Notes to Consolidated Financial Statements
(Unaudited)
1. Organization
Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware (the "Redomestication") in December 2018. As part of the Redomestication, we 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 exploration program balanced between proven basin infrastructure-led 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.
Kosmos is engaged in a single line of business, 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 operations in
four
geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico. In addition we have exploration activities in other countries in the Atlantic Margins.
2. 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
March 31, 2019
, the changes in the consolidated statements of stockholders’ equity for the
three
months ended
March 31, 2019
, the consolidated results of operations for the
three
months ended
March 31, 2019
and
2018
, and the consolidated cash flows for the
three
months ended
March 31, 2019
and
2018
. 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, 2018
, 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, stockholders’ equity or cash flows. Additionally, as a result of our outstanding shares in KTIPI being transferred for an undivided interest in the Ceiba Field and Okume Complex (effective January 1, 2019), our previously reported equity method investment in KTIPI has been allocated to the respective assets and liabilities on a relative fair value basis. See Note 7 — Equity Method Investments for additional information.
Cash, Cash Equivalents and Restricted Cash
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March 31,
2019
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|
December 31,
2018
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
$
|
134,423
|
|
|
$
|
173,515
|
|
|
Restricted cash - current
|
537
|
|
|
4,527
|
|
|
Restricted cash - long-term
|
7,574
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|
|
7,574
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|
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Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows
|
$
|
142,534
|
|
|
$
|
185,616
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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
Inventories consisted of
$78.1 million
and
$83.4 million
of materials and supplies and
$9.2 million
and
$1.4 million
of hydrocarbons as of
March 31, 2019
and
December 31, 2018
, 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.
Leases (Policy applicable beginning January 1, 2019)
We account for leases in accordance with ASC Topic 842, Leases, (“ASC 842”). We determine if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset (i.e., property, plant, and equipment), and (2) the customer has the right to control the use of the identified asset.
In the normal course of business, the Company enters into various lease agreements for real estate and equipment related to its exploration, development and production activities that are currently accounted for as operating leases. Operating Leases are included in Other assets and Accrued liabilities and Other long-term liabilities on our Consolidated Balance Sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date.
Key estimates and judgments include how we determined (1) the discount rate we use to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments.
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1.
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ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of our leases where we are the lessee do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Our incremental borrowing rate for a lease is the rate of interest we would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms.
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2.
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The lease term for all of our leases includes the noncancellable period of the lease plus any additional periods covered by either an option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor.
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3.
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Lease payments included in the measurement of the lease asset or liability comprise the following: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if we are reasonably certain to exercise. Amounts expected to be payable under residual value guarantee are also lease payments included in the measurement of the lease liability.
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The Right-of-use ("ROU") asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received.
For operating leases, the ROU asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term.
We monitor for events or changes in circumstances that require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding ROU asset unless doing so would reduce the carrying amount of the ROU asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative ROU asset balance is recorded in profit or loss.
We have lease agreements which include lease and nonlease components. We have elected to combine lease and nonlease components for all lease contracts.
We have elected not to recognize ROU assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. We recognize the lease payments associated with our short-term leases as an expense on a straight-line basis over the lease term.
We adopted ASU 2016-02 using a modified retrospective transition approach as of the effective date as permitted by the amendments in ASU 2018-11, which provides an alternative modified retrospective transition method. As a result, we were not required to adjust our comparative period financial information for effects of the standard or make the new required lease disclosures for periods before the date of adoption (i.e. January 1, 2019). We have elected to adopt the package of transition practical expedients and, therefore, have not reassessed (1) whether existing or expired contracts contain a lease, (2) lease classification for existing or expired leases or (3) the accounting for initial direct costs that were previously capitalized. We did not elect the practical expedient to use hindsight for leases existing at the adoption date. Further, we do not expect the amendments in ASU 2018-01: Land Easement Practical Expedient to have an effect on us because we do not enter into land easement arrangements.
Revenue Recognition
We recognize revenues on the volumes sold to a purchaser. 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
March 31, 2019
and
December 31, 2018
, 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:
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Three Months Ended March 31,
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|
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2019
|
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2018
|
|
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(In thousands)
|
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Revenues from contract with customers - Equatorial Guinea
|
$
|
89,115
|
|
|
$
|
—
|
|
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Revenues from contracts with customers - Ghana
|
119,330
|
|
|
128,037
|
|
|
Revenues from contracts with customers - U.S. Gulf of Mexico
|
85,067
|
|
|
—
|
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Provisional oil sales contracts
|
3,278
|
|
|
(841
|
)
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Oil and gas revenue
|
$
|
296,790
|
|
|
$
|
127,196
|
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Concentration of Credit Risk
Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of international operations. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines. For the
three months ended
March 31, 2019
, revenue from Phillips 66 Company made up approximately
22%
of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.
Recent Accounting Standards
Recently 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. In July 2018, the FASB issued ASU 2018-11, which added a transition option permitting entities to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the consolidated financial statements. Under this transition option, comparative reporting would not be required, and the provisions of the standard would be applied prospectively to leases in effect at the date of adoption. The Company adopted the guidance prospectively during the first quarter of 2019. As part of our adoption, we elected not to reassess historical lease classification, recognize short-term leases on our balance sheet, nor separate lease and non-lease components for our real estate leases. The adoption and implementation of this ASU resulted in a
$21.7 million
increase in assets and liabilities related to our leasing activities which primarily consists of office leases. Our adoption of ASU 2016-02 did not impact retained earnings or other components of equity as of December 31, 2018.
3. Acquisitions and Divestitures
2019 Transactions
During the first quarter of 2019, we entered into a petroleum contract covering Marine XXI block with the Republic of the Congo, subject to customary governmental approvals. Upon approval, we will hold an
85%
participating interest and are the operator. The Congolese national oil company, SPNC, has a
15%
carried participating interest during the exploration period. Should a commercial discovery be made, SNPC's
15%
carried interest will convert to a participating interest of at least
15%
. The petroleum contract covers approximately
2,350
square kilometers, with a first exploration period of
four
years and include a work program to acquire and interpret
2,200
square kilometers of 3D seismic. There are
two
optional exploration phases, each for a period of
three
years, which are subject to additional work program commitments.
During the first quarter of 2019, Kosmos farmed-in to
18
BP-owned blocks in the Garden Banks area of the deepwater U.S. Gulf of Mexico. In addition, Kosmos can earn an interest in
three
BP blocks in other areas of the deepwater U.S. Gulf of Mexico. This should allow Kosmos to execute projects that can be tied back to existing infrastructure. Kosmos is the designated operator and plans to commence drilling operations on the first well in Garden Banks block 492, the Resolution prospect, in 2019.
During the first quarter of 2019, Kosmos executed a farm-in agreement with Chevron covering the right to earn an interest in a strategic block in the deepwater U.S. Gulf of Mexico. This agreement allows Kosmos another opportunity to execute its deepwater U.S. Gulf of Mexico strategy of lower risk prospects with the potential for subsea development near existing infrastructure. Kosmos will be designated operator and plans to commence drilling operations in 2019.
During the first quarter of 2019, Kosmos was one of the most active participants in the U.S. Gulf of Mexico Lease Sale 252 in which we were the apparent high bidder on
nine
blocks.
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 and BP. We have a
35%
participating interest in the blocks and the operator, BP, holds a
50%
participating interest. The national petroleum agency, 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 across the
two
blocks.
In June 2018, we completed a farm-in agreement with a subsidiary of 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 agreed to 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 which was completed in November 2018. In March 2019, we acquired Ophir's remaining interest in the block, which resulted in Kosmos owning an
80%
interest in Block EG-24.
The Equatorial Guinean national oil company, 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.
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, offshore Equatorial Guinea, 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, 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, which was completed in 2018.
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.
The DGE acquisition was accounted for under the asset acquisition method and there were no changes from the purchase price allocation disclosed in the Company's Annual Report on Form 10-K for the year ended December 31, 2018.
In October 2018, Kosmos entered into a strategic exploration alliance with 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, and Sao Tome and Principe where we have entered into exclusive negotiations for Shell to take an interest in a portion of Kosmos’ acreage. As part of the alliance, the
two
companies intend to jointly evaluate opportunities in adjacent geographies. This alliance is consistent with Kosmos’ strategy of partnering with supermajors to leverage complementary skill sets. Shell has deep expertise in carbonate plays, while Kosmos brings significant knowledge of the Cretaceous in West Africa. Furthermore, by working with Shell, Kosmos has a partner with the expertise to efficiently move exploration successes through the development stage.
4. 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, 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
March 31, 2019
and
December 31, 2018
, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were
$14.0 million
and
$14.0 million
, respectively, and the long-term portions were
$15.2 million
and
$14.0 million
, respectively.
The Company's related party receivables consists primarily of receivables from Trident which, until January 2019, we shared a
50%
interest in KTIPI. As of December 31, 2018 the balance due from Trident consists of $
5.6 million
related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations. Subsequent to the unwind of KTIPI, Trident is no longer considered a related party.
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
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March 31,
2019
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|
December 31,
2018
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(In thousands)
|
|
Oil and gas properties:
|
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|
|
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Proved properties
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$
|
3,177,330
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|
|
$
|
2,773,276
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Unproved properties
|
857,009
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|
759,472
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Support equipment and facilities
|
1,528,308
|
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|
1,463,213
|
|
|
Total oil and gas properties
|
5,562,647
|
|
|
4,995,961
|
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Accumulated depletion
|
(1,662,063
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)
|
|
(1,551,097
|
)
|
|
Oil and gas properties, net
|
3,900,584
|
|
|
3,444,864
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|
|
|
|
|
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Other property
|
52,815
|
|
|
51,987
|
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|
Accumulated depreciation
|
(38,596
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)
|
|
(37,150
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)
|
|
Other property, net
|
14,219
|
|
|
14,837
|
|
|
|
|
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Property and equipment, net
|
$
|
3,914,803
|
|
|
$
|
3,459,701
|
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We recorded depletion expense of
$111.0 million
and
$51.6 million
for the
three months ended
March 31, 2019
and
2018
, respectively. The increase to oil and gas properties primarily relates to proportionate consolidation resulting from the unwind of our equity method investment in Equatorial Guinea. See Note 7 — Equity Method Investments for additional information.
6. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the
three
months ended
March 31, 2019
. The table excludes
nil
costs that were capitalized and subsequently expensed during the same period.
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|
March 31,
2019
|
|
|
(In thousands)
|
|
Beginning balance
|
$
|
367,665
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|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
2,410
|
|
|
Reclassification due to determination of proved reserves
|
—
|
|
|
Capitalized exploratory well costs charged to expense
|
—
|
|
|
Ending balance
|
$
|
370,075
|
|
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:
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|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
|
(In thousands, except well counts)
|
|
Exploratory well costs capitalized for a period of one year or less
|
$
|
—
|
|
|
$
|
—
|
|
|
Exploratory well costs capitalized for a period of one to two years
|
127,532
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|
|
299,253
|
|
|
Exploratory well costs capitalized for a period of three years
|
242,543
|
|
|
68,412
|
|
|
Ending balance
|
$
|
370,075
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|
|
$
|
367,665
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Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
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3
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|
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3
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As of
March 31, 2019
, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Greater Tortue Ahmeyim Unit, 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.
Greater Tortue Ahmeyim Unit — 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 Ahmeyim Unit. Data acquired from the drill stem test was used to further optimize field development and to refine process design parameters critical to the FEED process. In December 2018, we made a final investment decision to develop Phase 1 of the Greater Tortue Ahmeyim Unit.
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. An exploration well is planned for the nearby Orca prospect during 2019, which will help delineate the available resource in the region to refine the development plans for the BirAllah discovery.
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.
7. Equity Method Investments
Equatorial Guinea
As part of our acquisition of KTIPI, a corporate joint venture entity in which we owned 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.
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|
|
|
|
|
|
December 31,
|
|
|
2018
|
|
|
(In thousands)
|
|
Assets
|
|
|
|
Total current assets
|
$
|
149,950
|
|
|
Property and equipment, net
|
271,627
|
|
|
Other assets
|
21
|
|
|
Total assets
|
$
|
421,598
|
|
|
|
|
|
Liabilities and stockholders' equity
|
|
|
Total current liabilities
|
$
|
226,311
|
|
|
Total long-term liabilities
|
536,178
|
|
|
Shareholders' equity:
|
|
|
Total shareholders' equity
|
(340,891
|
)
|
|
Total liabilities and shareholders' equity
|
$
|
421,598
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2018
|
|
|
(In thousands)
|
|
Revenues and other income:
|
|
|
Oil and gas revenue
|
$
|
246,354
|
|
|
Other income
|
287
|
|
|
Total revenues and other income
|
246,641
|
|
|
|
|
|
Costs and expenses:
|
|
|
Oil and gas production
|
51,700
|
|
|
Depletion, depreciation and amortization
|
54,070
|
|
|
Other expenses, net
|
(79
|
)
|
|
Total costs and expenses
|
105,691
|
|
|
|
|
|
Income before income taxes
|
140,950
|
|
|
Income tax expense
|
49,632
|
|
|
Net income
|
$
|
91,318
|
|
|
|
|
|
Kosmos' share of net income
|
$
|
45,659
|
|
|
Basis difference amortization(1)
|
26,963
|
|
|
Equity in earnings - KTIPI
|
$
|
18,696
|
|
______________________________________
|
|
|
|
(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.
|
With an effective date of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a
40.375%
undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward. This transaction was accounted for as an asset acquisition. The carrying value of the equity method investment was allocated to the undivided interest acquired and net working capital based on the estimated relative fair value of the acquired assets.
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. These fair value estimates were used to allocate the carrying value of the equity method investment to our balance sheet on a relative fair value basis.
|
|
|
|
|
|
|
|
|
|
|
Carrying Value Allocation
(in thousands)
|
|
Assets acquired:
|
|
|
|
Proved oil and gas properties
|
|
$
|
372,144
|
|
|
Unproved oil and gas properties
|
|
103,909
|
|
|
Prepaids and other
|
|
7,273
|
|
|
Total assets acquired
|
|
$
|
483,326
|
|
|
|
|
|
|
Liabilities assumed:
|
|
|
|
Asset retirement obligations
|
|
$
|
114,395
|
|
|
Deferred tax liabilities
|
|
247,636
|
|
|
Accrued liabilities and other
|
|
69,399
|
|
|
Total liabilities assumed
|
|
$
|
431,430
|
|
|
|
|
|
|
Carrying value:
|
|
|
|
Equity method investment carrying value at December 31, 2018
|
|
$
|
51,896
|
|
8. Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2019
|
|
December 31,
2018
|
|
|
(In thousands)
|
|
Outstanding debt principal balances:
|
|
|
|
|
|
|
Facility
|
$
|
1,500,000
|
|
|
$
|
1,325,000
|
|
|
Corporate Revolver
|
225,000
|
|
|
325,000
|
|
|
Senior Secured Notes
|
525,000
|
|
|
525,000
|
|
|
Total
|
2,250,000
|
|
|
2,175,000
|
|
|
Unamortized deferred financing costs and discounts(1)
|
(54,174
|
)
|
|
(54,453
|
)
|
|
Long-term debt, net
|
$
|
2,195,826
|
|
|
$
|
2,120,547
|
|
__________________________________
|
|
|
|
(1)
|
Includes
$42.2 million
and
$40.5 million
of unamortized deferred financing costs related to the Facility and
$12.0 million
and
$14.0 million
of unamortized deferred financing costs and discounts related to the Senior Secured Notes as of
March 31, 2019
and
December 31, 2018
, 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 obligated 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. In March 2019, following the lender's annual redetermination, the available borrowing base under our Facility was
$1.7 billion
. 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
March 31, 2019
, we have
$42.2 million
of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility.
As of
March 31, 2019
, borrowings under the Facility totaled
$1,500.0 million
and the undrawn availability under the Facility was
$200.0 million
, which was reduced to
$100 million
following the Senior Notes issuance in April 2019.
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
March 31, 2019
, we had
no
letters of credit issued under the Facility.
We were in compliance with the financial covenants contained in the Facility as of
March 31, 2019
(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
March 31, 2019
, borrowings under the Corporate Revolver totaled
$225.0 million
and the undrawn availability under the Corporate Revolver was
$175.0 million
. As of
March 31, 2019
, we have
$8.3 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
March 31, 2019
(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 December 2018, the LC Facility size was voluntarily reduced to
$20.0 million
based on the expiration of several large outstanding letters of credit. As of
March 31, 2019
, there were
six
outstanding letters of credit totaling
$9.4 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
7.875%
Senior Secured Notes due 2021 (the "Senior Secured 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 Secured 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 Secured Notes had identical terms to the initial
$300.0 million
of Senior Secured Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
In April 2019, all of the Senior Secured Notes were redeemed for
$543.8 million
, including accrued interest and the early redemption premium. The redemption resulted in a
$22.9 million
loss on extinguishment of debt, which will be included in Interest and other financing costs, net on the Consolidated Statement of Operations during the second quarter.
7.125%
Senior Notes due 2026
In April 2019, the Company issued
$650.0 million
of
7.125%
Senior Notes (the "Senior Notes") and received net proceeds of approximately
$640.0 million
after deducting commissions and other expenses. We used the net proceeds to redeem all of the Senior Secured Notes, 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 Senior Notes.
The Senior Notes mature on April 4, 2026. We will pay interest in arrears on the Senior Notes each April 4 and October 4, commencing on October 4, 2019. The 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 rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility.
At any time prior to April 4, 2022, and subject to certain conditions, the Company may, on one or more occasions, redeem up to
40%
of the original principal amount of the Senior Notes with an amount not to exceed the net cash proceeds of certain equity offerings at a redemption price of
107.1%
of the outstanding principal amount of the 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 April 4, 2022 the Company may, on any one or more occasions, redeem all or a part of the Senior Notes at a redemption price equal to
100%
, plus any accrued and unpaid interest, and plus a “make-whole” premium. On or after April 4, 2022, the Company may redeem all or a part of the 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 April 4, 2022, but before April 4, 2023
|
|
103.6
|
%
|
|
On or after April 4, 2023, but before April 4, 2024
|
|
101.8
|
%
|
|
On or after April 4, 2024 and thereafter
|
|
100.0
|
%
|
We may also redeem the 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 Senior Notes at a price equal to the principal amount of the 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 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 Senior Notes indenture, the Company will be required to make an offer to repurchase the 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 Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to
100%
of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.
The Senior Notes indenture restricts our ability and the ability of our 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 our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 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 and is continuing.
At
March 31, 2019
, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
|
Total
|
|
2019(2)
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
|
(In thousands)
|
|
Principal debt repayments(1)
|
$
|
2,250,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
799,800
|
|
|
$
|
509,200
|
|
|
$
|
271,600
|
|
|
$
|
669,400
|
|
__________________________________
|
|
|
|
(1)
|
Includes the scheduled principal maturities for the
$525.0 million
aggregate principal amount of Senior Secured 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
March 31, 2019
, 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. In April 2019, the Senior Secured Notes were redeemed with the proceeds from the issuance of the Senior Notes which increased the borrowings to
$650 million
and extended the maturity date to 2026.
|
|
|
|
|
(2)
|
Represents payments for the period
April 1, 2019
through
December 31, 2019
.
|
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
|
Interest expense
|
$
|
38,172
|
|
|
$
|
24,893
|
|
|
Amortization—deferred financing costs
|
2,387
|
|
|
2,440
|
|
|
Loss on extinguishment of debt
|
—
|
|
|
4,056
|
|
|
Capitalized interest
|
(7,251
|
)
|
|
(4,820
|
)
|
|
Deferred interest
|
836
|
|
|
(1,256
|
)
|
|
Interest income
|
(652
|
)
|
|
(948
|
)
|
|
Other, net
|
1,549
|
|
|
1,329
|
|
|
Interest and other financing costs, net
|
$
|
35,041
|
|
|
$
|
25,694
|
|
9. 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
March 31, 2019
. 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
|
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apr — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
7,880
|
|
|
$
|
1.17
|
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
53.33
|
|
|
$
|
73.57
|
|
|
|
Apr — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
688
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
80.00
|
|
|
|
Apr — Dec
|
|
Swaps
|
|
NYMEX WTI
|
|
1,224
|
|
|
—
|
|
|
52.22
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Apr — Jun
|
|
Collars
|
|
NYMEX WTI
|
|
169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57.77
|
|
|
63.70
|
|
|
|
Apr — Dec
|
|
Collars
|
|
Argus LLS
|
|
750
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.00
|
|
|
88.75
|
|
|
|
2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
4,500
|
|
|
$
|
0.58
|
|
|
$
|
—
|
|
|
$
|
45.00
|
|
|
$
|
57.50
|
|
|
$
|
81.91
|
|
|
|
Jan — Dec
|
|
Sold calls(1)(2)
|
|
Dated Brent
|
|
8,000
|
|
|
$
|
1.17
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
85.00
|
|
|
__________________________________
|
|
|
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
|
|
|
|
(2)
|
Deferred premium payable to be paid April 1, 2019 — December 31, 2019.
|
In April 2019, we entered into three-way collar contracts for
1.5
MMBbl from January 2020 through December 2020 with a sold put price of
$45.00
per barrel, a floor price of
$57.50
per barrel and a ceiling price of
$75.00
per barrel. The contracts are indexed to Dated Brent prices.
The following tables disclose the Company’s derivative instruments as of
March 31, 2019
and
December 31, 2018
and gain/(loss) from derivatives during the
three
months ended
March 31, 2019
and
2018
, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
|
|
|
|
Asset (Liability)
|
|
Type of Contract
|
|
Balance Sheet Location
|
|
March 31,
2019
|
|
December 31,
2018
|
|
|
|
|
|
(In thousands)
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Derivative assets:
|
|
|
|
|
|
|
|
Commodity(1)
|
|
Derivatives assets—current
|
|
$
|
17,289
|
|
|
$
|
38,785
|
|
|
Commodity(2)
|
|
Derivatives assets—long-term
|
|
8,243
|
|
|
14,312
|
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
Commodity(3)
|
|
Derivatives liabilities—current
|
|
(51,713
|
)
|
|
(12,172
|
)
|
|
Commodity(4)
|
|
Derivatives liabilities—long-term
|
|
(13,306
|
)
|
|
(10,181
|
)
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(39,487
|
)
|
|
$
|
30,744
|
|
__________________________________
|
|
|
|
(1)
|
Includes
zero
and
$0.4 million
as of
March 31, 2019
and
December 31, 2018
, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of
$5.5 million
and
$1.6 million
related to commodity derivative contracts as of
March 31, 2019
and
December 31, 2018
, respectively.
|
|
|
|
|
(2)
|
Includes net deferred premiums payable of
$0.1 million
and
$1.3 million
related to commodity derivative contracts as of
March 31, 2019
and
December 31, 2018
, respectively.
|
|
|
|
|
(3)
|
Includes net deferred premiums payable of
$11.0 million
and
$18.0 million
related to commodity derivative contracts as of
March 31, 2019
and
December 31, 2018
, respectively.
|
|
|
|
|
(4)
|
Includes net deferred premiums payable of
$2.0 million
and
$0.5 million
related to commodity derivative contracts as of
March 31, 2019
and
December 31, 2018
, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss)
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
Type of Contract
|
|
Location of Gain/(Loss)
|
|
2019
|
|
2018
|
|
|
|
|
|
(In thousands)
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
Commodity(1)
|
|
Oil and gas revenue
|
|
$
|
3,278
|
|
|
$
|
(841
|
)
|
|
Commodity
|
|
Derivatives, net
|
|
(77,085
|
)
|
|
(38,478
|
)
|
|
Interest rate
|
|
Interest expense
|
|
—
|
|
|
353
|
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(73,807
|
)
|
|
$
|
(38,966
|
)
|
__________________________________
|
|
|
|
(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
March 31, 2019
and
December 31, 2018
, 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.
10. 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
March 31, 2019
and
December 31, 2018
, 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)
|
|
March 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
25,532
|
|
|
$
|
—
|
|
|
$
|
25,532
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(65,019
|
)
|
|
—
|
|
|
(65,019
|
)
|
|
Total
|
$
|
—
|
|
|
$
|
(39,487
|
)
|
|
$
|
—
|
|
|
$
|
(39,487
|
)
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
53,097
|
|
|
$
|
—
|
|
|
$
|
53,097
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(22,353
|
)
|
|
—
|
|
|
(22,353
|
)
|
|
Total
|
$
|
—
|
|
|
$
|
30,744
|
|
|
$
|
—
|
|
|
$
|
30,744
|
|
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.
Debt
The following table presents the carrying values and fair values at
March 31, 2019
and
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
|
(In thousands)
|
|
Senior Notes
|
$
|
513,006
|
|
|
$
|
535,337
|
|
|
$
|
511,873
|
|
|
$
|
525,026
|
|
|
Corporate Revolver
|
225,000
|
|
|
225,000
|
|
|
325,000
|
|
|
325,000
|
|
|
Facility
|
1,500,000
|
|
|
1,500,000
|
|
|
1,325,000
|
|
|
1,325,000
|
|
|
Total
|
$
|
2,238,006
|
|
|
$
|
2,260,337
|
|
|
$
|
2,161,873
|
|
|
$
|
2,175,026
|
|
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.
11. 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 Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of
$8.4 million
and
$8.0 million
during the
three months ended
March 31, 2019
and
2018
, respectively. The total tax benefit was
$1.3 million
and
$0.9 million
during the
three months ended
March 31, 2019
and
2018
, respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of
$1.2 million
and
$0.2 million
during the
three months ended
March 31, 2019
and
2018
, respectively. The fair value of awards vested was
$13.2 million
and
$56.6 million
during the
three months ended
March 31, 2019
and
2018
, 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 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
March 31, 2019
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2018
|
4,115
|
|
|
$
|
6.42
|
|
|
6,716
|
|
|
$
|
9.02
|
|
|
Granted(1)
|
2,726
|
|
|
4.81
|
|
|
3,041
|
|
|
6.02
|
|
|
Forfeited(1)
|
(53
|
)
|
|
6.46
|
|
|
(275
|
)
|
|
10.64
|
|
|
Vested
|
(1,797
|
)
|
|
5.78
|
|
|
(1,269
|
)
|
|
6.36
|
|
|
Outstanding at March 31, 2019
|
4,991
|
|
|
5.76
|
|
|
8,213
|
|
|
8.41
|
|
__________________________________
|
|
|
|
(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
March 31, 2019
, total equity-based compensation to be recognized on unvested restricted stock units is
$54.9 million
over a weighted average period of
2.35 years
. In March 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 stockholders 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
March 31, 2019
, the Company had approximately
10.2 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
$12.96
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
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
0.8%
to
2.5%
.
12. Income Taxes
Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018. The company was not subject to taxation at the parent company level for the three months ended March 31, 2018. We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors, which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions.
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.
The income tax provision consists of United States, Ghanaian income and Texas margin taxes. Beginning January 1, 2019, the income tax provision includes our Equatorial Guinean pre-tax income and income taxes. For 2018, results from operations in Equatorial Guinea is reported, net of tax, as Gain on equity method investments, net in our Consolidated Statement of Operations. 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 March 31,
|
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
|
United States
|
$
|
(55,741
|
)
|
|
$
|
1,633
|
|
|
Bermuda
|
—
|
|
|
(16,071
|
)
|
|
Foreign—other
|
(5,839
|
)
|
|
(60,136
|
)
|
|
Income (loss) before income taxes
|
$
|
(61,580
|
)
|
|
$
|
(74,574
|
)
|
For the
three months ended
,
March 31, 2019
and
2018
, our effective tax rate was
14%
and
33%
, respectively. For the three months ended
March 31, 2019
our overall effective tax rate was 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, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean 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.
For the three-months ended March 31, 2018, our overall effective tax rate was 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 the United States, Ghana and Equatorial Guinea. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2018 and in the United States, to federal income tax examinations for tax years 2015 through 2018.
As of
March 31, 2019
, 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.
13.
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
|
|
|
March 31,
|
|
|
2019
|
|
2018
|
|
Numerator:
|
|
|
|
|
|
|
Net loss allocable to common stockholders
|
$
|
(52,906
|
)
|
|
$
|
(50,226
|
)
|
|
Denominator:
|
|
|
|
|
Weighted average number of shares outstanding:
|
|
|
|
|
Basic
|
401,164
|
|
|
395,600
|
|
|
Restricted stock units(1)
|
—
|
|
|
—
|
|
|
Diluted
|
401,164
|
|
|
395,600
|
|
|
Net loss per share:
|
|
|
|
|
Basic
|
$
|
(0.13
|
)
|
|
$
|
(0.13
|
)
|
|
Diluted
|
$
|
(0.13
|
)
|
|
$
|
(0.13
|
)
|
__________________________________
|
|
|
|
(1)
|
We excluded outstanding restricted stock awards and units of
8.9 million
and
11.3 million
for the
three
months ended
March 31, 2019
and
2018
, respectively, from the computations of diluted net
loss
per share because the effect would have been anti-dilutive
.
|
14. 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 each of Mauritania, Sao Tome and Principe, and Namibia and
two
exploration wells in Senegal. Our partner in Mauritania and Senegal 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 Sao Tome and Principe, we also have 3D seismic acquisition requirements of approximately
13,500
square kilometers.
Leases
We have commitments under operating leases primarily related to office leases. Our leases have initial lease terms ranging from
one year
to
ten years
. Certain lease agreements contain provisions for future rent increases.
The components of lease cost for the three months ended March 31 are as follows:
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2019
|
|
|
(In thousands)
|
|
Operating lease cost
|
$
|
1,407
|
|
|
Short-term lease cost
|
5
|
|
|
Total lease cost
|
$
|
1,412
|
|
Other information related to operating leases at
March 31, 2019
, is as follows:
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
|
(In thousands, except lease term and discount rate)
|
|
|
Balance sheet classifications
|
|
|
Other assets (right-of-use assets)
|
$
|
22,410
|
|
|
Accrued liabilities (current maturities of leases)
|
2,842
|
|
|
Other long-term liabilities (non-current maturities of leases)
|
20,884
|
|
|
|
|
|
Weighted average remaining lease term
|
9.1 years
|
|
|
|
|
|
Weighted average discount rate
|
9.9
|
%
|
The table below presents supplemental cash flow information related to leases during the three months ended March 31, 2019:
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2019
|
|
|
(In thousands)
|
|
Operating cash flows for operating leases
|
$
|
1,223
|
|
Future minimum rental commitments under our leases at
March 31, 2019
, are as follows:
|
|
|
|
|
|
|
|
|
Operating Leases(1)
|
|
|
(In thousands)
|
|
2019(2)
|
$
|
2,078
|
|
|
2020
|
4,522
|
|
|
2021
|
3,852
|
|
|
2022
|
3,903
|
|
|
2023
|
3,916
|
|
|
Thereafter
|
19,549
|
|
|
Total undiscounted lease payments
|
$
|
37,820
|
|
|
Less: Imputed interest
|
(14,094
|
)
|
|
Total lease liabilities
|
$
|
23,726
|
|
__________________________________
|
|
|
|
(1)
|
Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.
|
|
|
|
|
(2)
|
Represents payments for the period from
April 1, 2019
through
December 31, 2019
.
|
Performance Obligations
As of
March 31, 2019
and
December 31, 2018
, the Company had secured performance bonds totaling
$199.8 million
and
$200.9 million
, respectively, for our supplemental bonding requirements stipulated by the BOEM and
$3.7 million
and
$3.7 million
, respectively, 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
March 31, 2019
and
December 31, 2018
, we had
zero
and
$0.6 million
, respectively, of cash collateral against these secured performance bonds which is classified as Other long term assets in our consolidated balance sheet.
In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal which obligate us separately to finance the respective national oil company’s share of certain development costs incurred through first gas for Phase 1, currently projected in the first half of 2022. Kosmos’ total 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.
Dividends
On February 25, 2019, we announced our quarterly cash dividend of
$0.0452
per common share. Dividends of
$18.1 million
were paid on March 28, 2019 to stockholders of record on March 7, 2019. On May 3, 2019, we declared our quarterly cash dividend of
$0.0452
per common share for Q2 payable on June 27, 2019 to stockholders of record as of June 6, 2019.
15. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2019
|
|
December 31,
2018
|
|
|
(In thousands)
|
|
Accrued liabilities:
|
|
|
|
|
|
|
Exploration, development and production
|
$
|
102,538
|
|
|
$
|
92,613
|
|
|
Revenue payable
|
21,288
|
|
|
24,379
|
|
|
Current asset retirement obligations
|
5,776
|
|
|
6,617
|
|
|
Operating lease liabilities
|
2,842
|
|
|
—
|
|
|
General and administrative expenses
|
14,742
|
|
|
39,373
|
|
|
Interest
|
7,445
|
|
|
18,152
|
|
|
Income taxes
|
24,665
|
|
|
8,958
|
|
|
Taxes other than income
|
2,669
|
|
|
4,613
|
|
|
Derivatives
|
3,504
|
|
|
441
|
|
|
Other
|
2,472
|
|
|
450
|
|
|
|
$
|
187,941
|
|
|
$
|
195,596
|
|
Asset Retirement Obligations
The following table summarizes the changes in the Company's asset retirement obligations:
|
|
|
|
|
|
|
|
|
March 31,
2019
|
|
|
(In thousands)
|
|
Asset retirement obligations:
|
|
|
|
Beginning asset retirement obligations
|
$
|
151,953
|
|
|
Additions associated with Equatorial Guinea - Ceiba Field and Okume Complex
|
114,395
|
|
|
Liabilities incurred during period
|
3,348
|
|
|
Liabilities settled during period
|
(2,232
|
)
|
|
Revisions in estimated retirement obligations
|
1,164
|
|
|
Accretion expense
|
5,683
|
|
|
Ending asset retirement obligations
|
$
|
274,311
|
|
With an effective date of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a
40.375%
undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward, which includes additions to our asset retirement obligations.
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, net of any insurance reimbursements. During the three months ended March 31, 2019 and 2018 we incurred approximately
$11.0 million
and
$9.8 million
, respectively in expenditures offset by approximately
$31.0 million
and
$1.3 million
, respectively in insurance recoveries.
Other Expenses, Net
Other expenses, net incurred during the period is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
|
Loss on disposal of inventory
|
$
|
187
|
|
|
$
|
—
|
|
|
Loss on ARO liability settlements
|
1,918
|
|
|
—
|
|
|
Disputed charges and related costs, net of recoveries
|
(14
|
)
|
|
2,335
|
|
|
Other, net
|
28
|
|
|
1,370
|
|
|
Other expenses, net
|
$
|
2,119
|
|
|
$
|
3,705
|
|
The disputed charges and related costs, net of recoveries 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, during 2018 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.
16. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At
March 31, 2019
, substantially all of our long-lived assets and all of our product sales are related to operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. In addition, we have exploration activities in other countries in the Atlantic Margins. To assess performance of the reporting segments, the Chief Operating Decision Maker ("CODM") 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 March 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
122,919
|
|
|
$
|
88,805
|
|
|
$
|
—
|
|
|
$
|
85,066
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
296,790
|
|
|
Other income, net
|
—
|
|
|
—
|
|
|
—
|
|
|
135
|
|
|
72,809
|
|
|
(72,944
|
)
|
|
—
|
|
|
Total revenues and other income
|
122,919
|
|
|
88,805
|
|
|
—
|
|
|
85,201
|
|
|
72,809
|
|
|
(72,944
|
)
|
|
296,790
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
30,057
|
|
|
22,605
|
|
|
—
|
|
|
27,137
|
|
|
—
|
|
|
—
|
|
|
79,799
|
|
|
Facilities insurance modifications, net
|
(20,021
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20,021
|
)
|
|
Exploration expenses
|
52
|
|
|
3,171
|
|
|
6,442
|
|
|
11,194
|
|
|
9,485
|
|
|
—
|
|
|
30,344
|
|
|
General and administrative
|
5,956
|
|
|
2,045
|
|
|
2,287
|
|
|
7,393
|
|
|
44,205
|
|
|
(25,978
|
)
|
|
35,908
|
|
|
Depletion, depreciation and amortization
|
54,863
|
|
|
23,017
|
|
|
15
|
|
|
39,090
|
|
|
1,110
|
|
|
—
|
|
|
118,095
|
|
|
Interest and other financing costs, net(1)
|
20,653
|
|
|
—
|
|
|
(6,793
|
)
|
|
5,929
|
|
|
17,036
|
|
|
(1,784
|
)
|
|
35,041
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
31,903
|
|
|
45,182
|
|
|
—
|
|
|
77,085
|
|
|
Other expenses, net
|
45,100
|
|
|
340
|
|
|
229
|
|
|
1,592
|
|
|
40
|
|
|
(45,182
|
)
|
|
2,119
|
|
|
Total costs and expenses
|
136,660
|
|
|
51,178
|
|
|
2,180
|
|
|
124,238
|
|
|
117,058
|
|
|
(72,944
|
)
|
|
358,370
|
|
|
Income (loss) before income taxes
|
(13,741
|
)
|
|
37,627
|
|
|
(2,180
|
)
|
|
(39,037
|
)
|
|
(44,249
|
)
|
|
—
|
|
|
(61,580
|
)
|
|
Income tax expense (benefit)
|
(4,983
|
)
|
|
15,531
|
|
|
—
|
|
|
(8,206
|
)
|
|
(11,016
|
)
|
|
—
|
|
|
(8,674
|
)
|
|
Net income (loss)
|
$
|
(8,758
|
)
|
|
$
|
22,096
|
|
|
$
|
(2,180
|
)
|
|
$
|
(30,831
|
)
|
|
$
|
(33,233
|
)
|
|
$
|
—
|
|
|
$
|
(52,906
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
34,967
|
|
|
$
|
14,936
|
|
|
$
|
2,252
|
|
|
$
|
45,882
|
|
|
$
|
12,191
|
|
|
$
|
—
|
|
|
$
|
110,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
$
|
1,681,317
|
|
|
$
|
470,974
|
|
|
$
|
414,035
|
|
|
$
|
1,309,412
|
|
|
$
|
39,065
|
|
|
$
|
—
|
|
|
$
|
3,914,803
|
|
|
Total assets
|
$
|
1,938,645
|
|
|
$
|
533,244
|
|
|
$
|
528,068
|
|
|
$
|
3,369,271
|
|
|
$
|
10,092,342
|
|
|
$
|
(11,959,714
|
)
|
|
$
|
4,501,856
|
|
______________________________________
|
|
|
|
(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(1)
|
|
Mauritania/Senegal
|
|
U.S. Gulf of Mexico(2)
|
|
Corporate & Other
|
|
Eliminations(3)
|
|
Total
|
|
|
(in thousands)
|
|
Three months ended March 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenue
|
$
|
127,196
|
|
|
$
|
123,177
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(123,177
|
)
|
|
$
|
127,196
|
|
|
Other income, net
|
(18
|
)
|
|
143
|
|
|
—
|
|
|
—
|
|
|
65,060
|
|
|
(65,204
|
)
|
|
(19
|
)
|
|
Total revenues and other income
|
127,178
|
|
|
123,320
|
|
|
—
|
|
|
—
|
|
|
65,060
|
|
|
(188,381
|
)
|
|
127,177
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production
|
46,768
|
|
|
25,850
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25,850
|
)
|
|
46,768
|
|
|
Facilities insurance modifications, net
|
8,449
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,449
|
|
|
Exploration expenses
|
224
|
|
|
869
|
|
|
3,198
|
|
|
—
|
|
|
16,902
|
|
|
—
|
|
|
21,193
|
|
|
General and administrative
|
5,253
|
|
|
985
|
|
|
1,291
|
|
|
—
|
|
|
39,111
|
|
|
(24,757
|
)
|
|
21,883
|
|
|
Depletion, depreciation and amortization
|
53,351
|
|
|
53,998
|
|
|
15
|
|
|
—
|
|
|
911
|
|
|
(53,998
|
)
|
|
54,277
|
|
|
Interest and other financing costs, net(4)
|
21,254
|
|
|
(1
|
)
|
|
(3,921
|
)
|
|
—
|
|
|
10,146
|
|
|
(1,784
|
)
|
|
25,694
|
|
|
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38,478
|
|
|
—
|
|
|
38,478
|
|
|
(Gain) loss on equity method investments, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18,696
|
)
|
|
(18,696
|
)
|
|
Other expenses, net
|
40,809
|
|
|
121
|
|
|
1
|
|
|
—
|
|
|
1,254
|
|
|
(38,480
|
)
|
|
3,705
|
|
|
Total costs and expenses
|
176,108
|
|
|
81,822
|
|
|
584
|
|
|
—
|
|
|
106,802
|
|
|
(163,565
|
)
|
|
201,751
|
|
|
Income (loss) before income taxes
|
(48,930
|
)
|
|
41,498
|
|
|
(584
|
)
|
|
—
|
|
|
(41,742
|
)
|
|
(24,816
|
)
|
|
(74,574
|
)
|
|
Income tax expense (benefit)
|
(24,408
|
)
|
|
24,816
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
(24,816
|
)
|
|
(24,348
|
)
|
|
Net income (loss)
|
$
|
(24,522
|
)
|
|
$
|
16,682
|
|
|
$
|
(584
|
)
|
|
$
|
—
|
|
|
$
|
(41,802
|
)
|
|
$
|
—
|
|
|
$
|
(50,226
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated capital expenditures
|
$
|
18,102
|
|
|
$
|
6,891
|
|
|
$
|
3,256
|
|
|
$
|
—
|
|
|
$
|
29,380
|
|
|
$
|
—
|
|
|
$
|
57,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
$
|
1,868,283
|
|
|
$
|
7,931
|
|
|
$
|
385,386
|
|
|
$
|
—
|
|
|
$
|
44,937
|
|
|
$
|
—
|
|
|
$
|
2,306,537
|
|
|
Total assets
|
$
|
2,165,726
|
|
|
$
|
214,546
|
|
|
$
|
499,082
|
|
|
$
|
—
|
|
|
$
|
8,516,046
|
|
|
$
|
(8,364,872
|
)
|
|
$
|
3,030,528
|
|
______________________________________
|
|
|
|
(1)
|
Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the three months ended March 31, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.
|
|
|
|
|
(2)
|
No activity prior to September 14, 2018, the DGE acquisition date.
|
|
|
|
|
(3)
|
Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.
|
|
|
|
|
(4)
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2019
|
|
2018
|
|
|
|
(In thousands)
|
|
|
Consolidated capital expenditures:
|
|
|
|
|
|
Consolidated Statements of Cash Flows - Investing activities:
|
|
|
|
|
|
Oil and gas assets
|
$
|
78,377
|
|
|
$
|
34,712
|
|
|
|
Other property
|
1,071
|
|
|
1,757
|
|
|
|
Adjustments:
|
|
|
|
|
|
Changes in capital accruals
|
14,925
|
|
|
4,684
|
|
|
|
Exploration expense, excluding unsuccessful well costs(1)
|
30,504
|
|
|
21,150
|
|
|
|
Capitalized interest
|
(7,251
|
)
|
|
(4,820
|
)
|
|
|
Other
|
(7,398
|
)
|
|
146
|
|
|
|
Total consolidated capital expenditures
|
$
|
110,228
|
|
|
$
|
57,629
|
|
|
______________________________________
|
|
|
|
(1)
|
Unsuccessful well costs are included in oil and gas assets when incurred.
|