Notes to Consolidated Financial Statements
(Unaudited)
1. Organization
Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s corporate management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.
Kosmos is
a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margin. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin short-cycle exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia and Sao Tome and Principe).
Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.
We have
one
reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to production located offshore Ghana and U.S. Gulf of Mexico. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea.
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
September 30, 2018
, the changes in the consolidated statements of shareholders’ equity for the
nine
months ended
September 30, 2018
, the consolidated results of operations for the three and
nine
months ended
September 30, 2018
and
2017
, and the consolidated cash flows for the
nine
months ended
September 30, 2018
and
2017
. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended
December 31, 2017
, included in our annual report on Form 10-K.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net
loss
, current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
(In thousands)
|
Cash and cash equivalents
|
$
|
192,646
|
|
|
$
|
233,412
|
|
Restricted cash - current
|
5,376
|
|
|
56,380
|
|
Restricted cash - long-term
|
9,473
|
|
|
15,194
|
|
Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows
|
$
|
207,495
|
|
|
$
|
304,986
|
|
Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of
September 30, 2018
and
December 31, 2017
, we had
$5.4 million
and
$31.6 million
, respectively, of current restricted cash and
$9.2 million
and
$15.2 million
, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. As of
September 30, 2018
, we also had
$0.2 million
in other long-term restricted cash.
In addition, prior to our reserves based debt facility (the "Facility") being amended and restated in February 2018, we were required to maintain a restricted cash balance that was sufficient to meet the payment of interest and fees for the next
six
-month period on the
7.875%
Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver, or the Facility, whichever was greater. As of
December 31, 2017
, we had
$24.8 million
in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios.
Inventories
Inventories consisted of
$86.8 million
(including
$22.1 million
acquired through the Deep Gulf Energy (together with its subsidiaries "DGE") acquisition) and
$63.5 million
of materials and supplies and
$3.2 million
and
$8.4 million
of hydrocarbons as of
September 30, 2018
and
December 31, 2017
, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Revenue Recognition
We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of
September 30, 2018
and
December 31, 2017
, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are recognized when production has been sold to a purchaser at a fixed or determinable price, title has transferred and collectability is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Oil and gas revenue is composed of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands)
|
Revenue from contracts with customers - Ghana
|
$
|
215,581
|
|
|
$
|
157,461
|
|
|
$
|
557,459
|
|
|
$
|
401,816
|
|
Revenue from contracts with customers - U.S. Gulf of Mexico
|
24,177
|
|
|
—
|
|
|
24,177
|
|
|
—
|
|
Provisional oil sales contracts
|
3,075
|
|
|
(6,221
|
)
|
|
3,584
|
|
|
(10,781
|
)
|
Oil and gas revenue
|
$
|
242,833
|
|
|
$
|
151,240
|
|
|
585,220
|
|
|
391,035
|
|
Recent Accounting Standards
Recently Adopted
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.
In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued.
Not Yet Adopted
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements.
3. Acquisitions and Divestitures
2018 Transactions
In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a
35%
participating interest in the blocks and the operator, BP, holds a
50%
participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a
15%
carried interest in the blocks through exploration. The petroleum contracts cover approximately
13,600
square kilometers, with a first exploration period of
four
years from the effective date (March 2018). The exploration periods can be extended an additional
four
years at our election subject to fulfilling specific work obligations. The first exploration period work programs include a
13,500
square kilometer 3D seismic acquisition requirement across the
two
blocks.
In June 2018, we completed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a
40%
non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately
3,500
square kilometers, with a first exploration period of
three
years from the effective date (March 2018) which can be extended up to
four
additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a
3,000
square kilometer 3D seismic acquisition requirement.
In September 2018, we completed the acquisition of DGE, a deepwater company operating in the U.S. Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of
$1.275 billion
, comprised of
$952.6 million
in cash and
$307.9 million
in Kosmos common stock and
$14.9 million
of transaction related costs. We funded the cash portion of the purchase price using cash on hand and drawings under our existing credit facilities. We also received
$200.0 million
of additional firm commitments under the Facility, which provides further liquidity to the Company.
The DGE acquisition was accounted for under the asset acquisition method and the purchase price allocation is shown below. The purchase price allocation was based on the estimated relative fair value of identifiable assets acquired and liabilities assumed.
The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate.
|
|
|
|
|
|
|
|
Purchase Price Allocation
(in thousands)
|
Fair value of assets acquired:
|
|
|
Proved oil and gas properties
|
|
$
|
1,045,509
|
|
Unproved oil and gas properties
|
|
300,420
|
|
Accounts receivable and other
|
|
179,332
|
|
|
|
|
Total assets acquired
|
|
$
|
1,525,261
|
|
|
|
|
Fair value of liabilities assumed:
|
|
|
Accrued liabilities and other
|
|
$
|
123,034
|
|
Asset retirement obligations
|
|
86,580
|
|
Derivative liabilities
|
|
40,265
|
|
|
|
|
Total liabilities assumed
|
|
$
|
249,879
|
|
|
|
|
|
|
|
Cash consideration paid
|
|
$
|
952,586
|
|
Fair value of common stock(1)
|
|
307,944
|
|
Transaction related costs
|
|
14,852
|
|
Total purchase price
|
|
$
|
1,275,382
|
|
|
|
(1)
|
Based on
34,993,585
common shares issued at a price of
$8.80
per share, which is the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.
|
As a result of the DGE acquisition, we have included
$24.2 million
of revenues and
$4.4 million
of direct operating expenses in our consolidated statements of operations for the period from September 14, 2018 to September 30, 2018.
In October 2018, Kosmos entered into a strategic exploration alliance with Shell Exploration Company B.V. (“Shell”) to jointly explore in Southern West Africa. Initially the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39.
2017 Transactions
In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which held an
85%
paying interest (
80.75%
revenue interest) in the Ceiba Field and Okume Complex assets located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own
50%
of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was
$650 million
effective as of
January 1, 2017
. After purchase price adjustments, Kosmos paid net cash consideration of approximately
$231 million
at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment.
In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. In August 2018, we closed a farm-out agreement with Trident, whereby they acquired a
40%
participating interest in blocks EG-21, S, and W, resulting in a
$7.7 million
gain. After giving effect to the farm-out agreement, we hold a
40%
participating interest and are the operator in all
three
blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a
20%
carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's
20%
carried interest will convert to a
20%
participating interest. The petroleum contracts cover approximately
6,000
square kilometers, with a first exploration period of
five
years from the effective date (March 2018). The first exploration period consists of
two
sub-periods of
three
and
two
years, respectively. The first exploration sub-period work program includes a
6,000
square kilometer 3D seismic acquisition requirement across the
three
blocks.
In
December 2017
, as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a
45%
participating interest and are the operator in all
five
blocks. BP has a
45%
participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a
10%
carried interest. The petroleum contracts cover approximately
17,000
square kilometers, with a first exploration period of
three
years. The first exploration period work program includes a
12,000
square kilometer 3D seismic acquisition across the
five
blocks.
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, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s
5%
share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of
September 30, 2018
and
December 31, 2017
, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were
$14.0 million
and
$15.2 million
, respectively, and the long-term portions were
$21.9 million
and
$31.6 million
, respectively.
The Company's related party receivables consists primarily of receivables from Trident who owns a
50%
interest in KTIPI. As of September 30, 2018 the balance due from Trident consists of $
13.7 million
related to the farm-out of Blocks EG-21, S, and W, and $
7.1 million
related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations.
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
(In thousands)
|
Oil and gas properties:
|
|
|
|
|
|
Proved properties
|
$
|
2,749,163
|
|
|
$
|
1,653,616
|
|
Unproved properties
|
733,274
|
|
|
465,109
|
|
Support equipment and facilities
|
1,450,907
|
|
|
1,427,054
|
|
Total oil and gas properties
|
4,933,344
|
|
|
3,545,779
|
|
Accumulated depletion
|
(1,434,489
|
)
|
|
(1,234,806
|
)
|
Oil and gas properties, net
|
3,498,855
|
|
|
2,310,973
|
|
|
|
|
|
Other property
|
46,513
|
|
|
39,405
|
|
Accumulated depreciation
|
(35,831
|
)
|
|
(32,550
|
)
|
Other property, net
|
10,682
|
|
|
6,855
|
|
|
|
|
|
Property and equipment, net
|
$
|
3,509,537
|
|
|
$
|
2,317,828
|
|
We recorded depletion expense of
$76.8 million
and
$70.9 million
for the three months ended
September 30, 2018
and
2017
, respectively, and
$199.7 million
and
$173.3 million
for the
nine months ended
September 30, 2018
and
2017
, respectively.
6. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the
nine
months ended
September 30, 2018
. The table excludes
$48.0 million
in costs that were capitalized and subsequently expensed during the same period.
|
|
|
|
|
|
September 30,
2018
|
|
(In thousands)
|
Beginning balance
|
$
|
410,113
|
|
Additions associated with the acquisition of DGE
|
26,426
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
7,658
|
|
Reclassification due to determination of proved reserves
|
—
|
|
Capitalized exploratory well costs charged to expense
|
(52,498
|
)
|
Ending balance
|
$
|
391,699
|
|
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
(In thousands, except well counts)
|
Exploratory well costs capitalized for a period of one year or less
|
$
|
26,426
|
|
|
$
|
67,159
|
|
Exploratory well costs capitalized for a period of one to two years
|
296,866
|
|
|
291,252
|
|
Exploratory well costs capitalized for a period of three years
|
68,407
|
|
|
51,702
|
|
Ending balance
|
$
|
391,699
|
|
|
$
|
410,113
|
|
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
|
3
|
|
|
5
|
|
As of
September 30, 2018
, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Greater Tortue discovery, which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal.
Akasa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Akasa discovery. As a result, we wrote off
$39.8 million
of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Akasa discovery area, and the acreage is not currently being relinquished.
Wawa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Wawa discovery. As a result, we wrote off
$17.9 million
of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Wawa discovery area, and the acreage is not currently being relinquished.
Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania, which encountered hydrocarbon pay.
Two
additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design ("FEED") process. The partnership has made significant progress towards a final investment decision for phase one. Led by BP, the FEED work for phase one is substantially complete. The Unit Development Plan has been submitted to both governments, and we have reached agreement with the Governments of Mauritania and Senegal on the non-PSA fiscal terms for this cross border project.
BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made.
Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. An appraisal well is scheduled in 2019 to further evaluate the discovery. Following additional evaluation, a decision regarding commerciality is expected to be made.
Nearly Headless Nick Discovery — In September 2018, the Nearly Headless Nick exploration well (
22.0%
WI) was successfully drilled to a total depth of approximately
5,800
meters (
19,050
feet) and encountered approximately
26
meters (
85
feet) of net pay in the Middle Miocene objective within the Mississippi Canyon 387 block offshore U.S. Gulf of Mexico. Nearly Headless Nick will be developed as a subsea tie back, which is expected to be brought online through the Delta House facility by 2020.
7. Equity Method Investments
Kosmos BP Senegal Limited ("KBSL")
As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture entity in which we owned a
50.01%
interest which was accounted for under the equity method of accounting.
In October 2017, KBSL transferred a
30%
participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a
30%
participating interest in the Senegal Blocks.
During the
three
and nine months ended
September 30,
2017 we recognized
$4.8 million
and
$11.2 million
, respectively, related to our share of losses in KBSL. Our initial contribution to KBSL was
$133.9 million
, which was recorded at our carrying costs.
Equatorial Guinea
As part of our acquisition of KTIPI, a corporate joint venture entity in which we own a
50%
interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a
100%
basis.
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
December 31,
|
|
2018
|
|
2017
|
|
(In thousands)
|
Assets
|
|
|
|
|
Total current assets
|
$
|
158,140
|
|
|
$
|
179,070
|
|
Property and equipment, net
|
291,960
|
|
|
345,611
|
|
Other assets
|
487
|
|
|
567
|
|
Total assets
|
$
|
450,587
|
|
|
$
|
525,248
|
|
|
|
|
|
Liabilities and shareholders' equity
|
|
|
|
Total current liabilities
|
$
|
196,338
|
|
|
$
|
106,769
|
|
Total long-term liabilities
|
541,881
|
|
|
565,591
|
|
Shareholders' equity:
|
|
|
|
Total shareholders' equity
|
(287,632
|
)
|
|
(147,112
|
)
|
Total liabilities and shareholders' equity
|
$
|
450,587
|
|
|
$
|
525,248
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Nine Months Ended September 30, 2018
|
|
(In thousands)
|
Revenues and other income:
|
|
|
|
|
Oil and gas revenue
|
$
|
215,408
|
|
|
$
|
600,158
|
|
Other income
|
(72
|
)
|
|
44
|
|
Total revenues and other income
|
215,336
|
|
|
600,202
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
Oil and gas production
|
40,334
|
|
|
115,366
|
|
Depletion and depreciation
|
33,044
|
|
|
108,996
|
|
Other expenses, net
|
(58
|
)
|
|
(211
|
)
|
Total costs and expenses
|
73,320
|
|
|
224,151
|
|
|
|
|
|
Income before income taxes
|
142,016
|
|
|
376,051
|
|
Income tax expense
|
50,796
|
|
|
134,047
|
|
Net income
|
$
|
91,220
|
|
|
$
|
242,004
|
|
|
|
|
|
Kosmos' share of net income
|
$
|
45,610
|
|
|
$
|
121,002
|
|
Basis difference amortization(1)
|
20,769
|
|
|
61,365
|
|
Equity in earnings - KTIPI
|
$
|
24,841
|
|
|
$
|
59,637
|
|
______________________________________
|
|
(1)
|
The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.
|
When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of
September 30, 2018
, we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such,
no
impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the
nine months ended
September 30, 2018
, we received
$207.5 million
of cash dividends from KTIPI, and we received an additional
$32.5 million
of cash dividends in October 2018.
8. Debt
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
(In thousands)
|
Outstanding debt principal balances:
|
|
|
|
|
|
Facility
|
$
|
1,325,000
|
|
|
$
|
800,000
|
|
Corporate Revolver
|
300,000
|
|
|
—
|
|
Senior Notes
|
525,000
|
|
|
525,000
|
|
Total
|
2,150,000
|
|
|
1,325,000
|
|
Unamortized deferred financing costs and discounts(1)
|
(55,466
|
)
|
|
(42,203
|
)
|
Long-term debt, net
|
$
|
2,094,534
|
|
|
$
|
1,282,797
|
|
__________________________________
|
|
(1)
|
Includes
$40.3 million
and
$23.6 million
of unamortized deferred financing costs related to the Facility and
$15.2 million
and
$18.6 million
of unamortized deferred financing costs and discounts related to the Senior Notes as of
September 30, 2018
and
December 31, 2017
, respectively.
|
Facility
In February 2018, the Company amended and restated the Facility with a total commitment of
$1.5 billion
from a number of financial institutions with additional commitments up to
$0.5 billion
being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with
two
existing financial institutions, which obligate the
two
financial institutions to provide the Company, upon the Company's election, with an additional commitment of
$200 million
in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and
$4.1 million
of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of
September 30, 2018
, we have
$40.3 million
of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility.
As of
September 30, 2018
, borrowings under the Facility totaled
$1,325.0 million
and the undrawn availability under the Facility was
$375.0 million
, which includes the
$200 million
in additional commitments referenced above.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires
one month
prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of
September 30, 2018
, we had
no
letters of credit issued under the Facility.
We were in compliance with the financial covenants contained in the Facility as of
September 30, 2018
(the most recent assessment date). The Facility contains customary cross default provisions.
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at
$400.0 million
, extending the maturity date from November 2018 to May 2022 and lowering the margin
100
basis points to
5%
. This results in lower commitment fees on the undrawn portion of the total commitments, which is
30%
per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs.
As of
September 30, 2018
, borrowings under the Corporate Revolver totaled
$300 million
and the undrawn availability under the Corporate Revolver was
$100 million
. As of September 30, 2018, we have
$9.6 million
of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. We were in compliance with the financial covenants contained in the Corporate Revolver as of
September 30, 2018
(the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
Revolving Letter of Credit Facility
We have a revolving letter of credit facility agreement (“LC Facility”), which matures in
July 2019
. In July 2018, the LC Facility size was voluntarily reduced to
$40.0 million
based on the expiration of several large outstanding letters of credit. As of
September 30, 2018
, there were
eight
outstanding letters of credit totaling
$16.9 million
under the LC Facility. The LC Facility contains customary cross default provisions.
7.875%
Senior Secured Notes due 2021
During August 2014, the Company issued
$300.0 million
of Senior Notes and received net proceeds of approximately
$292.5 million
after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
During April 2015, we issued an additional
$225.0 million
of Senior Notes and received net proceeds of
$206.8 million
after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional
$225.0 million
of Senior Notes have identical terms to the initial
$300.0 million
of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial
$300.0 million
Senior Notes and August 1, 2015 for the additional
$225.0 million
Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee both the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.
At
September 30, 2018
, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year
|
|
Total
|
|
2018(2)
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
(In thousands)
|
Principal debt repayments(1)
|
$
|
2,150,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
685,600
|
|
|
$
|
589,100
|
|
|
$
|
875,300
|
|
__________________________________
|
|
(1)
|
Includes the scheduled principal maturities for the
$525.0 million
aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of
September 30, 2018
, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
|
|
|
(2)
|
Represents payments for the period
October 1, 2018
through
December 31, 2018
.
|
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands)
|
Interest expense
|
$
|
27,317
|
|
|
$
|
22,961
|
|
|
$
|
77,121
|
|
|
$
|
68,934
|
|
Amortization—deferred financing costs
|
2,346
|
|
|
2,551
|
|
|
7,069
|
|
|
7,653
|
|
Loss on extinguishment of debt
|
268
|
|
|
—
|
|
|
4,324
|
|
|
—
|
|
Capitalized interest
|
(7,097
|
)
|
|
(8,563
|
)
|
|
(21,209
|
)
|
|
(25,498
|
)
|
Deferred interest
|
(194
|
)
|
|
662
|
|
|
(1,284
|
)
|
|
1,610
|
|
Interest income
|
(788
|
)
|
|
(745
|
)
|
|
(2,579
|
)
|
|
(2,485
|
)
|
Other, net
|
1,697
|
|
|
1,612
|
|
|
4,671
|
|
|
4,515
|
|
Interest and other financing costs, net
|
$
|
23,549
|
|
|
$
|
18,478
|
|
|
$
|
68,113
|
|
|
$
|
54,729
|
|
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
September 30, 2018
. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|
|
|
|
|
|
|
|
Net Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Premium
|
|
|
|
|
|
|
|
|
|
|
Term
|
|
Type of Contract
|
|
Index
|
|
MBbl
|
|
Payable/(Receivable)
|
|
Swap
|
|
Sold Put
|
|
Floor
|
|
Ceiling
|
|
Call
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oct — Dec
|
|
Swap with puts
|
|
Dated Brent
|
|
1,500
|
|
|
$
|
—
|
|
|
$
|
56.75
|
|
|
$
|
43.33
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Oct — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
733
|
|
|
0.74
|
|
|
—
|
|
|
41.57
|
|
|
56.57
|
|
|
65.91
|
|
|
—
|
|
Oct — Dec
|
|
Four-way collars
|
|
Dated Brent
|
|
751
|
|
|
1.06
|
|
|
—
|
|
|
40.00
|
|
|
50.00
|
|
|
61.33
|
|
|
70.00
|
|
Oct — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
503
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65.00
|
|
|
—
|
|
Oct — Dec
|
|
Purchased Calls
|
|
Dated Brent
|
|
500
|
|
|
1.88
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70.00
|
|
Oct — Dec
|
|
Purchased Puts
|
|
NYMEX WTI
|
|
141
|
|
|
2.70
|
|
|
—
|
|
|
—
|
|
|
53.00
|
|
|
—
|
|
|
—
|
|
Oct — Dec
|
|
Collars
|
|
NYMEX WTI
|
|
35
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
62.29
|
|
|
66.35
|
|
|
—
|
|
Oct — Dec
|
|
Swaps
|
|
NYMEX WTI
|
|
698
|
|
|
—
|
|
|
54.69
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
10,500
|
|
|
$
|
1.17
|
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
53.33
|
|
|
$
|
73.58
|
|
|
$
|
—
|
|
Jan — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
913
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
80.00
|
|
|
—
|
|
Jan — Dec
|
|
Swaps
|
|
NYMEX WTI
|
|
1,747
|
|
|
—
|
|
|
52.31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jan — Jun
|
|
Collars
|
|
NYMEX WTI
|
|
339
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57.77
|
|
|
63.70
|
|
|
—
|
|
Jan — Dec
|
|
Collars
|
|
Argus LLS
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.00
|
|
|
88.75
|
|
|
—
|
|
2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jan — Dec
|
|
Three-way collars
|
|
Dated Brent
|
|
2,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50.00
|
|
|
$
|
60.00
|
|
|
$
|
90.54
|
|
|
$
|
—
|
|
Jan — Dec
|
|
Sold calls(1)
|
|
Dated Brent
|
|
8,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
80.00
|
|
|
$
|
—
|
|
__________________________________
|
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
Interest Rate Derivative Contracts
The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
Term
|
|
Type of Contract
|
|
Floating Rate
|
|
Notional
|
|
Swap
|
|
Sold Call
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
October 2018 — December 2018
|
|
Capped swap
|
|
1-month LIBOR
|
|
$
|
200,000
|
|
|
1.23
|
%
|
|
3.00
|
%
|
The following tables disclose the Company’s derivative instruments as of
September 30, 2018
and
December 31, 2017
and gain/(loss) from derivatives during the
three
months ended
September 30, 2018
and
2017
, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value
|
|
|
|
|
Asset (Liability)
|
Type of Contract
|
|
Balance Sheet Location
|
|
September 30,
2018
|
|
December 31,
2017
|
|
|
|
|
(In thousands)
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
Derivative assets:
|
|
|
|
|
|
|
Commodity(1)
|
|
Derivatives assets—current
|
|
$
|
40,953
|
|
|
$
|
665
|
|
Interest rate
|
|
Derivatives assets—current
|
|
513
|
|
|
1,017
|
|
Commodity(2)
|
|
Derivatives assets—long-term
|
|
14,486
|
|
|
39
|
|
Derivative liabilities:
|
|
|
|
|
|
|
Commodity(3)
|
|
Derivatives liabilities—current
|
|
(212,217
|
)
|
|
(67,531
|
)
|
Commodity(4)
|
|
Derivatives liabilities—long-term
|
|
(110,245
|
)
|
|
(30,209
|
)
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(266,510
|
)
|
|
$
|
(96,019
|
)
|
__________________________________
|
|
(1)
|
Includes net deferred premiums payable of
$4.7 million
and net deferred premiums receivable of
$0.8 million
related to commodity derivative contracts as of
September 30, 2018
and
December 31, 2017
, respectively.
|
|
|
(2)
|
Includes net deferred premiums payable of
$2.4 million
and net deferred premiums receivable of
$0.1 million
related to commodity derivative contracts as of
September 30, 2018
and
December 31, 2017
, respectively.
|
|
|
(3)
|
Includes net deferred premiums payable of
$6.0 million
and
$5.6 million
related to commodity derivative contracts as of
September 30, 2018
and
December 31, 2017
, respectively.
|
|
|
(4)
|
Includes net deferred premiums payable of
$1.6 million
and
$4.8 million
related to commodity derivative contracts as of
September 30, 2018
and
December 31, 2017
, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain/(Loss)
|
|
Amount of Gain/(Loss)
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
September 30,
|
|
September 30,
|
Type of Contract
|
|
Location of Gain/(Loss)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
(In thousands)
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity(1)
|
|
Oil and gas revenue
|
|
$
|
3,075
|
|
|
$
|
(6,221
|
)
|
|
$
|
3,584
|
|
|
$
|
(10,781
|
)
|
Commodity
|
|
Derivatives, net
|
|
(57,357
|
)
|
|
(26,864
|
)
|
|
(236,107
|
)
|
|
36,404
|
|
Interest rate
|
|
Interest expense
|
|
15
|
|
|
64
|
|
|
466
|
|
|
301
|
|
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
(54,267
|
)
|
|
$
|
(33,021
|
)
|
|
$
|
(232,057
|
)
|
|
$
|
25,924
|
|
__________________________________
|
|
(1)
|
Amounts represent the change in fair value of our provisional oil sales contracts.
|
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of
September 30, 2018
and
December 31, 2017
, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.
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
September 30, 2018
and
December 31, 2017
, for each fair value hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
|
Quoted Prices in
|
|
|
|
|
|
|
|
Active Markets for
|
|
Significant Other
|
|
Significant
|
|
|
|
Identical Assets
|
|
Observable Inputs
|
|
Unobservable Inputs
|
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Total
|
|
(In thousands)
|
September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
55,439
|
|
|
$
|
—
|
|
|
$
|
55,439
|
|
Interest rate derivatives
|
—
|
|
|
513
|
|
|
—
|
|
|
513
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(322,462
|
)
|
|
—
|
|
|
(322,462
|
)
|
Total
|
$
|
—
|
|
|
$
|
(266,510
|
)
|
|
$
|
—
|
|
|
$
|
(266,510
|
)
|
December 31, 2017
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
Commodity derivatives
|
$
|
—
|
|
|
$
|
704
|
|
|
$
|
—
|
|
|
$
|
704
|
|
Interest rate derivatives
|
—
|
|
|
1,017
|
|
|
—
|
|
|
1,017
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity derivatives
|
—
|
|
|
(97,740
|
)
|
|
—
|
|
|
(97,740
|
)
|
Total
|
$
|
—
|
|
|
$
|
(96,019
|
)
|
|
$
|
—
|
|
|
$
|
(96,019
|
)
|
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
Commodity Derivatives
Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
Interest Rate Derivatives
Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.
Debt
The following table presents the carrying values and fair values at
September 30, 2018
and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2018
|
|
December 31, 2017
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
(In thousands)
|
Senior Notes
|
$
|
510,766
|
|
|
$
|
535,941
|
|
|
$
|
507,600
|
|
|
$
|
542,472
|
|
Corporate Revolver
|
300,000
|
|
|
300,000
|
|
|
—
|
|
|
—
|
|
Facility
|
1,325,000
|
|
|
1,325,000
|
|
|
800,000
|
|
|
800,000
|
|
Total
|
$
|
2,135,766
|
|
|
$
|
2,160,941
|
|
|
$
|
1,307,600
|
|
|
$
|
1,342,472
|
|
The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
11. Equity-based Compensation
Restricted Stock Awards and Restricted Stock Units
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of
$8.9 million
and
$9.6 million
during the three months ended
September 30, 2018
and
2017
, respectively, and
$26.0 million
and
$29.9 million
during the
nine months ended
September 30, 2018
and
2017
, respectively. The total tax benefit for the three months ended
September 30, 2018
and
2017
was
$1.6 million
and
$3.2 million
, respectively, and
$5.0 million
and
$9.9 million
during the
nine months ended
September 30, 2018
and
2017
, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of
$0.1 million
and
$0.2 million
for the three months ended
September 30, 2018
and
2017
, respectively, and
$(0.3) million
and
$3.1 million
during the
nine months ended
September 30, 2018
and
2017
, respectively. The fair value of
awards vested during the three months ended
September 30, 2018
and
2017
was approximately
$1.1 million
and
$1.4 million
, respectively, and
$83.1 million
and
$20.7 million
during the
nine months ended
September 30, 2018
and
2017
, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these grants vest over
three
years. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.
The following table reflects the outstanding restricted stock awards as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
Service Vesting
|
|
Average
|
|
Restricted Stock
|
|
Grant-Date
|
|
Awards
|
|
Fair Value
|
|
(In thousands)
|
|
|
Outstanding at December 31, 2017
|
220
|
|
|
$
|
8.64
|
|
Granted
|
—
|
|
|
—
|
|
Forfeited
|
—
|
|
|
—
|
|
Vested
|
(220
|
)
|
|
8.64
|
|
Outstanding at September 30, 2018
|
—
|
|
|
—
|
|
The following table reflects the outstanding restricted stock units as of
September 30, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
Market / Service
|
|
Weighted-
|
|
Service Vesting
|
|
Average
|
|
Vesting
|
|
Average
|
|
Restricted Stock
|
|
Grant-Date
|
|
Restricted Stock
|
|
Grant-Date
|
|
Units
|
|
Fair Value
|
|
Units
|
|
Fair Value
|
|
(In thousands)
|
|
|
|
(In thousands)
|
|
|
Outstanding at December 31, 2017
|
4,183
|
|
|
$
|
6.39
|
|
|
8,452
|
|
|
$
|
11.26
|
|
Granted(1)(2)
|
2,360
|
|
|
7.03
|
|
|
8,140
|
|
|
12.39
|
|
Forfeited
|
(116
|
)
|
|
6.49
|
|
|
(46
|
)
|
|
9.74
|
|
Vested
|
(2,173
|
)
|
|
6.93
|
|
|
(9,545
|
)
|
|
13.75
|
|
Outstanding at September 30, 2018
|
4,254
|
|
|
6.41
|
|
|
7,001
|
|
|
9.17
|
|
__________________________________
|
|
(1)
|
The restricted stock units with a combination of market and service vesting criteria include
4.9 million
shares granted as a result of the 2014 and 2015 awards achieving
200%
of their respective market performance conditions.
|
|
|
(2)
|
The restricted stock units with a combination of market and service vesting criteria include
0.7 million
shares granted to DGE employees as part of a new hire grant upon becoming employees of Kosmos. These shares were valued at
$12.93
per share based on the Monte Carlo simulation model.
|
As of
September 30, 2018
, total equity-based compensation to be recognized on unvested restricted stock units is
$36.2 million
over a weighted average period of
2.05 years
. In January 2018, the board of directors approved an amendment to the LTIP to add
11.0 million
shares to the plan which was approved by our shareholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of
50.5 million
shares pursuant to awards under the plan. At
September 30, 2018
, the Company had approximately
15.8 million
shares that remain available for issuance under the LTIP.
For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to
200%
of the awards granted. The grant date fair value ranged from
$4.83
to
$15.71
per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from
44.0%
to
53.0%
. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from
0.7%
to
2.2%
.
12. Income Taxes
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.
On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances.
The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a
0%
effective tax rate because they reside in countries with a
0%
statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.
Income (loss) before income taxes is composed of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands)
|
Bermuda
|
$
|
(15,513
|
)
|
|
$
|
(17,740
|
)
|
|
$
|
(47,474
|
)
|
|
$
|
(50,680
|
)
|
United States
|
(53,136
|
)
|
|
1,437
|
|
|
(49,967
|
)
|
|
4,231
|
|
Foreign—other
|
(46,044
|
)
|
|
(48,617
|
)
|
|
(240,444
|
)
|
|
(9,863
|
)
|
Income (loss) before income taxes
|
$
|
(114,693
|
)
|
|
$
|
(64,920
|
)
|
|
$
|
(337,885
|
)
|
|
$
|
(56,312
|
)
|
Our effective tax rate for the
three months ended
September 30, 2018
and
2017
is
10%
and
2%
, respectively. For the
nine months ended
,
September 30, 2018
and
2017
, our effective tax rate was
17%
and
79%
, respectively. For the periods ended
September 30, 2018
and 2017 our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.
The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017.
As of
September 30, 2018
, the Company had
no
material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.
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
|
|
Nine Months Ended
|
|
September 30,
|
|
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
$
|
(126,057
|
)
|
|
$
|
(63,405
|
)
|
|
$
|
(279,556
|
)
|
|
$
|
(100,713
|
)
|
Basic income allocable to participating securities(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Basic net loss allocable to common shareholders
|
(126,057
|
)
|
|
(63,405
|
)
|
|
(279,556
|
)
|
|
(100,713
|
)
|
Diluted adjustments to income allocable to participating securities(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted net loss allocable to common shareholders
|
$
|
(126,057
|
)
|
|
$
|
(63,405
|
)
|
|
$
|
(279,556
|
)
|
|
$
|
(100,713
|
)
|
Denominator:
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding:
|
|
|
|
|
|
|
|
Basic
|
404,536
|
|
|
389,058
|
|
|
399,026
|
|
|
388,114
|
|
Restricted stock awards and units(1)(2)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Diluted
|
404,536
|
|
|
389,058
|
|
|
399,026
|
|
|
388,114
|
|
Net loss per share:
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.31
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.26
|
)
|
Diluted
|
$
|
(0.31
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.26
|
)
|
__________________________________
|
|
(1)
|
Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net
loss
per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net
loss
per common share calculation in periods we are in a net loss position.
|
|
|
(2)
|
We excluded outstanding restricted stock awards and units of
13.1 million
and
12.9 million
for the
three
months ended
September 30, 2018
and
2017
, respectively, and
14.5 million
and
12.9 million
for the
nine
months ended
September 30, 2018
and
2017
, respectively, from the computations of diluted net
loss
per share because the effect would have been anti-dilutive
.
|
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 Mauritania and
two
exploration wells in Senegal. Our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately
9,000
square kilometers and
13,500
square kilometers, respectively.
Future minimum rental commitments under our leases at
September 30, 2018
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Year(1)
|
|
Total
|
|
2018(2)
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
(In thousands)
|
Operating leases(3)
|
$
|
37,971
|
|
|
$
|
1,463
|
|
|
$
|
2,775
|
|
|
$
|
4,173
|
|
|
$
|
3,276
|
|
|
$
|
3,326
|
|
|
$
|
22,958
|
|
__________________________________
|
|
(1)
|
Does not include purchase commitments for jointly owned fields and facilities where we are not the operator or discrete purchases of long lead items purchased through normal operations and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.
|
|
|
(2)
|
Represents payments for the period from
October 1, 2018
through
December 31, 2018
.
|
|
|
(3)
|
Primarily relates to corporate office and foreign office leases.
|
Performance Obligations
As of
September 30, 2018
, the Company had secured performance bonds totaling
$214 million
for our supplemental bonding requirements stipulated by the Bureau of Ocean Energy Management ("BOEM") and
$4 million
to another operator related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in its U.S. Gulf of Mexico fields. As of
September 30, 2018
, we had
$0.6 million
of cash collateral against these secured performance bonds which is classified as Other long term assets in our consolidated balance sheet.
15. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
(In thousands)
|
Accrued liabilities:
|
|
|
|
|
|
Exploration, development and production
|
$
|
101,767
|
|
|
$
|
144,717
|
|
Current asset retirement obligations
|
11,161
|
|
|
—
|
|
General and administrative expenses
|
27,902
|
|
|
31,124
|
|
Interest
|
7,430
|
|
|
20,457
|
|
Income taxes
|
7,618
|
|
|
17,423
|
|
Taxes other than income
|
3,457
|
|
|
3,270
|
|
Derivatives
|
21,704
|
|
|
825
|
|
Acquired liabilities
|
80,783
|
|
|
—
|
|
Other
|
488
|
|
|
1,596
|
|
|
$
|
262,310
|
|
|
$
|
219,412
|
|
Gain on sale of assets
During the three and nine months ended
September 30, 2018
, we recognized a
$7.7 million
gain related to the farm-out of Blocks EG-21, S and W to Trident.
Other Income, Net
Other income, net which includes Loss of Production Income ("LOPI") payments in 2017, consisted of
zero
and
$58.7 million
for the
nine
months ended
September 30, 2018
and
2017
, respectively. Our LOPI coverage for the turret bearing issue on the Jubilee FPSO ended in May 2017.
Oil and Gas Production
Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of
zero
and
$17.1 million
for the
nine
months ended
September 30, 2018
and
2017
, respectively.
Facilities Insurance Modifications, Net
Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility which we expect to recover from our insurance policy net of any insurance reimbursements.
Other Expenses, Net
Other expenses, net incurred during the period is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
(In thousands)
|
(Gain) loss on disposal of inventory
|
$
|
(2
|
)
|
|
$
|
(500
|
)
|
|
$
|
(26
|
)
|
|
$
|
47
|
|
Gain on insurance settlements
|
—
|
|
|
—
|
|
|
—
|
|
|
(461
|
)
|
Disputed charges and related costs, net of recoveries
|
(12,682
|
)
|
|
821
|
|
|
(9,721
|
)
|
|
3,260
|
|
Other, net
|
(123
|
)
|
|
(88
|
)
|
|
1,583
|
|
|
157
|
|
Other expenses, net
|
$
|
(12,807
|
)
|
|
$
|
233
|
|
|
$
|
(8,164
|
)
|
|
$
|
3,003
|
|
The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.
In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we recovered from Tullow Ghana Limited disputed charges in the amount of
$12.9 million
in the form of cash payments and offsets against other unrelated joint venture costs, which include amounts previously paid under protest as well as certain costs and fees incurred pursuing the arbitration.