
$
|
644,038
|
|
|
$
|
640,224
|
|
|
$
|
643,524
|
|
|
$
|
613,412
|
|
|
7.500% Senior Notes
|
444,575
|
|
|
445,770
|
|
|
—
|
|
|
—
|
|
|
GoM Term Loan
|
200,000
|
|
|
200,000
|
|
|
200,000
|
|
|
200,000
|
|
|
Corporate Revolver
|
—
|
|
|
—
|
|
|
100,000
|
|
|
100,000
|
|
|
Facility
|
1,000,000
|
|
|
1,000,000
|
|
|
1,200,000
|
|
|
1,200,000
|
|
|
Total
|
$
|
2,288,613
|
|
|
$
|
2,285,994
|
|
|
$
|
2,143,524
|
|
|
$
|
2,113,412
|
|
The carrying values of our 7.125% Senior Notes and 7.500% Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying values of the GoM Term Loan, Corporate Revolver and Facility approximate fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.
Nonrecurring Fair Value Measurements - Long-lived assets
Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
The Company calculates the estimated fair values of its long-lived assets using the income approach described in the ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices, production, and risk adjustment factors.
As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we reviewed our long-lived assets for impairment at March 31, 2020, which resulted in impairment charges of $150.8 million, reducing the carrying value of the properties to their estimated fair values of $243.7 million. During the fourth quarter of 2020 the Company recorded additional impairment charges totaling approximately $3.2 million resulting in impairment charges totaling $154.0 million for the year ended December 31, 2020. During the three and six months ended June 30, 2021, the Company did not recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience further declines in oil pricing expectations, increases in our estimated future expenditures or a decrease in our estimated production profile, our long-lived assets could be at risk of additional impairment.
10. Equity-based Compensation
Restricted Stock Units
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $7.6 million and $8.3 million during the three months ended June 30, 2021 and 2020, respectively, and $15.9 million and $17.7 million during the six months ended June 30, 2021 and 2020, respectively. The total tax benefit for the three months ended June 30, 2021 and 2020 was $1.5 million and $1.7 million, respectively, and $2.9 million and $3.8 million during the six months ended June 30, 2021 and 2020, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of nil and $0.2 million for the three months ended June 30, 2021 and 2020, respectively, and $4.8 million and $1.1 million during the six months ended June 30, 2021 and 2020, respectively. The fair value of awards vested during the three months ended June 30, 2021 and 2020 was $1.8 million and $0.4 million, respectively, and $8.4 million and $25.8 million during the six months ended June 30, 2021 and 2020, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all of these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.
The following table reflects the outstanding restricted stock units as of June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2020
|
4,840
|
|
|
$
|
5.34
|
|
|
7,859
|
|
|
$
|
8.11
|
|
|
Granted(1)
|
2,794
|
|
|
2.54
|
|
|
6,703
|
|
|
3.91
|
|
|
Forfeited(1)
|
(401)
|
|
|
4.23
|
|
|
(1,869)
|
|
|
9.14
|
|
|
Vested
|
(2,320)
|
|
|
5.13
|
|
|
(1,065)
|
|
|
5.53
|
|
|
Outstanding at June 30, 2021
|
4,913
|
|
|
3.93
|
|
|
11,628
|
|
|
5.49
|
|
__________________________________
(1)The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.
As of June 30, 2021, total equity-based compensation to be recognized on unvested restricted stock units is $36.0 million over a weighted average period of 1.85 years. In April 2021, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan, which was approved by our stockholders at the Annual Stockholders Meeting in June 2021. At June 30, 2021, the Company had approximately 10.7 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 $1.06 to $9.52 per award. The Monte Carlo simulation model utilized multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculated 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 50.0% to 52.0%. 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 0.2% to 2.5%. For the restricted stock units awarded in 2019 and 2020, the Monte Carlo simulation model included estimated quarterly dividend inputs ranging from $0.000 to $0.050.
11. Income Taxes
We evaluate our estimated annual effective income tax rate each quarter, based on current and forecasted business results and enacted tax laws, 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.
Income (loss) before income taxes is composed of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
(In thousands)
|
|
United States
|
$
|
(16,798)
|
|
|
$
|
(79,703)
|
|
|
$
|
(38,640)
|
|
|
$
|
(269,840)
|
|
|
Foreign
|
(46,922)
|
|
|
(167,113)
|
|
|
(132,553)
|
|
|
(94,200)
|
|
|
Income (loss) before income taxes
|
$
|
(63,720)
|
|
|
$
|
(246,816)
|
|
|
$
|
(171,193)
|
|
|
$
|
(364,040)
|
|
For the three months ended June 30, 2021 and 2020, our effective tax rate was 10% and 19%, respectively. For the six months ended, June 30, 2021 and 2020, our effective tax rate was 14% and 5%, respectively. For the three and six months ended June 30, 2021 and 2020, our overall effective tax rates were impacted by:
•The difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations,
•Jurisdictions that have a 0% statutory rate or where we have incurred losses and have recorded valuation allowances against the corresponding net deferred tax assets, and
•Other non-deductible expenses primarily in the U.S.
Additionally, for the three and six months ended, June 30, 2020, our overall effective tax rate was impacted by:
•$30.9 million deferred tax expense related valuation allowances on U.S. deferred tax assets recognized in prior periods, and
•$4.9 million tax benefit associated with a 2018 U.S. tax loss carry back, pursuant to the Coronavirus Aid, Relief, and Economic Security ACT (“CARES ACT”), to an earlier tax year with a higher statutory tax rate.
12. 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
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
(In thousands, except per share data)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
Net loss allocable to common stockholders
|
$
|
(57,187)
|
|
|
$
|
(199,391)
|
|
|
$
|
(147,955)
|
|
|
$
|
(382,158)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
408,131
|
|
|
405,195
|
|
|
409,828
|
|
|
404,990
|
|
|
Restricted stock awards and units(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Diluted
|
408,131
|
|
|
405,195
|
|
|
409,828
|
|
|
404,990
|
|
|
Net loss per share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.14)
|
|
|
$
|
(0.49)
|
|
|
$
|
(0.36)
|
|
|
$
|
(0.94)
|
|
|
Diluted
|
$
|
(0.14)
|
|
|
$
|
(0.49)
|
|
|
$
|
(0.36)
|
|
|
$
|
(0.94)
|
|
__________________________________
(1)We excluded outstanding restricted stock units of 15.7 million and 11.6 million for the three months ended June 30, 2021 and 2020, respectively, and 14.7 million and 11.3 million for the six months ended June 30, 2021 and 2020, respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive.
13. Commitments and Contingencies
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
We currently have a commitment to drill two exploration wells in Mauritania.
Performance Obligations
As of June 30, 2021 and December 31, 2020, the Company had performance bonds totaling $229.3 million and $195.5 million, respectively, for our supplemental bonding requirements stipulated by the BOEM and $3.5 million and $7.1 million, respectively, to third parties related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in our U.S. Gulf of Mexico fields. As of June 30, 2021 and December 31, 2020, we had zero cash collateral against these secured performance bonds.
Dividends
On March 26, 2020, the quarterly cash dividend of $0.0452 per common share was paid to stockholders of record as of March 5, 2020. In March 2020, in response to economic conditions, including oil price volatility and the impact of the COVID-19 pandemic, the Board of Directors decided to suspend the dividend.
14. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
December 31,
2020
|
|
|
(In thousands)
|
|
Accrued liabilities:
|
|
|
|
|
Exploration, development and production
|
$
|
49,722
|
|
|
$
|
89,162
|
|
|
Revenue payable
|
26,716
|
|
|
15,079
|
|
|
Current asset retirement obligations
|
7,197
|
|
|
7,255
|
|
|
General and administrative expenses
|
18,037
|
|
|
4,988
|
|
|
Interest
|
25,460
|
|
|
23,725
|
|
|
Income taxes
|
61,453
|
|
|
37,344
|
|
|
Taxes other than income
|
3,529
|
|
|
2,815
|
|
|
Derivatives
|
25,818
|
|
|
17,475
|
|
|
Other
|
5,014
|
|
|
5,417
|
|
|
|
$
|
222,946
|
|
|
$
|
203,260
|
|
Asset Retirement Obligations
The following table summarizes the changes in the Company's asset retirement obligations as of and during the six months ended June 30, 2021:
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
|
(In thousands)
|
|
Asset retirement obligations:
|
|
|
Beginning asset retirement obligations
|
$
|
251,421
|
|
|
Liabilities incurred during period
|
3,255
|
|
|
Liabilities settled during period
|
(616)
|
|
|
Revisions in estimated retirement obligations
|
388
|
|
|
Accretion expense
|
9,913
|
|
|
Ending asset retirement obligations
|
$
|
264,361
|
|
Other Expenses, Net
Other expenses, net incurred during the period is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2021
|
|
2020
|
|
2021
|
|
2020
|
|
|
(In thousands)
|
|
Loss on disposal of inventory
|
$
|
215
|
|
|
$
|
361
|
|
|
$
|
582
|
|
|
$
|
1,828
|
|
|
(Gain) loss on asset retirement obligations liability settlements
|
357
|
|
|
(28)
|
|
|
386
|
|
|
2,122
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring charges
|
18
|
|
|
(575)
|
|
|
837
|
|
|
13,340
|
|
|
Other, net
|
(3,249)
|
|
|
1,470
|
|
|
(996)
|
|
|
7,867
|
|
|
Other expenses, net
|
$
|
(2,659)
|
|
|
$
|
1,228
|
|
|
$
|
809
|
|
|
$
|
25,157
|
|
The restructuring charges are for employee severance and related benefit costs incurred as part of a corporate reorganization.
15. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At June 30, 2021, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ghana
|
|
Equatorial Guinea
|
|
Mauritania/Senegal
|
|
U.S. Gulf of Mexico
|
|
Corporate & Other
|
|
Eliminations
|
|
Total
|
|
|
(In thousands)
|
|
Three months ended June 30, 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
191,826
|
|
|
$
|
84,329
|
|
|
$
|
—
|
|
|
$
|
107,890
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
384,045
|
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other income, net
|
1
|
|
|
—
|
|
|
—
|
|
|
443
|
|
|
144,426
|
|
|
(144,796)
|
|
|
74
|
|
|
Total revenues and other income
|
191,827
|
|
|
84,329
|
|
|
—
|
|
|
108,333
|
|
|
144,426
|
|
|
(144,796)
|
|
|
384,119
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
57,313
|
|
|
31,715
|
|
|
—
|
|
|
26,775
|
|
|
—
|
|
|
—
|
|
|
115,803
|
|
|
Facilities insurance modifications, net
|
1,269
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1,270
|
|
|
Exploration expenses
|
43
|
|
|
684
|
|
|
1,557
|
|
|
5,418
|
|
|
1,587
|
|
|
—
|
|
|
9,289
|
|
|
General and administrative
|
2,884
|
|
|
1,251
|
|
|
2,724
|
|
|
3,204
|
|
|
44,539
|
|
|
(32,874)
|
|
|
21,728
|
|
|
Depletion, depreciation and amortization
|
87,639
|
|
|
19,284
|
|
|
16
|
|
|
43,796
|
|
|
426
|
|
|
—
|
|
|
151,161
|
|
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Interest and other financing costs, net(1)
|
8,138
|
|
|
(403)
|
|
|
(12,396)
|
|
|
4,295
|
|
|
39,692
|
|
|
—
|
|
|
39,326
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111,921
|
|
|
—
|
|
|
111,921
|
|
|
Other expenses, net
|
87,867
|
|
|
13,798
|
|
|
(3,026)
|
|
|
11,048
|
|
|
(425)
|
|
|
(111,921)
|
|
|
(2,659)
|
|
|
Total costs and expenses
|
245,153
|
|
|
66,329
|
|
|
(11,125)
|
|
|
94,536
|
|
|
197,741
|
|
|
(144,795)
|
|
|
447,839
|
|
|
Loss before income taxes
|
(53,326)
|
|
|
18,000
|
|
|
11,125
|
|
|
13,797
|
|
|
(53,315)
|
|
|
(1)
|
|
|
(63,720)
|
|
|
Income tax expense (benefit)
|
(18,120)
|
|
|
11,565
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
(6,533)
|
|
|
Net loss
|
$
|
(35,206)
|
|
|
$
|
6,435
|
|
|
$
|
11,125
|
|
|
$
|
13,797
|
|
|
$
|
(53,337)
|
|
|
$
|
(1)
|
|
|
$
|
(57,187)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
26,011
|
|
|
$
|
19,669
|
|
|
$
|
82,672
|
|
|
$
|
20,219
|
|
|
$
|
327
|
|
|
$
|
1,917
|
|
|
$
|
150,815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ghana
|
|
Equatorial Guinea
|
|
Mauritania/Senegal
|
|
U.S. Gulf of Mexico
|
|
Corporate & Other
|
|
Eliminations
|
|
Total
|
|
|
(In thousands)
|
|
Six months ended June 30, 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
245,879
|
|
|
$
|
112,361
|
|
|
$
|
—
|
|
|
$
|
202,279
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
560,519
|
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|
26
|
|
|
Other income, net
|
1
|
|
|
—
|
|
|
—
|
|
|
772
|
|
|
281,925
|
|
|
(282,554)
|
|
|
144
|
|
|
Total revenues and other income
|
245,880
|
|
|
112,361
|
|
|
—
|
|
|
203,051
|
|
|
281,951
|
|
|
(282,554)
|
|
|
560,689
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
69,699
|
|
|
43,344
|
|
|
—
|
|
|
48,512
|
|
|
—
|
|
|
—
|
|
|
161,555
|
|
|
Facilities insurance modifications, net
|
1,940
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1,941
|
|
|
Exploration expenses
|
75
|
|
|
2,577
|
|
|
3,731
|
|
|
6,566
|
|
|
4,521
|
|
|
—
|
|
|
17,470
|
|
|
General and administrative
|
5,471
|
|
|
2,302
|
|
|
4,697
|
|
|
8,443
|
|
|
89,644
|
|
|
(66,388)
|
|
|
44,169
|
|
|
Depletion, depreciation and amortization
|
111,274
|
|
|
28,475
|
|
|
31
|
|
|
87,047
|
|
|
875
|
|
|
—
|
|
|
227,702
|
|
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Interest and other financing costs, net(1)
|
20,054
|
|
|
(772)
|
|
|
(22,212)
|
|
|
8,861
|
|
|
59,707
|
|
|
(1,784)
|
|
|
63,854
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
214,382
|
|
|
—
|
|
|
214,382
|
|
|
Other expenses, net
|
158,988
|
|
|
30,867
|
|
|
(2,242)
|
|
|
25,537
|
|
|
2,041
|
|
|
(214,382)
|
|
|
809
|
|
|
Total costs and expenses
|
367,501
|
|
|
106,793
|
|
|
(15,995)
|
|
|
184,966
|
|
|
371,171
|
|
|
(282,554)
|
|
|
731,882
|
|
|
Loss before income taxes
|
(121,621)
|
|
|
5,568
|
|
|
15,995
|
|
|
18,085
|
|
|
(89,220)
|
|
|
—
|
|
|
(171,193)
|
|
|
Income tax expense (benefit)
|
(41,988)
|
|
|
14,199
|
|
|
—
|
|
|
—
|
|
|
4,551
|
|
|
—
|
|
|
(23,238)
|
|
|
Net loss
|
$
|
(79,633)
|
|
|
$
|
(8,631)
|
|
|
$
|
15,995
|
|
|
$
|
18,085
|
|
|
$
|
(93,771)
|
|
|
$
|
—
|
|
|
$
|
(147,955)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
30,635
|
|
|
$
|
31,093
|
|
|
$
|
155,424
|
|
|
$
|
44,486
|
|
|
$
|
5,726
|
|
|
$
|
—
|
|
|
$
|
267,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
$
|
1,214,334
|
|
|
$
|
432,087
|
|
|
$
|
751,237
|
|
|
$
|
955,805
|
|
|
$
|
21,180
|
|
|
$
|
—
|
|
|
$
|
3,374,643
|
|
|
Total assets
|
$
|
1,290,106
|
|
|
$
|
797,425
|
|
|
$
|
1,105,754
|
|
|
$
|
3,198,153
|
|
|
$
|
13,985,966
|
|
|
$
|
(16,374,132)
|
|
|
$
|
4,003,272
|
|
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ghana
|
|
Equatorial Guinea
|
|
Mauritania/Senegal
|
|
U.S. Gulf of Mexico
|
|
Corporate & Other
|
|
Eliminations
|
|
Total
|
|
|
(In thousands)
|
|
Three months ended June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
61,192
|
|
|
$
|
26,901
|
|
|
$
|
—
|
|
|
$
|
39,221
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
127,314
|
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other income, net
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
121,264
|
|
|
(121,268)
|
|
|
—
|
|
|
Total revenues and other income
|
61,192
|
|
|
26,901
|
|
|
—
|
|
|
39,225
|
|
|
121,264
|
|
|
(121,268)
|
|
|
127,314
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
46,568
|
|
|
25,414
|
|
|
—
|
|
|
16,765
|
|
|
—
|
|
|
—
|
|
|
88,747
|
|
|
Facilities insurance modifications, net
|
52
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
Exploration expenses
|
13
|
|
|
2,117
|
|
|
985
|
|
|
6,594
|
|
|
6,002
|
|
|
—
|
|
|
15,711
|
|
|
General and administrative
|
3,132
|
|
|
1,222
|
|
|
2,176
|
|
|
2,849
|
|
|
28,217
|
|
|
(19,410)
|
|
|
18,186
|
|
|
Depletion, depreciation and amortization
|
64,917
|
|
|
19,409
|
|
|
16
|
|
|
36,880
|
|
|
635
|
|
|
—
|
|
|
121,857
|
|
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Interest and other financing costs, net(1)
|
13,322
|
|
|
(331)
|
|
|
(6,222)
|
|
|
2,991
|
|
|
20,297
|
|
|
(1,783)
|
|
|
28,274
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100,075
|
|
|
—
|
|
|
100,075
|
|
|
Other expenses, net
|
54,048
|
|
|
6,379
|
|
|
(322)
|
|
|
40,093
|
|
|
1,105
|
|
|
(100,075)
|
|
|
1,228
|
|
|
Total costs and expenses
|
182,052
|
|
|
54,210
|
|
|
(3,367)
|
|
|
106,172
|
|
|
156,331
|
|
|
(121,268)
|
|
|
374,130
|
|
|
Income (loss) before income taxes
|
(120,860)
|
|
|
(27,309)
|
|
|
3,367
|
|
|
(66,947)
|
|
|
(35,067)
|
|
|
—
|
|
|
(246,816)
|
|
|
Income tax expense (benefit)
|
(44,051)
|
|
|
(13,258)
|
|
|
—
|
|
|
(1)
|
|
|
9,885
|
|
|
—
|
|
|
(47,425)
|
|
|
Net income (loss)
|
$
|
(76,809)
|
|
|
$
|
(14,051)
|
|
|
$
|
3,367
|
|
|
$
|
(66,946)
|
|
|
$
|
(44,952)
|
|
|
$
|
—
|
|
|
$
|
(199,391)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
8,590
|
|
|
$
|
9,335
|
|
|
$
|
2,202
|
|
|
$
|
39,897
|
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
66,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ghana
|
|
Equatorial Guinea
|
|
Mauritania/Senegal
|
|
U.S. Gulf of Mexico
|
|
Corporate & Other
|
|
Eliminations
|
|
Total
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
110,900
|
|
|
$
|
51,520
|
|
|
$
|
—
|
|
|
$
|
142,674
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
305,094
|
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other income, net
|
1
|
|
|
—
|
|
|
—
|
|
|
451
|
|
|
9,255
|
|
|
(9,706)
|
|
|
1
|
|
|
Total revenues and other income
|
110,901
|
|
|
51,520
|
|
|
—
|
|
|
143,125
|
|
|
9,255
|
|
|
(9,706)
|
|
|
305,095
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
64,610
|
|
|
36,889
|
|
|
—
|
|
|
48,851
|
|
|
—
|
|
|
—
|
|
|
150,350
|
|
|
Facilities insurance modifications, net
|
8,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,090
|
|
|
Exploration expenses
|
98
|
|
|
4,836
|
|
|
4,459
|
|
|
20,561
|
|
|
30,362
|
|
|
—
|
|
|
60,316
|
|
|
General and administrative
|
7,022
|
|
|
2,960
|
|
|
4,285
|
|
|
6,853
|
|
|
60,079
|
|
|
(42,102)
|
|
|
39,097
|
|
|
Depletion, depreciation and amortization
|
84,648
|
|
|
28,303
|
|
|
31
|
|
|
100,714
|
|
|
1,463
|
|
|
—
|
|
|
215,159
|
|
|
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
—
|
|
|
150,820
|
|
|
—
|
|
|
—
|
|
|
150,820
|
|
|
Interest and other financing costs, net(1)
|
28,153
|
|
|
(700)
|
|
|
(12,848)
|
|
|
7,680
|
|
|
37,391
|
|
|
(3,567)
|
|
|
56,109
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(35,963)
|
|
|
—
|
|
|
(35,963)
|
|
|
Other expenses, net
|
(62,324)
|
|
|
(9,377)
|
|
|
2,471
|
|
|
43,745
|
|
|
14,679
|
|
|
35,963
|
|
|
25,157
|
|
|
Total costs and expenses
|
130,297
|
|
|
62,911
|
|
|
(1,602)
|
|
|
379,224
|
|
|
108,011
|
|
|
(9,706)
|
|
|
669,135
|
|
|
Income (loss) before income taxes
|
(19,396)
|
|
|
(11,391)
|
|
|
1,602
|
|
|
(236,099)
|
|
|
(98,756)
|
|
|
—
|
|
|
(364,040)
|
|
|
Income tax expense (benefit)
|
(5,830)
|
|
|
(8,670)
|
|
|
—
|
|
|
30,902
|
|
|
1,716
|
|
|
—
|
|
|
18,118
|
|
|
Net income (loss)
|
$
|
(13,566)
|
|
|
$
|
(2,721)
|
|
|
$
|
1,602
|
|
|
$
|
(267,001)
|
|
|
$
|
(100,472)
|
|
|
$
|
—
|
|
|
$
|
(382,158)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
25,076
|
|
|
$
|
16,106
|
|
|
$
|
5,323
|
|
|
$
|
78,551
|
|
|
$
|
25,795
|
|
|
$
|
—
|
|
|
$
|
150,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
$
|
1,429,160
|
|
|
$
|
453,178
|
|
|
$
|
451,140
|
|
|
$
|
1,018,586
|
|
|
$
|
26,601
|
|
|
$
|
—
|
|
|
$
|
3,378,665
|
|
|
Total assets
|
$
|
1,567,529
|
|
|
$
|
692,283
|
|
|
$
|
650,351
|
|
|
$
|
3,067,724
|
|
|
$
|
12,404,285
|
|
|
$
|
(14,395,681)
|
|
|
$
|
3,986,491
|
|
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
|
2021
|
|
2020
|
|
|
|
(In thousands)
|
|
|
Consolidated capital expenditures:
|
|
|
|
|
|
Consolidated Statements of Cash Flows - Investing activities:
|
|
|
|
|
|
Oil and gas assets
|
$
|
290,399
|
|
|
$
|
135,242
|
|
|
|
Other property
|
140
|
|
|
1,536
|
|
|
|
Adjustments:
|
|
|
|
|
|
Changes in capital accruals
|
(15,830)
|
|
|
(20,392)
|
|
|
|
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)
|
12,605
|
|
|
39,461
|
|
|
|
Capitalized interest
|
(19,704)
|
|
|
(12,256)
|
|
|
|
Proceeds on sale of assets
|
(858)
|
|
|
—
|
|
|
|
Other
|
612
|
|
|
7,260
|
|
|
|
Total consolidated capital expenditures
|
$
|
267,364
|
|
|
$
|
150,851
|
|
|
______________________________________
(1)Unsuccessful well costs are included in oil and gas assets when incurred.
16. Subsequent Events
In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO (which is currently under construction by Technip Energies in China) to an affiliate of BP (“BP Buyer”). The FPSO will be leased back to BP Operator under a long-term lease agreement, for exclusive use in the Greater Tortue project.
BP Operator will continue to manage and supervise the construction contract with Technip Energies. Delivery of the FPSO to BP Buyer will occur after construction is complete and the FPSO has entered international waters, with the lease to BP Operator becoming effective on the same date, currently estimated to be late third quarter of 2022.
In July 2021, the Company commenced drilling the Zora infrastructure-led exploration prospect located in DeSoto Canyon Block 266 (37.5% working interest). The well did not find hydrocarbons and is currently being plugged and abandoned. The well results will be integrated into the ongoing evaluation of the surrounding area. The Company expects to record approximately $11.0 million of exploration expenses in the third quarter related to the well.