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EX-32.2 - EXHIBIT 32.2 - Kosmos Energy Ltd.kos-09302017xex322.htm
EX-32.1 - EXHIBIT 32.1 - Kosmos Energy Ltd.kos-09302017xex321.htm
EX-31.2 - EXHIBIT 31.2 - Kosmos Energy Ltd.kos-09302017xex312.htm
EX-31.1 - EXHIBIT 31.1 - Kosmos Energy Ltd.kos-09302017xex311.htm
EX-10.2 - EXHIBIT 10.2 - Kosmos Energy Ltd.kos-09302017xex102.htm
EX-10.1 - EXHIBIT 10.1 - Kosmos Energy Ltd.kos-09302017xex101.htm

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
(Mark One)
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended September 30, 2017
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from               to              
 
Commission file number:  001-35167
 
kos2a01.jpg
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
Bermuda
 
98-0686001
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
 
Clarendon House
 
 
2 Church Street
 
 
Hamilton, Bermuda
 
HM 11
(Address of principal executive offices)
 
(Zip Code)
 
Registrant’s telephone number, including area code: +1 441 295 5950
 
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒  No ☐
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒  No ☐
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒
 
Accelerated filer ☐
 
 
 
Non-accelerated filer ☐
 
Smaller reporting company ☐
(Do not check if a smaller reporting company)
 
 
 
 
Emerging growth company ☐
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
 
Outstanding at November 1, 2017
Common Shares, $0.01 par value
 
389,355,364
 



TABLE OF CONTENTS
 
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.
 
 
Page
PART I. FINANCIAL INFORMATION
 
 
 
 
 
 
 
PART II. OTHER INFORMATION
 
 
 

2


KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
 
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
 
“2D seismic data”
Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.
 
 
“3D seismic data”
Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
 
 
“API”
A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
 
 
“ASC”
Financial Accounting Standards Board Accounting Standards Codification.
 
 
“ASU”
Financial Accounting Standards Board Accounting Standards Update.
 
 
“Barrel” or “Bbl”
A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
 
 
“BBbl”
Billion barrels of oil.
 
 
“BBoe”
Billion barrels of oil equivalent.
 
 
“Bcf”
Billion cubic feet.
 
 
“Boe”
Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
 
 
“Boepd”
Barrels of oil equivalent per day.
 
 
“Bopd”
Barrels of oil per day.
 
 
“Bwpd”
Barrels of water per day.
 
 
“Debt cover ratio”
The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.
 
 
“Developed acreage”
The number of acres that are allocated or assignable to productive wells or wells capable of production.
 
 
“Development”
The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.

3


“Dry hole”
A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
 
 
“EBITDAX”
Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity-based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.
 
 
“E&P”
Exploration and production.
 
 
“FASB”
Financial Accounting Standards Board.
 
 
“Farm-in”
An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.
 
 
“Farm-out”
An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of the drilling costs of one or more specific wells and/or other work as a condition of the assignment.
 
 
“Field life cover ratio”
The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana assets, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.
 
 
“FPSO”
Floating production, storage and offloading vessel.
 
 
“Interest cover ratio”
The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
 
 
“Loan life cover ratio”
The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.

4


“MBbl”
Thousand barrels of oil.
 
 
“Mcf”
Thousand cubic feet of natural gas.
 
 
“Mcfpd”
Thousand cubic feet per day of natural gas.
 
 
“MMBbl”
Million barrels of oil.
 
 
“MMBoe”
Million barrels of oil equivalent.
 
 
“MMcf”
Million cubic feet of natural gas.
 
 
“MMcfd”
Million cubic feet per day of natural gas.
 
 
“Natural gas liquid” or “NGL”
Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
 
 
“Petroleum contract”
A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.
 
 
“Petroleum system”
A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.
 
 
“Plan of development” or “PoD”
A written document outlining the steps to be undertaken to develop a field.
 
 
“Productive well”
An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
 
 
“Prospect(s)”
A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.
 
 
“Proved reserves”
Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).
 
 
“Proved developed reserves”
Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
 
 
“Proved undeveloped reserves”
Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.

5


“Reconnaissance contract”
A contract in which the owner of hydrocarbons gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but may not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.
 
 
“Resource Bridge”
Borrowing Base availability attributable to probable reserves and contingent resources from Jubilee Field Future Phases and potentially Mahogany, Teak and Akasa fields.
 
 
“Shelf margin”
The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
 
 
“Stratigraphy”
The study of the composition, relative ages and distribution of layers of sedimentary rock.
 
 
“Stratigraphic trap”
A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
 
 
“Structural trap”
A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and natural gas in the strata.
 
 
“Structural-stratigraphic trap”
A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.
 
 
“Submarine fan”
A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.
 
 
“Three-way fault trap”
A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.
 
 
“Trap”
A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
 
 
“Undeveloped acreage”
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.

6




KOSMOS ENERGY LTD. 
CONSOLIDATED BALANCE SHEETS 
(In thousands, except share data)
 
September 30,
2017
 
December 31,
2016
 
(Unaudited)
 
 
Assets
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
164,162

 
$
194,057

Restricted cash
55,852

 
24,506

Receivables:
 
 
 
Joint interest billings, net
75,373

 
63,249

Oil sales
51,726

 
54,195

Related party
6,446

 

Other
15,756

 
25,893

Inventories
74,275

 
74,380

Prepaid expenses and other
9,359

 
7,209

Derivatives
16,200

 
31,698

Total current assets
469,149

 
475,187

Property and equipment:
 

 
 

Oil and gas properties, net
2,251,977

 
2,700,889

Other property, net
6,424

 
8,003

Property and equipment, net
2,258,401

 
2,708,892

Other assets:
 

 
 

Equity method investment
122,664

 

Restricted cash
15,194

 
54,632

Long-term receivables - joint interest billings
47,525

 
45,663

Deferred financing costs, net of accumulated amortization of $13,267 and $11,213 at September 30, 2017 and December 31, 2016, respectively
3,194

 
5,248

Long-term deferred tax assets
34,546

 
37,827

Derivatives
2,412

 
3,808

Other
17,363

 
10,208

Total assets
$
2,970,448

 
$
3,341,465

Liabilities and shareholders’ equity
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
100,302

 
$
220,627

Accrued liabilities
173,804

 
129,706

Derivatives
9,016

 
19,692

Total current liabilities
283,122

 
370,025

Long-term liabilities:
 

 
 

Long-term debt, net
1,080,352

 
1,321,874

Derivatives
7,256

 
14,123

Asset retirement obligations
68,713

 
63,574

Deferred tax liabilities
511,891

 
482,221

Other long-term liabilities
9,871

 
8,449

Total long-term liabilities
1,678,083

 
1,890,241

Shareholders’ equity:
 

 
 

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2017 and December 31, 2016

 

Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,545,540 and 395,859,061 issued at September 30, 2017 and December 31, 2016, respectively
3,985

 
3,959

Additional paid-in capital
2,004,578

 
1,975,247

Accumulated deficit
(951,123
)
 
(850,410
)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at September 30, 2017 and December 31, 2016, respectively
(48,197
)
 
(47,597
)
Total shareholders’ equity
1,009,243

 
1,081,199

Total liabilities and shareholders’ equity
$
2,970,448

 
$
3,341,465

See accompanying notes.

7


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
(In thousands, except per share data)
 
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2017
 
2016
 
2017
 
2016
Revenues and other income:
 

 
 

 
 

 
 

Oil and gas revenue
$
151,240

 
$
46,628

 
$
391,035

 
$
154,259

Other income, net
2

 
20,001

 
58,697

 
20,179

Total revenues and other income
151,242

 
66,629

 
449,732

 
174,438

Costs and expenses:
 

 
 

 
 

 
 

Oil and gas production
39,187

 
13,574

 
80,677

 
75,647

Facilities insurance modifications, net
(3,906
)
 
5,946

 
(1,334
)
 
5,946

Exploration expenses
36,983

 
66,238

 
162,679

 
126,498

General and administrative
20,029

 
21,914

 
50,555

 
59,672

Depletion and depreciation
73,490

 
17,838

 
180,909

 
66,031

Interest and other financing costs, net
18,478

 
11,066

 
54,729

 
30,268

Derivatives, net
26,864

 
(16,891
)
 
(36,404
)
 
33,752

Other expenses, net
5,037

 
(795
)
 
14,233

 
13,768

Total costs and expenses
216,162

 
118,890

 
506,044

 
411,582

Loss before income taxes
(64,920
)
 
(52,261
)
 
(56,312
)
 
(237,144
)
Income tax expense (benefit)
(1,515
)
 
7,502

 
44,401

 
(10,064
)
Net loss
$
(63,405
)
 
$
(59,763
)
 
$
(100,713
)
 
$
(227,080
)
 
 
 
 
 
 
 
 
Net loss per share:
 

 
 

 
 

 
 

Basic
$
(0.16
)
 
$
(0.15
)
 
$
(0.26
)
 
$
(0.59
)
Diluted
$
(0.16
)
 
$
(0.15
)
 
$
(0.26
)
 
$
(0.59
)
 
 
 
 
 
 
 
 
Weighted average number of shares used to compute net loss per share:
 

 
 

 
 

 
 

Basic
389,058

 
386,026

 
388,114

 
385,130

Diluted
389,058

 
386,026

 
388,114

 
385,130

 
See accompanying notes.

8


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
 
(In thousands)
 
(Unaudited)
 
 
 
 
 
 
Additional
 
 
 
 
 
 
 
Common Shares
 
Paid-in
 
Accumulated
 
Treasury
 
 
 
Shares
 
Amount 
 
Capital
 
Deficit
 
Stock
 
Total
Balance as of December 31, 2016
395,859

 
$
3,959

 
$
1,975,247

 
$
(850,410
)
 
$
(47,597
)
 
$
1,081,199

Equity-based compensation

 

 
30,873

 

 

 
30,873

Restricted stock awards and units
2,686

 
26

 
(26
)
 

 

 

Purchase of treasury stock

 

 
(1,516
)
 

 
(600
)
 
(2,116
)
Net loss

 

 

 
(100,713
)
 

 
(100,713
)
Balance as of September 30, 2017
398,545

 
$
3,985

 
$
2,004,578

 
$
(951,123
)
 
$
(48,197
)
 
$
1,009,243

 
See accompanying notes.

9


KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(In thousands)
 
(Unaudited)
 
 
Nine Months Ended September 30,
 
2017
 
2016
Operating activities
 

 
 

Net loss
$
(100,713
)
 
$
(227,080
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
 
 
 
Depletion, depreciation and amortization
188,563

 
73,684

Deferred income taxes
32,820

 
(16,821
)
Unsuccessful well costs
24,515

 
2,609

Change in fair value of derivatives
(25,924
)
 
37,179

Cash settlements on derivatives, net (including $36.4 million and $146.5 million on commodity hedges during 2017 and 2016)
25,275

 
144,522

Equity-based compensation
29,945

 
30,391

Loss on equity method investment
11,230

 

Other
3,412

 
13,358

Changes in assets and liabilities:
 
 
 
Decrease in receivables
3,232

 
29,833

(Increase) decrease in inventories
58

 
(12,066
)
(Increase) decrease in prepaid expenses and other
(19,327
)
 
15,164

Decrease in accounts payable
(120,325
)
 
(122,142
)
Increase (decrease) in accrued liabilities
41,651

 
(34,254
)
Net cash provided by (used in) operating activities
94,412

 
(65,623
)
Investing activities
 

 
 

Oil and gas assets
(100,712
)
 
(506,256
)
Other property
(1,639
)
 
(1,003
)
Proceeds on sale of assets
222,068

 
210

Net cash provided by (used in) investing activities
119,717

 
(507,049
)
Financing activities
 

 
 

Borrowings under long-term debt

 
450,000

Payments on long-term debt
(250,000
)
 

Purchase of treasury stock
(2,116
)
 
(1,930
)
Net cash provided by (used in) financing activities
(252,116
)
 
448,070

Net decrease in cash, cash equivalents and restricted cash
(37,987
)
 
(124,602
)
Cash, cash equivalents and restricted cash at beginning of period
273,195

 
310,862

Cash, cash equivalents and restricted cash at end of period
$
235,208

 
$
186,260

 
 
 
 
Supplemental cash flow information
 

 
 

Cash paid for:
 

 
 

Interest
$
48,694

 
$
25,540

Income taxes
$
27,199

 
$
6,997

Non-cash activity:
 

 
 

Conversion of joint interest billings receivable to long-term note receivable
$

 
$
8,124

Contribution to equity method investment
$
133,893

 
$

 
See accompanying notes.

10


KOSMOS ENERGY LTD.
 
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.
 

11


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

12


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 agreement, 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

13


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:
 
 
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.
 

14


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

15


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.
 

16


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:
 
 
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.


17


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

18


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.

19


 
 
 
 
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.


20


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

21


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

 

22


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

23


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.

24


 
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.


25


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.
 



26


Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2016, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
 
Overview
 
We are 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.
 
Recent Developments
 
Corporate
 
In August 2017,  we announced that our entire issued and outstanding share capital has been admitted to the standard listing segment of the Official List of the Financial Conduct Authority and to trading on the London Stock Exchange’s main market for listed securities under the ticker “KOS”. The listing is expected to broaden Kosmos’ international investor base and provide access to an additional pool of capital.

The availability period for the Facility, as amended in March 2014, expires on March 31, 2018 and the letter of credit sublimit expires on the final maturity date of March 31, 2021. The first required payment could be as early as September 30, 2019, subject to the level of outstanding borrowings and the borrowing base constraints. We are currently in discussions with our lenders to refinance the Facility during the first quarter of 2018 to extend the availability period as well as include reserves for Equatorial Guinea.

Ghana
 
Jubilee
 
Kosmos and its partners have determined the preferred long-term solution to the turret bearing issue is to convert the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring at its current heading was completed in February 2017. This allowed the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the cost and complexity of the current operation. The next phase of the remediation work involves lifting and locking the main bearing. The partners and the government of Ghana have agreed on the need to lift and lock the turret bearing and a shutdown is being planned in early 2018 to execute this workscope. Planning for the rotation of the vessel and the installation of a deepwater CALM buoy is ongoing, subject to final decisions and government approval. Total shutdown duration, for lifting and locking, rotation and offloading system installation, is not expected to exceed 12 weeks as previously forecast by the Operator.
 
The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Our LOPI coverage for this incident ended in May 2017 and final claim amounts have been approved with remaining cash proceeds received in August 2017.
 
The Greater Jubilee Full Field Development Plan (“GJFFDP”) was resubmitted to the government of Ghana in September 2017 and subsequently approved in October 2017. This plan, which is expected to increase proved reserves and extend the field production profile, has been optimized to reduce overall capital expenditures to reflect the current oil price market. In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners, which became effective upon approval of the GJFFDP, to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure, thus reducing their development cost. Upon approval of the GJFFDP by the Ministry of Energy in October 2017, operatorship for

27


the Mahogany and Teak discoveries transferred to Tullow.  The WCTP Block partners are in the process of taking the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow.

Tweneboa, Enyenra and Ntomme (“TEN”)
 
In September 2017, the Special Chamber of the International Tribunal of the Sea (ITLOS) issued its final decision in the maritime boundary dispute between the Governments of Ghana and Cote d'Ivoire. The maritime boundary delimited by the Special Chamber's decision has no impact on TEN production or reserves or otherwise on the company's interests in Ghana. Production from TEN in the nine months ended September 30, 2017 averaged approximately 52,000 bopd and is on track to achieve or exceed the operator’s 2017 guidance of 50,000 bopd. After resuming drilling, the TEN fields are expected to increase production towards FPSO capacity of 80,000 bopd as development progresses.
 
Greater Tortue Discovery

In August 2017, we announced the successful completion of the drill stem test ("DST") of the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 million cubic feet per day (MMcfd) during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST will be used to further optimize field development and to refine process design parameters critical to the front end engineering and design ("FEED") process.

Senegal (Kosmos BP Senegal Limited (“KBSL”) – equity method investment)
 
In October 2017, 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 which was approved, resulting in KBSL becoming a wholly-owned subsidiary of Kosmos. 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 and therefore, KBSL will no longer be accounted for under the equity method of accounting.
 
Mauritania
 
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.

Drilling of the Hippocampe-1 exploration well on the C8 block was completed in October 2017. Designed to test Lower Cenomanian and Albian reservoirs, the well was drilled to a total depth of approximately 5,500 meters. Well-developed reservoirs were encountered in both exploration targets, but these proved to be water bearing. The well has been plugged and abandoned. Total well and other related costs of $21.0 million incurred from inception through September 30, 2017 are included in exploration expenses in the accompanying consolidated statement of operations. We estimate an additional $10.6 million of related well costs will be incurred in the fourth quarter, and will be expensed when incurred.
 
Sao Tome and Principe

In August 2017, we completed a 3D seismic survey of approximately 15,800 square kilometers over Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe.


28


Equatorial Guinea

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 agreement, 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 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.



29


Results of Operations
 
All of our results, as presented in the table below, represent operations in Ghana. Certain operating results and statistics for the three and nine months ended September 30, 2017 and 2016 are included in the following table:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
 
(In thousands, except per barrel data)
Sales volumes (MBbl):
 
 
 
 
 
 
 
Jubilee
1,943

 
947

 
5,838

 
3,791

TEN
996

 

 
1,992

 

Total sales volumes
2,939

 
947

 
7,830

 
3,791

 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
Oil and gas sales
$
151,240

 
$
46,628

 
$
391,035

 
$
154,259

Average sales price per Boe
51.46

 
49.24

 
49.94

 
40.69

 
 
 
 
 
 
 
 
Costs:
 
 
 
 
 
 
 
Oil and gas production, excluding workovers
$
38,118

 
$
13,525

 
$
79,110

 
$
75,587

Oil and gas production, workovers
1,069

 
49

 
1,567

 
60

Total oil and gas production costs
$
39,187

 
$
13,574

 
$
80,677