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