Document
Table of Contents

 

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, 2018
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
 
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12530575&doc=26
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, 2018
Common Shares, $0.01 par value
 
433,617,302
 


Table of Contents

TABLE OF CONTENTS
 
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned 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

Table of Contents

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.
 
 
“Dry hole" or "Unsuccessful well”
A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.

3

Table of Contents

 
 
“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. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
 
 
“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/or for taking on a portion of future costs 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 future costs 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 and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
 
 
"FPS"
Floating production system.
 
 
“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 Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
 
 
"LNG"
Liquefied natural gas.
 
 
“MBbl”
Thousand barrels of oil.
 
 
"MBoe"
Thousand barrels of oil equivalent.
 
 
“Mcf”
Thousand cubic feet of natural gas.
 
 

4

Table of Contents

“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 planned 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.
 
 
“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.

5

Table of Contents

 
 
“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

Table of Contents



KOSMOS ENERGY LTD. 
CONSOLIDATED BALANCE SHEETS 
(In thousands, except share data)
 
September 30,
2018
 
December 31,
2017
 
(Unaudited)
 
 
Assets
 

 
 

Current assets:
 

 
 

Cash and cash equivalents
$
192,646

 
$
233,412

Restricted cash
5,376

 
56,380

Receivables:
 
 
 
Joint interest billings, net
84,209

 
134,565

Oil sales
131,546

 

Related party
20,834

 
780

Other
15,750

 
25,616

Inventories
90,003

 
71,861

Prepaid expenses and other
58,949

 
9,306

Derivatives
41,466

 
1,682

Total current assets
640,779

 
533,602

Property and equipment:
 

 
 

Oil and gas properties, net
3,498,855

 
2,310,973

Other property, net
10,682

 
6,855

Property and equipment, net
3,509,537

 
2,317,828

Other assets:
 

 
 

Equity method investment
88,652

 
236,514

Restricted cash
9,473

 
15,194

Long-term receivables - joint interest billings
21,861

 
34,941

Deferred financing costs, net of accumulated amortization of $11,411 and $13,951 at September 30, 2018 and December 31, 2017, respectively
9,582

 
2,510

Deferred tax assets
31,890

 
22,517

Derivatives
14,486

 
39

Other
3,204

 
29,458

Total assets
$
4,329,464

 
$
3,192,603

Liabilities and shareholders’ equity
 

 
 

Current liabilities:
 

 
 

Accounts payable
$
153,922

 
$
141,787

Accrued liabilities
262,310

 
219,412

Derivatives
212,217

 
67,531

Total current liabilities
628,449

 
428,730

Long-term liabilities:
 

 
 

Long-term debt, net
2,094,534

 
1,282,797

Derivatives
110,245

 
30,209

Asset retirement obligations
150,200

 
66,595

Deferred tax liabilities
401,826

 
476,548

Other long-term liabilities
9,277

 
10,612

Total long-term liabilities
2,766,082

 
1,866,761

Shareholders’ equity:
 

 
 

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2018 and December 31, 2017

 

Common shares, $0.01 par value; 2,000,000,000 authorized shares; 442,856,360 and 398,599,457 issued at September 30, 2018 and December 31, 2017, respectively
4,429

 
3,986

Additional paid-in capital
2,331,969

 
2,014,525

Accumulated deficit
(1,352,758
)
 
(1,073,202
)
Treasury stock, at cost, 9,263,269 and 9,188,819 shares at September 30, 2018 and December 31, 2017, respectively
(48,707
)
 
(48,197
)
Total shareholders’ equity
934,933

 
897,112

Total liabilities and shareholders’ equity
$
4,329,464

 
$
3,192,603

See accompanying notes.

7

Table of Contents

KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
(In thousands, except per share data)
 
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
 
2017
 
2018
 
2017
Revenues and other income:
 

 
 

 
 

 
 

Oil and gas revenue
$
242,833

 
$
151,240

 
$
585,220

 
$
391,035

Gain on sale of assets
7,666

 

 
7,666

 

Other income, net
(280
)
 
2

 
(17
)
 
58,697

Total revenues and other income
250,219

 
151,242

 
592,869

 
449,732

Costs and expenses:
 

 
 

 
 

 
 

Oil and gas production
55,078

 
39,187

 
151,661

 
80,677

Facilities insurance modifications, net
12,334

 
(3,906
)
 
21,812

 
(1,334
)
Exploration expenses
148,238

 
36,983

 
246,912

 
162,679

General and administrative
25,963

 
20,029

 
65,343

 
50,555

Depletion and depreciation
80,041

 
73,490

 
208,607

 
180,909

Interest and other financing costs, net
23,549

 
18,478

 
68,113

 
54,729

Derivatives, net
57,357

 
26,864

 
236,107

 
(36,404
)
(Gain) loss on equity method investments, net
(24,841
)
 
4,804

 
(59,637
)
 
11,230

Other expenses, net
(12,807
)
 
233

 
(8,164
)
 
3,003

Total costs and expenses
364,912

 
216,162

 
930,754

 
506,044

Loss before income taxes
(114,693
)
 
(64,920
)
 
(337,885
)
 
(56,312
)
Income tax expense (benefit)
11,364

 
(1,515
)
 
(58,329
)
 
44,401

Net loss
$
(126,057
)
 
$
(63,405
)
 
$
(279,556
)
 
$
(100,713
)
 
 
 
 
 
 
 
 
Net loss per share:
 

 
 

 
 

 
 

Basic
$
(0.31
)
 
$
(0.16
)
 
$
(0.70
)
 
$
(0.26
)
Diluted
$
(0.31
)
 
$
(0.16
)
 
$
(0.70
)
 
$
(0.26
)
 
 
 
 
 
 
 
 
Weighted average number of shares used to compute net loss per share:
 

 
 

 
 

 
 

Basic
404,536

 
389,058

 
399,026

 
388,114

Diluted
404,536

 
389,058

 
399,026

 
388,114

 
See accompanying notes.

8

Table of Contents

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, 2017
398,599

 
$
3,986

 
$
2,014,525

 
$
(1,073,202
)
 
$
(48,197
)
 
$
897,112

Acquisition of oil and gas properties
34,994

 
350

 
307,594

 

 

 
307,944

Equity-based compensation

 

 
27,128

 

 

 
27,128

Restricted stock awards and units
9,263

 
93

 
(93
)
 

 

 

Purchase of treasury stock / tax withholdings

 

 
(17,185
)
 

 
(510
)
 
(17,695
)
Net loss

 

 

 
(279,556
)
 

 
(279,556
)
Balance as of September 30, 2018
442,856

 
$
4,429

 
$
2,331,969

 
$
(1,352,758
)
 
$
(48,707
)
 
$
934,933

 
See accompanying notes.

9

Table of Contents

KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(In thousands)
 
(Unaudited)
 
Nine Months Ended September 30,
 
2018
 
2017
Operating activities
 

 
 

Net loss
$
(279,556
)
 
$
(100,713
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depletion, depreciation and amortization
215,676

 
188,563

Deferred income taxes
(84,095
)
 
32,820

Unsuccessful well costs
114,948

 
24,515

Change in fair value of derivatives
232,057

 
(25,924
)
Cash settlements on derivatives, net (including $(107.3) million and $36.4 million on commodity hedges during 2018 and 2017)
(102,705
)
 
25,275

Equity-based compensation
25,975

 
29,945

Gain on sale of assets
(7,666
)
 

Loss on extinguishment of debt
4,324

 

Distributions in excess of equity in earnings
5,235

 
11,230

Other
1,237

 
3,412

Changes in assets and liabilities:
 
 
 
Decrease in receivables
59,318

 
3,232

Decrease in inventories
3,978

 
58

Increase in prepaid expenses and other
(9,732
)
 
(19,327
)
Decrease in accounts payable
(15,178
)
 
(120,325
)
Increase (decrease) in accrued liabilities
(73,569
)
 
41,651

Net cash provided by operating activities
90,247

 
94,412

Investing activities
 

 
 

Oil and gas assets
(149,305
)
 
(100,712
)
Other property
(3,560
)
 
(1,639
)
Acquisition of oil and gas properties, net of cash acquired
(961,764
)
 

Return of investment from KTIPI
142,628

 

Proceeds on sale of assets
13,703

 
222,068

Net cash provided by (used in) investing activities
(958,298
)
 
119,717

Financing activities
 

 
 

Borrowings under long-term debt
1,000,000

 

Payments on long-term debt
(175,000
)
 
(250,000
)
Purchase of treasury stock / tax withholdings
(17,695
)
 
(2,116
)
Deferred financing costs
(36,745
)
 

Net cash provided by (used in) financing activities
770,560

 
(252,116
)
Net decrease in cash, cash equivalents and restricted cash
(97,491
)
 
(37,987
)
Cash, cash equivalents and restricted cash at beginning of period
304,986

 
273,195

Cash, cash equivalents and restricted cash at end of period
$
207,495

 
$
235,208

 
 
 
 
Supplemental cash flow information
 

 
 

Cash paid for:
 

 
 

Interest
$
86,981

 
$
48,694

Income taxes
$
25,601

 
$
27,199

Non-cash activity:
 

 
 

Contribution to equity method investment
$

 
$
133,893

Common stock issued for acquisition of oil and gas properties
$
307,944

 
$

 See accompanying notes.

10

Table of Contents

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 corporate management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.
 
Kosmos is a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margin. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable exploration program balanced between proven basin short-cycle exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire, Namibia and Sao Tome and Principe). Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.
 
We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to production located offshore Ghana and U.S. Gulf of Mexico. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea.
 
2. Accounting Policies
 
General
 
The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of September 30, 2018, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2018, the consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and the consolidated cash flows for the nine months ended September 30, 2018 and 2017. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2017, included in our annual report on Form 10-K.
 
Reclassifications
 
Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net loss, current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. 

Cash, Cash Equivalents and Restricted Cash 

 
September 30,
2018
 
December 31,
2017
 
(In thousands)
Cash and cash equivalents
$
192,646

 
$
233,412

Restricted cash - current
5,376

 
56,380

Restricted cash - long-term
9,473

 
15,194

Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows
$
207,495

 
$
304,986

 

11

Table of Contents

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
 
In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of September 30, 2018 and December 31, 2017, we had $5.4 million and $31.6 million, respectively, of current restricted cash and $9.2 million and $15.2 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. As of September 30, 2018, we also had $0.2 million in other long-term restricted cash.

In addition, prior to our reserves based debt facility (the "Facility") being amended and restated in February 2018, we were required to maintain a restricted cash balance that was sufficient to meet the payment of interest and fees for the next six-month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver, or the Facility, whichever was greater. As of December 31, 2017, we had $24.8 million in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios.
 
Inventories
 
Inventories consisted of $86.8 million (including $22.1 million acquired through the Deep Gulf Energy (together with its subsidiaries "DGE") acquisition) and $63.5 million of materials and supplies and $3.2 million and $8.4 million of hydrocarbons as of September 30, 2018 and December 31, 2017, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.
 
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Revenue Recognition

We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of September 30, 2018 and December 31, 2017, we had no oil and gas imbalances recorded in our consolidated financial statements.

Our oil and gas revenues are recognized when production has been sold to a purchaser at a fixed or determinable price, title has transferred and collectability is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Oil and gas revenue is composed of the following:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Revenue from contracts with customers - Ghana
$
215,581

 
$
157,461

 
$
557,459

 
$
401,816

Revenue from contracts with customers - U.S. Gulf of Mexico
24,177

 

 
24,177

 

Provisional oil sales contracts
3,075

 
(6,221
)
 
3,584

 
(10,781
)
Oil and gas revenue
$
242,833

 
$
151,240

 
585,220

 
391,035



12

Table of Contents

Recent Accounting Standards

Recently Adopted

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.

In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued.

Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements.

3. Acquisitions and Divestitures
 
2018 Transactions

In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a 35% participating interest in the blocks and the operator, BP, holds a 50% participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a 15% carried interest in the blocks through exploration. The petroleum contracts cover approximately 13,600 square kilometers, with a first exploration period of four years from the effective date (March 2018). The exploration periods can be extended an additional four years at our election subject to fulfilling specific work obligations. The first exploration period work programs include a 13,500 square kilometer 3D seismic acquisition requirement across the two blocks.

In June 2018, we completed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contract covers approximately 3,500 square kilometers, with a first exploration period of three years from the effective date (March 2018) which can be extended up to four additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a 3,000 square kilometer 3D seismic acquisition requirement.

In September 2018, we completed the acquisition of DGE, a deepwater company operating in the U.S. Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of $1.275 billion, comprised of $952.6 million in cash and $307.9 million in Kosmos common stock and $14.9 million of transaction related costs. We funded the cash portion of the purchase price using cash on hand and drawings under our existing credit facilities. We also received $200.0 million of additional firm commitments under the Facility, which provides further liquidity to the Company. The DGE acquisition was accounted for under the asset acquisition method and the purchase price allocation is shown below. The purchase price allocation was based on the estimated relative fair value of identifiable assets acquired and liabilities assumed.
 

13

Table of Contents

The estimated fair value measurements of oil and gas assets acquired and asset retirement obligations liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation. Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market-based weighted average cost of capital rate.

 
 
Purchase Price Allocation
(in thousands)
Fair value of assets acquired:
 
 
Proved oil and gas properties
 
$
1,045,509

Unproved oil and gas properties
 
300,420

Accounts receivable and other
 
179,332

 
 
 
Total assets acquired
 
$
1,525,261

 
 
 
Fair value of liabilities assumed:
 
 
Accrued liabilities and other
 
$
123,034

Asset retirement obligations
 
86,580

Derivative liabilities
 
40,265

 
 
 
Total liabilities assumed
 
$
249,879

 
 
 
 
 
 
Cash consideration paid
 
$
952,586

Fair value of common stock(1)
 
307,944

Transaction related costs
 
14,852

Total purchase price
 
$
1,275,382

(1)
Based on 34,993,585 common shares issued at a price of $8.80 per share, which is the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.

As a result of the DGE acquisition, we have included $24.2 million of revenues and $4.4 million of direct operating expenses in our consolidated statements of operations for the period from September 14, 2018 to September 30, 2018.

In October 2018, Kosmos entered into a strategic exploration alliance with Shell Exploration Company B.V. (“Shell”) to jointly explore in Southern West Africa. Initially the alliance will focus on Namibia where Kosmos has completed a farm-in to Shell's acreage in PEL 39.

2017 Transactions

In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which held an 85% paying interest (80.75% revenue interest) in the Ceiba Field and Okume Complex assets located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own 50% of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was $650 million effective as of January 1, 2017. After purchase price adjustments, Kosmos paid net cash consideration of approximately $231 million at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment.


14

Table of Contents

In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. In August 2018, we closed a farm-out agreement with Trident, whereby they acquired a 40% participating interest in blocks EG-21, S, and W, resulting in a $7.7 million gain. After giving effect to the farm-out agreement, we hold a 40% participating interest and are the operator in all three blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the effective date (March 2018). The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks.

In December 2017, as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a 45% participating interest and are the operator in all five blocks. BP has a 45% participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a 10% carried interest. The petroleum contracts cover approximately 17,000 square kilometers, with a first exploration period of three years. The first exploration period work program includes a 12,000 square kilometer 3D seismic acquisition across the five blocks.
 
4. Joint Interest Billings and Related Party Receivables
 
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.
 
In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of September 30, 2018 and December 31, 2017, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $14.0 million and $15.2 million, respectively, and the long-term portions were $21.9 million and $31.6 million, respectively.

The Company's related party receivables consists primarily of receivables from Trident who owns a 50% interest in KTIPI. As of September 30, 2018 the balance due from Trident consists of $13.7 million related to the farm-out of Blocks EG-21, S, and W, and $7.1 million related to joint interest billings for the exploration blocks and Kosmos' support of KTIPI operations.


15

Table of Contents

5. Property and Equipment
 
Property and equipment is stated at cost and consisted of the following:
 
 
September 30,
2018
 
December 31,
2017
 
(In thousands)
Oil and gas properties:
 

 
 

Proved properties
$
2,749,163

 
$
1,653,616

Unproved properties
733,274

 
465,109

Support equipment and facilities
1,450,907

 
1,427,054

Total oil and gas properties
4,933,344

 
3,545,779

Accumulated depletion
(1,434,489
)
 
(1,234,806
)
Oil and gas properties, net
3,498,855


2,310,973

 
 
 
 
Other property
46,513

 
39,405

Accumulated depreciation
(35,831
)
 
(32,550
)
Other property, net
10,682

 
6,855

 
 
 
 
Property and equipment, net
$
3,509,537

 
$
2,317,828

 
We recorded depletion expense of $76.8 million and $70.9 million for the three months ended September 30, 2018 and 2017, respectively, and $199.7 million and $173.3 million for the nine months ended September 30, 2018 and 2017, respectively.
 

16

Table of Contents

6. Suspended Well Costs
 
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2018. The table excludes $48.0 million in costs that were capitalized and subsequently expensed during the same period.
 
 
September 30,
2018
 
(In thousands)
Beginning balance 
$
410,113

Additions associated with the acquisition of DGE
26,426

Additions to capitalized exploratory well costs pending the determination of proved reserves 
7,658

Reclassification due to determination of proved reserves 

Capitalized exploratory well costs charged to expense 
(52,498
)
Ending balance 
$
391,699


The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
 
 
September 30, 2018
 
December 31, 2017
 
(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less
$
26,426

 
$
67,159

Exploratory well costs capitalized for a period of one to two years
296,866

 
291,252

Exploratory well costs capitalized for a period of three years
68,407

 
51,702

Ending balance
$
391,699

 
$
410,113

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
3

 
5

 
As of September 30, 2018, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Greater Tortue discovery, which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal.
 
Akasa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Akasa discovery. As a result, we wrote off $39.8 million of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Akasa discovery area, and the acreage is not currently being relinquished.
 
Wawa Discovery — As a result of discussions during our quarterly Ghana partner meetings in October 2018, we determined sufficient progress has not been made to continue to capitalize the costs associated with the Wawa discovery. As a result, we wrote off $17.9 million of previously capitalized costs to exploration expense during the third quarter of 2018. We retain our rights associated with the Wawa discovery area, and the acreage is not currently being relinquished.
 
Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania, which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design ("FEED") process. The partnership has made significant progress towards a final investment decision for phase one. Led by BP, the FEED work for phase one is substantially complete. The Unit Development Plan has been submitted to both governments, and we have reached agreement with the Governments of Mauritania and Senegal on the non-PSA fiscal terms for this cross border project.
 

17

Table of Contents

BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made.
Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. An appraisal well is scheduled in 2019 to further evaluate the discovery. Following additional evaluation, a decision regarding commerciality is expected to be made.

Nearly Headless Nick Discovery — In September 2018, the Nearly Headless Nick exploration well (22.0% WI) was successfully drilled to a total depth of approximately 5,800 meters (19,050 feet) and encountered approximately 26 meters (85 feet) of net pay in the Middle Miocene objective within the Mississippi Canyon 387 block offshore U.S. Gulf of Mexico. Nearly Headless Nick will be developed as a subsea tie back, which is expected to be brought online through the Delta House facility by 2020.

7. Equity Method Investments
Kosmos BP Senegal Limited ("KBSL")

As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture entity in which we owned a 50.01% interest which was accounted for under the equity method of accounting.

In October 2017, KBSL transferred a 30% participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a 30% participating interest in the Senegal Blocks.

During the three and nine months ended September 30, 2017 we recognized $4.8 million and $11.2 million, respectively, related to our share of losses in KBSL. Our initial contribution to KBSL was $133.9 million, which was recorded at our carrying costs.


18

Table of Contents

Equatorial Guinea

As part of our acquisition of KTIPI, a corporate joint venture entity in which we own a 50% interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a 100% basis.


 
September 30,
 
December 31,
 
2018
 
2017
 
(In thousands)
Assets
 
 
 

Total current assets
$
158,140

 
$
179,070

Property and equipment, net
291,960

 
345,611

Other assets
487

 
567

Total assets
$
450,587

 
$
525,248

 
 
 
 
Liabilities and shareholders' equity
 
 
 
Total current liabilities
$
196,338

 
$
106,769

Total long-term liabilities
541,881

 
565,591

Shareholders' equity:
 
 
 
Total shareholders' equity
(287,632
)
 
(147,112
)
Total liabilities and shareholders' equity
$
450,587

 
$
525,248


 
Three Months Ended September 30, 2018
 
Nine Months Ended September 30, 2018
 
(In thousands)
Revenues and other income:
 

 
 
Oil and gas revenue
$
215,408

 
$
600,158

Other income
(72
)
 
44

Total revenues and other income
215,336

 
600,202

 
 
 
 
Costs and expenses:
 
 
 
Oil and gas production
40,334

 
115,366

Depletion and depreciation
33,044

 
108,996

Other expenses, net
(58
)
 
(211
)
Total costs and expenses
73,320

 
224,151

 
 
 
 
Income before income taxes
142,016

 
376,051

Income tax expense
50,796

 
134,047

Net income
$
91,220

 
$
242,004

 
 
 
 
Kosmos' share of net income
$
45,610

 
$
121,002

Basis difference amortization(1)
20,769

 
61,365

Equity in earnings - KTIPI
$
24,841

 
$
59,637

______________________________________
(1)
The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.

19

Table of Contents


When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of September 30, 2018, we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such, no impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the nine months ended September 30, 2018, we received $207.5 million of cash dividends from KTIPI, and we received an additional $32.5 million of cash dividends in October 2018.

8. Debt
 
 
September 30,
2018
 
December 31,
2017
 
(In thousands)
Outstanding debt principal balances:
 

 
 

Facility
$
1,325,000

 
$
800,000

Corporate Revolver
300,000

 

Senior Notes
525,000

 
525,000

Total
2,150,000

 
1,325,000

Unamortized deferred financing costs and discounts(1)
(55,466
)
 
(42,203
)
Long-term debt, net
$
2,094,534

 
$
1,282,797

__________________________________
(1)
Includes $40.3 million and $23.6 million of unamortized deferred financing costs related to the Facility and $15.2 million and $18.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2018 and December 31, 2017, respectively.

Facility
 
In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with two existing financial institutions, which obligate the two financial institutions to provide the Company, upon the Company's election, with an additional commitment of $200 million in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and $4.1 million of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of September 30, 2018, we have $40.3 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility. As of September 30, 2018, borrowings under the Facility totaled $1,325.0 million and the undrawn availability under the Facility was $375.0 million, which includes the $200 million in additional commitments referenced above.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of September 30, 2018, we had no letters of credit issued under the Facility.
 
We were in compliance with the financial covenants contained in the Facility as of September 30, 2018 (the most recent assessment date). The Facility contains customary cross default provisions.
 
Corporate Revolver
 
In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This results in lower commitment fees on the undrawn portion of the total commitments, which is 30%

20

Table of Contents

per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs.
 
As of September 30, 2018, borrowings under the Corporate Revolver totaled $300 million and the undrawn availability under the Corporate Revolver was $100 million. As of September 30, 2018, we have $9.6 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2018 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
 
Revolving Letter of Credit Facility
 
We have a revolving letter of credit facility agreement (“LC Facility”), which matures in July 2019. In July 2018, the LC Facility size was voluntarily reduced to $40.0 million based on the expiration of several large outstanding letters of credit. As of September 30, 2018, there were eight outstanding letters of credit totaling $16.9 million under the LC Facility. The LC Facility contains customary cross default provisions.
 
7.875% Senior Secured Notes due 2021
 
During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
 
During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
 
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee both the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.
 
At September 30, 2018, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
 
 
Payments Due by Year
 
Total
 
2018(2)
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
(In thousands)
Principal debt repayments(1)
$
2,150,000


$


$


$


$
685,600


$
589,100


$
875,300

__________________________________
(1)
Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2018, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)
Represents payments for the period October 1, 2018 through December 31, 2018.


21

Table of Contents

Interest and other financing costs, net
 
Interest and other financing costs, net incurred during the periods is comprised of the following:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Interest expense
$
27,317

 
$
22,961

 
$
77,121

 
$
68,934

Amortization—deferred financing costs
2,346

 
2,551

 
7,069

 
7,653

Loss on extinguishment of debt
268

 

 
4,324

 

Capitalized interest
(7,097
)
 
(8,563
)
 
(21,209
)
 
(25,498
)
Deferred interest
(194
)
 
662

 
(1,284
)
 
1,610

Interest income
(788
)
 
(745
)
 
(2,579
)
 
(2,485
)
Other, net
1,697

 
1,612

 
4,671

 
4,515

Interest and other financing costs, net
$
23,549

 
$
18,478

 
$
68,113

 
$
54,729


9. Derivative Financial Instruments
 
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
 
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures.
 
Oil Derivative Contracts
 
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of September 30, 2018. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.
 

 

 
 
 

Weighted Average Price per Bbl
 

 

 
 
 

Net Deferred

 

 

 

 

 
 

 

 
 
 

Premium

 

 

 

 

 
Term

Type of Contract

Index
 
MBbl

Payable/(Receivable)

Swap

Sold Put

Floor

Ceiling

Call
2018:
 
 

 
 
 


 


 


 


 


 


 

Oct — Dec

Swap with puts

Dated Brent
 
1,500


$


$
56.75


$
43.33


$


$


$

Oct — Dec
 
Three-way collars

Dated Brent
 
733


0.74




41.57


56.57


65.91



Oct — Dec
 
Four-way collars

Dated Brent
 
751


1.06




40.00


50.00


61.33


70.00

Oct — Dec
 
Sold calls(1)

Dated Brent
 
503










65.00



Oct — Dec

Purchased Calls

Dated Brent
 
500


1.88










70.00

Oct — Dec

Purchased Puts

NYMEX WTI

141


2.70






53.00





Oct — Dec

Collars

NYMEX WTI

35








62.29


66.35



Oct — Dec

Swaps

NYMEX WTI

698




54.69









2019:
 
 

 
 
 


 


 


 


 


 


 

Jan — Dec
 
Three-way collars

Dated Brent
 
10,500


$
1.17


$


$
43.81


$
53.33


$
73.58


$

Jan — Dec
 
Sold calls(1)

Dated Brent
 
913










80.00



Jan — Dec

Swaps

NYMEX WTI

1,747




52.31









Jan — Jun

Collars

NYMEX WTI

339








57.77


63.70



Jan — Dec

Collars

Argus LLS

1,000








60.00


88.75



2020:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jan — Dec

Three-way collars

Dated Brent

2,000


$


$


$
50.00


$
60.00


$
90.54


$

Jan — Dec
 
Sold calls(1)
 
Dated Brent
 
8,000

 
$

 
$

 
$

 
$

 
$
80.00

 
$

__________________________________
(1)
Represents call option contracts sold to counterparties to enhance other derivative positions.
 
Interest Rate Derivative Contracts
 
The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of September 30, 2018:
 
 
 
 
 
 
 
Weighted Average
Term
 
Type of Contract
 
Floating Rate
 
Notional
 
Swap
 
Sold Call
 
 
 
 
 
 
(In thousands)
 
 
 
 
October 2018 — December 2018
 
Capped swap
 
1-month LIBOR
 
$
200,000

 
1.23
%
 
3.00
%

22

Table of Contents


The following tables disclose the Company’s derivative instruments as of September 30, 2018 and December 31, 2017 and gain/(loss) from derivatives during the three months ended September 30, 2018 and 2017, respectively:
 
 
 
 
 
Estimated Fair Value
 
 
 
 
Asset (Liability)
Type of Contract 
 
Balance Sheet Location
 
September 30,
2018
 
December 31,
2017
 
 
 
 
(In thousands)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
Derivative assets:
 
 
 
 
 
 
Commodity(1)
 
Derivatives assets—current
 
$
40,953

 
$
665

Interest rate
 
Derivatives assets—current
 
513

 
1,017

Commodity(2)
 
Derivatives assets—long-term
 
14,486

 
39

Derivative liabilities:
 
 
 
 
 
 
Commodity(3)
 
Derivatives liabilities—current
 
(212,217
)
 
(67,531
)
Commodity(4)
 
Derivatives liabilities—long-term
 
(110,245
)
 
(30,209
)
Total derivatives not designated as hedging instruments
 
 
 
$
(266,510
)
 
$
(96,019
)
__________________________________
(1)
Includes net deferred premiums payable of $4.7 million and net deferred premiums receivable of $0.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017, respectively.
(2)
Includes net deferred premiums payable of $2.4 million and net deferred premiums receivable of $0.1 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017, respectively.
(3)
Includes net deferred premiums payable of $6.0 million and $5.6 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017, respectively.
(4)
Includes net deferred premiums payable of $1.6 million and $4.8 million related to commodity derivative contracts as of September 30, 2018 and December 31, 2017, respectively.
 
 
 
 
Amount of Gain/(Loss)
 
Amount of Gain/(Loss)
 
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
 
September 30,
 
September 30,
Type of Contract
 
Location of Gain/(Loss)
 
2018
 
2017
 
2018
 
2017
 
 
 
 
(In thousands)
Derivatives not designated as hedging instruments:
 
 
 
 

 
 

 
 

 
 

Commodity(1)
 
Oil and gas revenue
 
$
3,075

 
$
(6,221
)
 
$
3,584

 
$
(10,781
)
Commodity
 
Derivatives, net
 
(57,357
)
 
(26,864
)
 
(236,107
)
 
36,404

Interest rate
 
Interest expense
 
15

 
64

 
466

 
301

Total derivatives not designated as hedging instruments
 
 
 
$
(54,267
)
 
$
(33,021
)
 
$
(232,057
)
 
$
25,924

__________________________________
(1)
Amounts represent the change in fair value of our provisional oil sales contracts.
Offsetting of Derivative Assets and Derivative Liabilities
 
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2018 and December 31, 2017, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.


23

Table of Contents

10. Fair Value Measurements
 
In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
 
Level 1 — quoted prices for identical assets or liabilities in active markets.
Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017, for each fair value hierarchy level:
 
 
Fair Value Measurements Using:
 
Quoted Prices in
 
 
 
 
 
 
 
Active Markets for
 
Significant Other
 
Significant
 
 
 
Identical Assets
 
Observable Inputs
 
Unobservable Inputs
 
 
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
Total
 
(In thousands)
September 30, 2018
 

 
 

 
 

 
 

Assets:
 

 
 

 
 

 
 

Commodity derivatives
$

 
$
55,439

 
$

 
$
55,439

Interest rate derivatives

 
513

 

 
513

Liabilities:
 
 
 
 
 
 
 
Commodity derivatives

 
(322,462
)
 

 
(322,462
)
Total
$

 
$
(266,510
)
 
$

 
$
(266,510
)
December 31, 2017
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$

 
$
704

 
$

 
$
704

Interest rate derivatives

 
1,017

 

 
1,017

Liabilities:
 
 
 
 
 
 
 
Commodity derivatives

 
(97,740
)
 

 
(97,740
)
Total
$

 
$
(96,019
)
 
$

 
$
(96,019
)
 
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
 

24

Table of Contents

Commodity Derivatives
 
Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
 
Provisional Oil Sales
 
The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
 
Interest Rate Derivatives
 
Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.
 
Debt
 
The following table presents the carrying values and fair values at September 30, 2018 and December 31, 2017:
 
 
September 30, 2018
 
December 31, 2017
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
 
(In thousands)
Senior Notes
$
510,766

 
$
535,941

 
$
507,600

 
$
542,472

Corporate Revolver
300,000

 
300,000

 

 

Facility
1,325,000

 
1,325,000

 
800,000

 
800,000

Total
$
2,135,766

 
$
2,160,941

 
$
1,307,600

 
$
1,342,472

 
The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
 
11. Equity-based Compensation
 
Restricted Stock Awards and Restricted Stock Units
 
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $8.9 million and $9.6 million during the three months ended September 30, 2018 and 2017, respectively, and $26.0 million and $29.9 million during the nine months ended September 30, 2018 and 2017, respectively. The total tax benefit for the three months ended September 30, 2018 and 2017 was $1.6 million and $3.2 million, respectively, and $5.0 million and $9.9 million during the nine months ended September 30, 2018 and 2017, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.1 million and $0.2 million for the three months ended September 30, 2018 and 2017, respectively, and $(0.3) million and $3.1 million during the nine months ended September 30, 2018 and 2017, respectively. The fair value of
awards vested during the three months ended September 30, 2018 and 2017 was approximately $1.1 million and $1.4 million, respectively, and $83.1 million and $20.7 million during the nine months ended September 30, 2018 and 2017, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these grants vest over three years. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.
 
The following table reflects the outstanding restricted stock awards as of September 30, 2018:
 
 
 
 
Weighted-
 
Service Vesting
 
Average
 
Restricted Stock
 
Grant-Date
 
Awards
 
Fair Value
 
(In thousands)
 
 
Outstanding at December 31, 2017
220

 
$
8.64

Granted

 

Forfeited

 

Vested
(220
)
 
8.64

Outstanding at September 30, 2018

 

 
The following table reflects the outstanding restricted stock units as of September 30, 2018:
 
 
 
 
Weighted-
 
Market / Service
 
Weighted-
 
Service Vesting
 
Average
 
Vesting
 
Average
 
Restricted Stock
 
Grant-Date
 
Restricted Stock
 
Grant-Date
 
Units
 
Fair Value
 
Units
 
Fair Value
 
(In thousands)
 
 
 
(In thousands)
 
 
Outstanding at December 31, 2017
4,183

 
$
6.39

 
8,452

 
$
11.26

Granted(1)(2)
2,360

 
7.03

 
8,140

 
12.39

Forfeited
(116
)
 
6.49

 
(46
)
 
9.74

Vested
(2,173
)
 
6.93

 
(9,545
)
 
13.75

Outstanding at September 30, 2018
4,254

 
6.41

 
7,001

 
9.17

__________________________________
(1)
The restricted stock units with a combination of market and service vesting criteria include 4.9 million shares granted as a result of the 2014 and 2015 awards achieving 200% of their respective market performance conditions.
(2)
The restricted stock units with a combination of market and service vesting criteria include 0.7 million shares granted to DGE employees as part of a new hire grant upon becoming employees of Kosmos. These shares were valued at $12.93 per share based on the Monte Carlo simulation model.

25

Table of Contents

 
As of September 30, 2018, total equity-based compensation to be recognized on unvested restricted stock units is $36.2 million over a weighted average period of 2.05 years. In January 2018, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan which was approved by our shareholders at the Annual General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At September 30, 2018, the Company had approximately 15.8 million shares that remain available for issuance under the LTIP.
 
For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $4.83 to $15.71 per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 44.0% to 53.0% . The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.7% to 2.2%.
  
12. Income Taxes
 
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.

On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances.

The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.
 
Income (loss) before income taxes is composed of the following:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Bermuda
$
(15,513
)
 
$
(17,740
)
 
$
(47,474
)
 
$
(50,680
)
United States
(53,136
)
 
1,437

 
(49,967
)
 
4,231

Foreign—other
(46,044
)
 
(48,617
)
 
(240,444
)
 
(9,863
)
Income (loss) before income taxes
$
(114,693
)
 
$
(64,920
)
 
$
(337,885
)
 
$
(56,312
)
 
Our effective tax rate for the three months ended September 30, 2018 and 2017 is 10% and 2%, respectively. For the nine months ended, September 30, 2018 and 2017, our effective tax rate was 17% and 79%, respectively. For the periods ended September 30, 2018 and 2017 our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.
 
The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017.
 
As of September 30, 2018, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.
 

26

Table of Contents

13. Net Loss Per Share
 
The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share:
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2018
 
2017
 
2018
 
2017
Numerator:
 

 
 

 
 

 
 

Net loss
$
(126,057
)
 
$
(63,405
)
 
$
(279,556
)
 
$
(100,713
)
Basic income allocable to participating securities(1)

 

 

 

Basic net loss allocable to common shareholders
(126,057
)
 
(63,405
)
 
(279,556
)
 
(100,713
)
Diluted adjustments to income allocable to participating securities(1)

 

 

 

Diluted net loss allocable to common shareholders
$
(126,057
)
 
$
(63,405
)
 
$
(279,556
)
 
$
(100,713
)
Denominator:
 
 
 
 
 
 
 
Weighted average number of shares outstanding:
 
 
 
 
 
 
 
Basic
404,536

 
389,058

 
399,026

 
388,114

Restricted stock awards and units(1)(2)

 

 

 

Diluted
404,536

 
389,058

 
399,026

 
388,114

Net loss per share:
 
 
 
 
 
 
 
Basic
$
(0.31
)
 
$
(0.16
)
 
$
(0.70
)
 
$
(0.26
)
Diluted
$
(0.31
)
 
$
(0.16
)
 
$
(0.70
)
 
$
(0.26
)
__________________________________
(1)
Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net loss per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net loss per common share calculation in periods we are in a net loss position.
(2)
We excluded outstanding restricted stock awards and units of 13.1 million and 12.9 million for the three months ended September 30, 2018 and 2017, respectively, and 14.5 million and 12.9 million for the nine months ended September 30, 2018 and 2017, respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive.  

14. Commitments and Contingencies
 
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
 
We currently have a commitment to drill one exploration well in Mauritania and two exploration wells in Senegal. Our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately 9,000 square kilometers and 13,500 square kilometers, respectively.
 
Future minimum rental commitments under our leases at September 30, 2018, are as follows:
 
 
Payments Due By Year(1)
 
Total
 
2018(2)
 
2019
 
2020
 
2021
 
2022