NOTES TO CON
SOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations
—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company
engaged in the development, production, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting Resources Corporation and Whiting Programs, Inc.
Basis of Presentation of Consolidated Financial Statements
—The consolidated financial statements have been prepared in accordance with GAAP and SEC rules and regulations and include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s
15.8%
ownership interest in Trust
I.
On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated and such interest in the underlying properties reverted back to Whiting.
Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method. Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses. All intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates
—
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (i) oil and natural
gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill; (vi) valuations of
the Company’s
reporting unit used in impairment tests of goodwill; (vii) income taxes; (viii) accrued liabilities; (ix) valuation of derivative instruments; and (x) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Reclassifications
—
Certain prior period balances in
the consolidated
balance sheets have been
reclassified to conform to
the current year
presentation.
Such
reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Cash, Cash Equivalents and Restricted Cash
—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
Restricted cash
at December 31, 2016
relate
d
to a deposit received in connection with the sale of
Whiting’s
interests in the Robinson Lake and Belfield gas processing plants. The use of these funds was restricted per the terms of the purchase agreement until the sale transaction closed on January
1, 2017. Refer to the “
Acquisition and Divestitures
” footnote for further information on this transaction.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
Cash and cash equivalents
|
|
$
|
879,379
|
|
$
|
55,975
|
Restricted cash
|
|
|
-
|
|
|
17,250
|
Total cash, cash equivalents and restricted cash
|
|
$
|
879,379
|
|
$
|
73,225
|
Accounts Receivable Trade
—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within
two
months, and to date, the Company has had minimal bad debts.
The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 201
7
and 201
6
, the Company had an allowance for doubtful accounts of
$
17
million and
$1
0
million, respectively.
Inventories
—
Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost. Materials and supplies are included in other property and equipment and totaled
$
24
million and
$
33
million as of December 31, 201
7
and 201
6
, respectively. Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or net
realizable value. Oil in tanks is included in prepaid expenses and other and totaled
$
7
million and
$8
million
as of December 31, 201
7
and 201
6, respectively
.
Oil and Gas Properties
Proved.
The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. Impairment expense for proved properties
totaled
$
83
5
m
illion
and
$1.6
billion
for the year
s
ended December 31, 201
7
and 2015, respectively
, which is reported in exploration and impairment expense.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use. During 201
7
, 201
6
and 201
5
, the Company capitalized interest of
$
0.1
million,
$
0.1
million and
$4
million, respectively.
Unproved.
Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on average lease-term lives and the historical experience of developing acreage in a particular prospect. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense for unproved properties totaled
$
59
million,
$
73
million and
$13
5
million for the years ended December 31, 201
7
, 201
6
and 201
5
, respectively, which is reported in exploration and impairment expense.
Exploratory.
Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs
and exploration expense.
Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Cost
s
incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
Other Property and Equipment
—
Other property and equipment consists of materials and supplies inventories, carried at weighted-average cost, and furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from
4
to
30
years.
Goodwill
—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value.
The Company performed its annual goodwill impairment test as of June 30, 2015, and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of Whiting’s common stock during the third quarter of 2015 caused by a significant decline in crude oil and natural gas prices over that same period, the Company performed another goodwill impairment test
as of September 30, 2015. The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying amount, and further that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recorded a non-cash impairment charge to reduce the carrying value of goodwill to
zero
.
Debt Issuance Costs
—Debt issuance costs related to the Company’s senior notes, convertible senior notes and senior subordinated notes are included as a deduction from the carrying amount of long-term debt in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the credit facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the agreement.
Debt Discounts and Premiums
—Debt discounts and premium
s related to the Company’s senior notes
and
convertible notes are included as a deduction from or addition to the carrying amount of the long-term debt in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related notes.
Derivative Instruments
—The Company enters into derivative contracts, primarily costless collars and swaps, to manage its exposure to commodity price risk. Whiting follows FASB ASC Topic 815,
Derivatives and Hedging
, to account for its derivative financial instruments.
All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria and the derivative has been designated as a hedge. The Company does not currently apply hedge accounting to any of its outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized currently in earnings.
Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions.
The Company does not enter into derivative instruments for speculative or trading purposes. Refer to the “Derivative Financial Instruments” footnote for further information.
Asset Retirement Obligations and Environmental Costs
—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The Company follows FASB ASC Topic 410,
Asset Retirement and Environmental Obligations
, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or when an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability.
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties.
Deferred Gain on Sale
—The deferred gain on sale relates to the sale of
18,400,000
Whiting USA Trust II (“Trust II”)
units, and is amortized to income based on the unit-of-production method.
Revenue Recognition
—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is reasonably assured. Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method). Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables. The Company’s aggregate imbalance positions as of December 31, 201
7
and 201
6
were not significant.
Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses.
General and Administrative Expenses
—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to the working interest owners that participate in oil and gas properties operated by Whiting.
Stock-based Compensation Expense
—The Company has share-based employee compensation plans that provide for the issuance of
various types of stock-based awards, including shares of
restricted stock
, restricted stock units
and stock option
s,
to employees and non-employee directors. The Company determines compensation expense for
restricted stock
awards
and options
granted under these plans based on the grant date fair value
,
and such expense is recognized on a straight-line basis over the requisite service period of the award.
The Company determines compensation expense for
cash-settled restricted stock units
granted under these plans based on the fair value
of such awards at the end of each reporting period
,
and such
awards are
recorded as
a
liability
in the consolidated
balance sheet
s
. Gains
and losses from changes in the fair value of
restricted stock units
are recognized immediately in earnings
.
The Company accounts for forfeitures of share-based awards as they occur.
Refer to the “Stock-Based Compensation” footnote for further information.
401(k) Plan
—The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for 201
7
, 201
6
and 201
5
were
$
8
million,
$
8
million and
$
12
million, respectively. Employees vest in employer contributions at
20%
per year of completed service.
Acquisition Costs
—
Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred.
Maintenance and Repairs
—Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized.
Income Taxes
—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
Earnings Per Share
—Basic earnings per common share is calculated by dividing net income
attributable
to common shareholders by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing adjusted net income
attributable
to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards, outstanding stock options and
contingently issuable shares of convertible debt to be settled in cash,
all using the treasury stock method. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 considers the effect of convertible debt issued and converted during 2016, using the if-converted method for periods prior to their actual conversions. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
Industry Segment and Geographic Information
—The Company has evaluated how it is organized and managed and has identified only
one
operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
Concentration of Credit Risk
—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 201
7
and 201
6
. For the year ended December 31, 2015, no individual purchaser accounted for 10% or more of the Company’s total oil, NGL and natural gas sales.
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|
Year Ended December 31, 2017
|
|
|
|
|
|
|
Tesoro Crude Oil Co
|
|
|
|
|
|
18%
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
Tesoro Crude Oil Co
|
|
|
|
|
|
15%
|
Jamex Marketing LLC
|
|
|
|
|
|
12%
|
Commodity derivative contracts held by the Company are with
nine
counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor’s. As of December 31, 201
7
, outstanding derivative contracts with JP Morgan Chase Bank, N.A.
,
Wells Fargo Bank, N.A.
,
Capital One, N.A. and KeyBank, N.A.
represented
24
%
,
1
7
%
,
14%
and
10%
,
respectively, of total crude oil volumes hedged.
Adopted and Recently Issued
Accounting Pronouncements
—
In May 2014, the FASB issued Accounting Standards Update No. 2014-09,
Revenue from Contracts with Customers
(“ASU 2014
‑09”). The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The FASB subsequently issued various ASUs which deferred the effective date of ASU 2014-09 and provided additional implementation guidance.
ASU 2014-09 and its amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standards permit retrospective application using either of the following methodologies: (i) restatement of each prior reporting period presented or (ii) recognition of a cumulative-effect adjustment as of the date of initial application. The Company adopt
ed
these ASUs effective January 1, 2018 using the modified retrospective approach. The Company
has
completed the assessment of
its contracts with customers and
is
in the process of implementing
the changes to its
financial statements, accounting policies and internal controls
as a result of the adoption of
these
standard
s.
The adoption is not expected to have a
n
impact on the Company’s net income or cash flows, however,
it
will
result in
changes to the
classification of
fees incurred under
certain pipeline gathering and transportation agreements
and
gas processing agreements
, as well as certain costs attributable to non-operated properties
, which will
result in an overall decrease in
total revenues
with a corresponding decrease in
lease operating
expenses under the new standards. In addition, the Company is
continuing to
assess the additional disclosures that will be required upon implementation of these ASUs.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02,
Leases
(“ASU 2016-02”). The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. Although the Company is still in the process of evaluating the effect of adopting ASU 2016
‑02, the adoption is expected to result in (i) an increase in the assets and liabilities recorded on its consolidated balance sheet, (ii) an increase in depreciation, depletion and amortization expense and interest expense recorded on its consolidated statement of operations, and (iii) additional disclosures. As of December 31, 2017, the Company had approximately $
73
million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09,
Improvements to Employee Share-Based Payment Accounting
(“ASU 2016-09”). The objective of this ASU is to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities and classification in the statement of cash flows. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, and the Company adopted this standard on January 1, 2017. Upon adoption of ASU 2016-09, the Company (i) recorded previously unrecognized excess tax benefits on a modified retrospective basis with a full valuation allowance, resulting in a net cumulative-effect adjustment to retained earnings of
zero
, (ii) prospectively removed excess tax benefits from its calculation of diluted shares, which had
no
impact on the Company’s diluted earnings per share for year ended December 31, 2017, and (iii) elected to account for forfeitures of share-based awards as they occur, rather than by applying an estimated forfeiture rate to determine compensation expense, the effect of which was recognized using a modified retrospective approach and resulted in an immaterial cumulative-effect adjustment to retained earnings and additional paid-in capital.
2.
OIL AND GAS PROPERTIES
Net capitalized costs related to
the Company’s
oil and gas
producing activities
at
December 31, 201
7
and 201
6
are as follows
(in thousands)
:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
Proved leasehold costs
|
|
$
|
2,622,576
|
|
$
|
3,330,928
|
Unproved leasehold costs
|
|
|
137,694
|
|
|
392,484
|
Costs of completed wells and facilities
|
|
|
8,288,591
|
|
|
9,016,472
|
Wells and facilities in progress
|
|
|
244,789
|
|
|
490,967
|
Total oil and gas properties, successful efforts method
|
|
|
11,293,650
|
|
|
13,230,851
|
Accumulated depletion
|
|
|
(4,185,301)
|
|
|
(4,170,237)
|
Oil and gas properties, net
|
|
$
|
7,108,349
|
|
$
|
9,060,614
|
3. ACQUISITIONS AND DIVESTITURES
2017 Acquisitions and Divestitures
On September 1, 2017, the Company completed the sale of its interests in certain producing oil and gas properties located in the Fort Berthold Indian Reservation area in Dunn and McLean counties of North Dakota, as well as other related assets and liabilities, (the “FBIR Assets”) for aggregate sales proceeds of
$500
million (before closing adjustments). The sale was effective September 1, 2017 and resulted in a pre-tax loss on sale of
$402
million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
On January
1, 2017, the Company completed the sale of its
50%
interest in the Robinson Lake gas processing plant located in Mountrail County, North Dakota and its
50%
interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January
1, 2017, for aggregate sales proceeds of
$375
million (before closing adjustments). The Company used the net proceeds from this transaction to repay a portion of the debt outstanding under its credit agreement.
The following table shows the components of assets and liabilities classified as held for sale as of December
31, 2016 (in thousands):
|
|
|
|
|
|
|
|
|
|
Carrying Value as of
|
|
|
December 31, 2016
|
Assets
|
|
|
|
Oil and gas properties, net
|
|
$
|
347,817
|
Other property and equipment, net
|
|
|
475
|
Total property and equipment, net
|
|
|
348,292
|
Other long-term assets
|
|
|
854
|
Total assets held for sale
|
|
$
|
349,146
|
|
|
|
|
Liabilities
|
|
|
|
Asset retirement obligations
|
|
$
|
131
|
Other long-term liabilities
|
|
|
407
|
Total liabilities related to assets held for sale
|
|
$
|
538
|
There were no significant acquisitions during the year ended December
31, 2017.
2016 Acquisitions and Divestitures
In July 2016, the Company completed the sale of its interest in its enhanced oil recovery project in the North Ward Estes field in Ward and Winkler counties of Texas, including Whiting’s interest in certain CO
2
properties in the McElmo Dome field in Colorado and certain other related assets and liabilities (the “North Ward Estes Properties”) for
a cash purchase price
of
$300
million (before closing adjustments). The sale was effective July
1, 2016 and resulted in a pre-tax loss on sale of
$
18
7
million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
In addition to the cash purchase price, the buyer agreed to pay Whiting
$100,000
for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above
$50.00/Bbl
up to a maximum amount of
$100
million (the “Contingent Payment”). The Company determined that this Contingent Payment
wa
s an embedded derivative and reflected it at fair value in the consolidated financial statements
prior to settlement
.
On July
19, 2017, the buyer paid
$35
million to Whiting to settle this Contingent Payment, resulting in a pre-tax gain of
$3
million.
Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on this embedded derivative instrument.
There were no significant acquisitions during the year ended December 31, 2016.
2015 Acquisitions and Divestitures
In December 2015, the Company completed the sale of a fresh water delivery system, a produced water gathering system and four saltwater disposal wells located in Weld County, Colorado, effective December 16, 2015, for aggregate sales proceeds of
$75
million (before closing adjustments).
In June 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective June
1, 2015, for aggregate sales proceeds of
$150
million (before closing adjustments) resulting in a pre-tax loss on sale of
$118
million. The properties included over
2,000
gross wells in
132
fields across
10
states.
In April 2015, the Company completed the sale of its interests in certain non-core oil and gas wells, effective May
1, 2015, for aggregate sales proceeds of
$108
million (before closing adjustments) resulting in a pre-tax gain on sale of
$29
million. The properties
we
re located in
187
fields across
14
states, and predominately consist
ed
of assets that were previously included in the underlying properties of Whiting USA Trust I.
Also during the year ended December
31, 2015, the Company completed several immaterial divestiture transactions for the sale of its interests in certain non-core oil and gas wells and undeveloped acreage, for aggregate sales proceeds of
$176
million (before closing adjustments) resulting in a pre-tax gain on sale of
$28
million.
There were no significant acquisitions during the year ended December
31, 2015.
4. LONG-TERM DEBT
Long-term debt
, including the current portion,
consisted of the following at December 31, 201
7
and 201
6
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
Credit agreement
|
|
$
|
-
|
|
$
|
550,000
|
6.5% Senior Subordinated Notes due 2018
|
|
|
-
|
|
|
275,121
|
5.0%
Senior Notes due 2019
|
|
|
961,409
|
|
|
961,409
|
1.25%
Convertible Senior Notes due 2020
|
|
|
562,075
|
|
|
562,075
|
5.75%
Senior Notes due 2021
|
|
|
873,609
|
|
|
873,609
|
6.25%
Senior Notes due 2023
|
|
|
408,296
|
|
|
408,296
|
6.625%
Senior Notes due 2026
|
|
|
1,000,000
|
|
|
-
|
Total principal
|
|
|
3,805,389
|
|
|
3,630,510
|
Unamortized debt discounts and premiums
|
|
|
(50,945)
|
|
|
(71,340)
|
Unamortized debt issuance costs on notes
|
|
|
(31,015)
|
|
|
(23,867)
|
Total debt
|
|
|
3,723,429
|
|
|
3,535,303
|
Less current portion of long-term debt
|
|
|
(958,713)
|
|
|
-
|
Total long-term debt
|
|
$
|
2,764,716
|
|
$
|
3,535,303
|
The following table shows five succeeding fiscal years of
anticipated
maturities for the Company’s long-term debt as of December
31, 201
7
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
Long-term debt
|
|
$
|
961,409
|
|
$
|
-
|
|
$
|
562,075
|
|
$
|
873,609
|
|
$
|
-
|
Credit Agreement
Whiting Oil and Gas, the Company’s wholly
owned subsidiary, has a credit agreement with a syndicate of banks that as of December
31, 201
7
had a borrowing
base
and
aggregate commitments of
$2.3
billion. As of December 31, 201
7
, the Company had
$2.3
billion of available borrowing capacity, which was net of
$2
million in letters of credit outstanding
, with
no
borrowings outstanding
.
The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November
1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement.
In October 2017, the borrowing
base
and aggregate commitments under the facility were reduced from
$2.5
billion to $2.3 billion in connection with the November 1, 2017 regular borrowing base redetermination, and was primarily a result of the sale of the Company’s FBIR Assets on September 1, 2017.
A portion of the revolving credit facility in an aggregate amount not to exceed
$50
million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of December 31, 201
7
,
$48
million was available for additional letters of credit under the agreement.
The credit agreement provides for interest only payments until December 2019, when the credit agreement expires and all outstanding borrowings are due. Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the
federal funds
rate plus
0.5%
per annum, or an adjusted LIBOR rate plus
1.0%
per annum, or (ii) an adjusted
LIBOR
rate for a Eurodollar loan plus the margin in the table below. Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interes
t expense. At December 31, 2016
, the weighted average interest rate on the outstanding principal balance under the credit agreement was
4.0%
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Applicable
|
|
Applicable
|
|
|
|
|
Margin for Base
|
|
Margin for
|
|
Commitment
|
Ratio of Outstanding Borrowings to Borrowing Base
|
|
Rate Loans
|
|
Eurodollar Loans
|
|
Fee
|
Less than
0.25
to 1.0
|
|
1.00%
|
|
2.00%
|
|
0.50%
|
Greater than or equal to
0.25
to 1.0 but less than
0.50
to 1.0
|
|
1.25%
|
|
2.25%
|
|
0.50%
|
Greater than or equal to
0.50
to 1.0 but less than
0.75
to 1.0
|
|
1.50%
|
|
2.50%
|
|
0.50%
|
Greater than or equal to
0.75
to 1.0 but less than
0.90
to 1.0
|
|
1.75%
|
|
2.75%
|
|
0.50%
|
Greater than or equal to
0.90
to 1.0
|
|
2.00%
|
|
3.00%
|
|
0.50%
|
The credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders.
However, the credit agreement permits the Company and certain of its subsidiaries to issue second lien indebtedness of up to
$1.0
billion subject to certain conditions and limitations.
Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock. These restrictions apply to all of the Company’s restricted subsidiaries (as defined in the credit agreement). As of December 31, 201
7
, there were
no
retained earnings free from restrictions. The credit agreement requires the Company, as of the last day of any quarter,
to maintain the following ratios (as defined in the credit agreement):
(i) a consolidated current assets to consolidated current liabilities ratio (which includes an add back of the available borrowing capacity under the credit agreement) of not less than
1.0
to 1.0, (ii)
a total senior secured debt to the last four quarters’ EBITDAX ratio of less than
3.0
to 1.0 during the Interim Covenant Period (defined below), and thereafter
a total debt to EBITDAX ratio of less than
4.0
to 1.0
,
and
(iii) a ratio of the last four quarters’ EBITDAX to consolidated
cash
interest charges of not less than
2.25
to 1.0 during the Interim Covenant Period. Under the credit agreement, the “Interim Covenant Period” is defined as the period from June 30, 2015 until the earlier of (
i
) April 1, 2018 or (
ii
) the commencement of an investment-grade debt rating period
(
as
defined in the credit agreement)
.
The Company was in compliance with its covenants under the credit agreement as of December 31, 201
7
.
The obligations of Whiting Oil and Gas under the credit agreement are
collateralized
by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee.
Senior Notes, Convertible Senior Notes and Senior Subordinated Notes
The following table summarizes the material terms of the Company’s senior notes and convertible senior notes outstanding at December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
2019
|
|
Convertible
|
|
2021
|
|
2023
|
|
2026
|
|
|
Senior Notes
(1)
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
Outstanding principal (in thousands)
|
|
$ 961,409
|
|
$ 562,075
|
|
$ 873,609
|
|
$ 408,296
|
|
$ 1,000,000
|
Interest rate
|
|
5.0%
|
|
1.25%
|
|
5.75%
|
|
6.25%
|
|
6.625%
|
Maturity date
|
|
Mar 15, 2019
|
|
Apr 1, 2020
|
|
Mar 15, 2021
|
|
Apr 1, 2023
|
|
Jan 15, 2026
|
Interest payment dates
|
|
Mar 15, Sep 15
|
|
Apr 1, Oct 1
|
|
Mar 15, Sep 15
|
|
Apr 1, Oct 1
|
|
Jan 15, Jul 15
|
Make-whole redemption date
(2)
|
|
Dec 15, 2018
|
|
N/A
(3)
|
|
Dec 15, 2020
|
|
Jan 1, 2023
|
|
Oct 15, 2025
|
_____________________
|
(1)
|
|
On January 26, 2018,
the Company
used the proceeds from the December 2017 issuance of
its
6.625% Senior Notes due January 2026 as well as borrowings under
its
credit agreement to redeem all of the outstanding 5.0% Senior Notes due March 2019.
|
|
(2)
|
|
On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to
100%
of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.
|
|
(3)
|
|
The indenture governing
the
1.25% Convertible Senior Notes due 2020 does not allow for optional redemption by the Company prior to the maturity date.
|
Senior Notes and Senior Subordinated Notes
—
In September 2010, the Company issued at par
$350
million of
6.5%
Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).
In September 2013, the Company issued at par
$1.1
billion of
5.0%
Senior Notes due March 2019 (the “2019 Senior Notes”) and
$800
million of
5.75%
Senior Notes due March 2021, and issued at
101%
of par an additional
$400
million of
5.75%
Senior Notes due March
2021 (collectively, the “2021 Senior Notes”).
The debt premium recorded in connection with the issuance of the 2021 Senior
Notes is
being
amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of
5.5%
per annum.
In March 2015, the Company issued at par
$750
million of
6.25%
Senior Notes due April 2023 (the “2023 Senior Notes”
).
Issuance of Senior Notes.
In December 2017, the Company issued at par
$1.0
billion of
6.625%
Senior Notes due January 2026 (the “2026 Senior Notes”
and together with the 2019 Senior Notes
, the
2021 Senior Notes
and the 2023 Senior Notes
, the “Senior Notes”
). The Company used the net proceeds from this offering to redeem on January 26, 2018 all of the outstanding 2019 Senior Notes at a
102.976%
redemption price plus all accrued and unpaid interest on the notes. Refer to the “Subsequent Events” footnote for more information on the redemption of the 2019 Senior Notes.
Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes
.
On March 23, 2016, the Company completed the exchange of
$477
million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes, consisting of (i)
$49
million aggregate principal amount of its 2018 Senior Subordinated Notes, (ii)
$97
million aggregate principal amount of its 2019 Senior Notes, (iii)
$152
million aggregate principal amount of its 2021 Senior Notes, and (iv)
$179
million aggregate principal amount of its 2023 Senior Notes, for
$477
million aggregate principal amount of convertible senior notes and convertible senior subordinated notes (the “New Convertible Notes”). This exchange transaction was accounted for as an extinguishment of debt for each portion of the Senior Notes and 2018 Senior Subordinated Notes that was exchanged. As a result, Whiting recognized a
$91
million gain on extinguishment of debt, which was net of a
$4
million non-cash charge for the acceleration of unamortized debt issuance costs and debt premium on the original notes. Each series of New Convertible Notes was recorded at fair value upon issuance, with the difference between the principal amount of the notes and their fair values, totaling
$95
million, recorded as a debt discount. The aggregate debt discount of
$185
million recorded upon issuance of the New Convertible Notes also included
$90
million related to the fair value of the holders’ conversion options, which were embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on these embedded derivatives.
During the second quarter of 2016, holders of the New Convertible Notes voluntarily converted all
$477
million aggregate principal amount of the New Convertible Notes for approximately
10.5
million shares of the Company’s common stock. Upon conversion, the Company paid
$46
million in cash consisting of early conversion payments to the holders of the notes, as well as all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a
$188
million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes. As of June 30, 2016,
no
New Convertible Notes remained outstanding.
Exchange of Senior Notes and Senior Subordinated Notes for Mandatory Convertible Notes.
On July 1, 2016, the Company completed the exchange of
$405
million aggregate principal amount of Senior Notes and 2018 Senior Subordinated Notes for the same aggregate principal amount of new mandatory convertible senior notes and mandatory convertible senior subordinated notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.
Kodiak Senior Notes.
In conjunction with the
acquisition of
Kodiak
in December 2014
, Whiting US Holding Company, a wholly
owned subsidiary of the Company, became a co-issuer of Kodiak’s
$800
million of
8.125%
Senior Notes due December 2019
(the “2019 Kodiak Notes”)
,
$350
million of
5.5%
Senior Notes due January 2021
(the “2021 Kodiak Notes”)
, and
$400
million of
5.5%
Senior Notes due February 2022 (
the “2022 Kodiak Notes” and together with the 2019 Kodiak Notes and the 2021 Kodiak Notes,
the “Kodiak Notes”).
I
n January
2015, Whiting offered to repurchase at
101%
of par all
$1,550
million principal amount of Kodiak Notes then outstanding.
I
n March 2015, Whiting paid
$760
million to repurchase
$2
million aggregate principal amount of the 2019 Kodiak Notes,
$346
million aggregate principal amount of the 2021 Kodiak Notes and
$399
million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the
101%
redemption price and all accrued and u
npaid interest on such notes. I
n May 2015,
Whiting paid an additional
$5
million to repurchase the remaining
$4
million aggregate principal amount of the 2021 Kodiak Notes and
$1
million aggregate principal amount of the 2022 Kodiak Notes, which payment consisted of the
101%
redemption price and all accrued and unpaid interest on such notes.
I
n December 2015, Whiting paid
$834
million to repurchase the remaining
$798
million aggregate principal amount of the 2019 Kodiak Notes, which payment consisted of the
104.063%
redemption price and all accrued and unpaid interest on such notes. As a result of the repurchases, Whiting recognized an
$18
million loss on extinguishment of debt, which consisted of a
$40
million cash charge related to the redemption premium on the Kodiak Notes, partially offset by a
$22
million non-cash credit related to the acceleration of unamortized debt premiums on such notes.
As of December 31, 2015,
no
Kodiak Notes remained outstanding.
Redemption of 2018 Senior Subordinated
Notes.
On February 2, 2017, the Company
paid
$281
million
to redeem all of the then outstanding
$275
million aggregate principal amount of 2018 Senior Subordinated Notes, which payment
consisted of the
100%
redemption price plus all accrued and unpaid interest on the notes
. The Company financed the redemption with borrowings under its credit agreement.
As a result of the redemption, Whiting recognized a
$2
million loss on extinguishment of debt, which consisted of a
non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2017,
no
2018 Senior Subordinated Notes remained outstanding.
2020
Convertible Senior Notes
—In March 2015, the Company issued at par
$1,250
million of
1.25%
Convertible Senior Notes due April 2020 (the “
2020
Convertible Senior Notes”) for net proceeds of
$1.2
billion, net of initial purchasers’ fees of
$25
million.
On June 29, 2016, the Company exchanged
$129
million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes, and on July 1, 2016, the Company exchanged
$559
million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.
For the remaining $562 million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of December 31, 2017, t
he Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the
2020
Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the
2020
Convertible Senior Notes will be convertible
at the holder’s option
only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least
20
trading days (whether or not consecutive) during the period of
30
consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130%
of the conversion price on each applicable trading day; (ii) during the
five
business day period after any
five
consecutive trading day period (the “measurement period”) in which the trading price per
$1,000
principal amount of the
2020
Convertible Senior Notes for each trading day of the measurement period is less than
98%
of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the
2020
Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at a
current
conversion rate of
6.4102
shares of Whiting’s common stock per
$1,000
principal amount of the notes, which is equivalent to a
current
conversion price of approximately
$156.00
. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its
2020
Convertible Senior Notes in connection with such corporate event. As of December 31, 201
7
, none of the contingent conditions allowing holders of the
2020
Convertible Senior Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the
2020
Convertible Senior Notes. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the
2020
Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and
is being
amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of
5.6%
per annum. The fair value of the
liability component of the 2020
Convertible Senior Notes as of the issuance date was estimated at
$1.0
billion, resulting in a debt discount at inception of
$238
million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the
2020
Convertible Senior Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity classification.
Transaction costs related to the
2020
Convertible Senior Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were recorded as a reduction to the carrying value of long-term debt on the consolidated balance sheet and are being amortized to
interest
expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity.
The
2020
Convertible Senior Notes consist
ed
of the following at December 31, 201
7 and 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
Liability component
|
|
|
|
|
|
|
Principal
|
|
$
|
562,075
|
|
$
|
562,075
|
Less: unamortized note discount
|
|
|
(51,666)
|
|
|
(72,622)
|
Less: unamortized debt issuance costs
|
|
|
(4,178)
|
|
|
(5,988)
|
Net carrying value
|
|
$
|
506,231
|
|
$
|
483,465
|
Equity component
(1)
|
|
$
|
136,522
|
|
$
|
136,522
|
|
(1)
|
|
Recorded in additional paid-in capital, net of
$5
million of issuance costs and
$50
million of deferred taxes as of December 31, 2017 and 2016.
|
Interest expense recognized
on the
2020
Convertible Senior Notes related to the stated interest rate and amortization
of the debt discount
totaled
$28
million,
$43
million and
$44
million for
the year
s
ended December 31, 201
7, 2016 and 2015, respectively.
Mandatory Convertible Notes
—
On June 29, 2016, the Company completed the exchange of
$129
million aggregate principal amount of its
2020
Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible notes, and on July
1, 2016, the Company completed the exchange of
$964
million aggregate principal amount of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes, consisting of (i)
$26
million aggregate principal amount of 2018 Senior Subordinated Notes, (ii)
$42
million aggregate principal amount of 2019 Senior Notes, (iii)
$559
million aggregate principal amount of 2020 Convertible Senior Notes, (iv)
$174
million aggregate principal amount of 2021 Senior Notes, and (v)
$163
million aggregate principal amount of 2023 Senior Notes, for the same aggregate principal amount of new mandatory convertible notes (together the “Mandatory Convertible Notes”).
These transactions were accounted for as extinguishments of debt for the portions of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated Notes that were exchanged. As a result, Whiting recognized a
$57
million gain on extinguishment of debt, which was net of a
$113
million charge for the non-cash write-off of unamortized debt issuance costs, debt discounts and debt premium on the original notes. In addition, Whiting recorded a
$63
million reduction to the equity component of the 2020 Convertible Senior Notes, which was net of deferred taxes. The Mandatory Convertible Notes were recorded at fair value upon issuance with the difference between the principal amount of the notes and their fair values, totaling
$69
million, recorded as a debt discount. The Mandatory Convertible Notes contained contingent beneficial conversion features, the intrinsic value of which was recognized in additional paid-in capital at the time the contingency was resolved, resulting in an additional debt discount of
$233
million. The aggregate debt discount of
$302
million was being amortized to interest expense over the term of the notes using the effective interest method.
The July 1, 2016 note exchange transactions triggered an ownership shift as defined under Section 382 of the Internal Revenue Code due to the “deemed share issuance” that resulted from the note exchanges. This triggering event will limit the Company’s usage of certain of its net operating losses and tax credits in the future. Refer to the “Income Taxes” footnote for more information.
During the second half of 2016, the entire
$1,093
million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately
28.9
million shares of the Company’s common stock pursuant to the terms of the notes. As a result of these conversions, Whiting recognized (i) a
$259
million non-cash charge for the acceleration of unamortized debt discounts on the notes, which is included in interest expense in the consolidated statements of operations, and (ii) a
$1
million net loss on extinguishment of debt. As of December 31, 2016,
no
Mandatory Convertible Notes remained outstanding.
Security and Guarantees
The Senior Notes and the
2020
Convertible Senior Notes are unsecured obligations of Whiting Petroleum Corporation and
these unsecured obligations
are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement.
The Company’s obligations under the
Senior Notes and the 2020
Convertible Senior Notes are guaranteed by the Company’s
100%
‑
owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”).
These guarantees are full and unconditional and joint and several among the Guarantors.
Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S
‑X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.
5. ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws. The current portions at December 31, 201
7
and 201
6
were
$5
million and
$8
million, respectively, and have been included in accrued liabilities and other
in the consolidated balance sheets
. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 201
7
and 201
6
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
Asset retirement obligation at January 1
|
|
$
|
177,004
|
|
$
|
161,908
|
Additional liability incurred
|
|
|
7,727
|
|
|
3,238
|
Revisions to estimated cash flows
(1) (2)
|
|
|
(52,947)
|
|
|
11,620
|
Accretion expense
|
|
|
13,809
|
|
|
13,800
|
Obligations on sold properties
|
|
|
(6,988)
|
|
|
(4,771)
|
Liabilities settled
|
|
|
(4,368)
|
|
|
(8,791)
|
Asset retirement obligation at December 31
|
|
$
|
134,237
|
|
$
|
177,004
|
|
(1)
|
|
Revisions to estimated cash flows during the year ended December 31, 2017 are primarily attributable to the
deferral of
the estimated timing of abandonment of a large number of
Whiting’s
producing properties resulting from
in
creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 2017
,
which
lengthened
the economic lives of these properties.
In addition, during 2017 there were decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Northern Rocky Mountains.
|
|
(2)
|
|
R
evisions to estimated cash flows during the year ended December 31, 2016 are primarily attributable to the
a
cceleration in the estimated timing of abandonment of a large number of
Whiting’s
producing properties resulting from
de
creases in commodity prices used in the calculation of the Company’s reserves as of December 31, 201
6,
which
shortened
the economic lives of these properties
.
For the year ended December 31, 2016, the increase was partially offset by decreases in the estimates of future costs required to plug and abandon wells in certain fields in the Central and Northern Rocky Mountains.
|
6. DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, and
it
uses derivative instruments to manage its commodity price risk.
In addition, the Company periodically enters into contracts that contain embedded features which are required to be bifurcated and accounted for separately as derivatives.
Commodity Derivative Contracts
—
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting
primarily
enters into derivative contracts such as
crude oil
costless collars
and
swaps
, as well as
sales and delivery contracts
,
to achieve a more predictable cash flow by reducing its exposure to commodity price volatility
,
thereby ensur
ing
adequate fund
ing for
the Company’s capital programs and
facilitating the management of
returns on drilling programs and acquisitions. The Company does not enter into derivative contracts for speculative or trading purposes.
Crude Oil Costless Collars.
Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.
The table below details the Company’s costless collar derivatives entered into to hedge forecasted crude oil production revenues as of
December 31
, 201
7
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
|
|
|
|
Contracted Crude
|
|
Weighted Average NYMEX Price
|
Instrument
|
|
Period
|
|
Oil Volumes (Bbl)
|
|
Collar Ranges for Crude Oil (per Bbl)
|
Three-way collars
(1)
|
|
Jan - Dec 2018
|
|
17,400,000
|
|
$37.07
-
$47.07
-
$57.30
|
|
|
Total
|
|
17,400,000
|
|
|
_____________________
|
(1)
|
|
A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
|
|
(2)
|
|
Subsequent to
December 31, 2017
, the Company entered into additional
swap
contracts
for
4,40
0,000
Bbl of crude oil volumes for the year ended December 31, 2018
, as well as
costless
collars for
900
,000
Bbl of crude oil volumes for the six months ended June
30, 2019
.
|
Crude Oil Sales and Delivery Contract.
As of December 31, 2017, t
he
Company ha
d
a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado. Under the terms of the agreement, Whiting ha
d
committed to deliver certain fixed volumes of crude oil through
April
2020. The Company determined it was not probable that future oil production from its Redtail field would be sufficient to meet the minimum volume requirement
s
specified in this contract
;
accordingly, the Company would not
settle this contract through physical delivery of crude oil volumes. As a result, Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial statements. As of December
31, 201
7 and 2016
, the estimated fair value of this derivative contract was a liability of $
63
million
and $9 million, respectively
.
On February 1, 2018, Whiting paid
$61
million to the counterparty to settle all future minimum volume commitments under this agreement
. Accordingly, this crude oil sales and delivery contract was fully terminated and the
fair value of this
corresponding derivative
was therefore
zero
as of that date.
Embedded Derivatives
—
I
n March 2016, the Company issued convertible notes that contained debtholder conversion options which the Company determined were not clearly and closely related to the debt host contracts, and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements.
During the second quarter of 2016, the entire aggregate principal amount of these notes was converted into shares of the Company’s common stock, and the fair value of these embedded derivatives as of December 31, 2017 and 2016 was therefore
zero
.
In July 2016, the Company entered into a purchase and sale agreement with the buyer of
its North Ward Estes Properties,
whereby the buyer agreed to pay Whiting additional proceeds of
$100,000
for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above
$50.00/Bbl
up to a maximum amount of
$100
million. The Company determined that this NYMEX-linked contingent payment was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at its estimated fair value of $51 million in the consolidated financial statements as of December 31, 2016. On July 19, 2017, the buyer paid
$35
million to Whiting to settle this NYMEX-linked contingent payment, and accordingly, the embedded derivative’s fair value was
zero
as of December 31, 2017.
Derivative Instrument Reporting
—
All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion
or other derivative scope exceptions
. The following table summarize
s
the effects of derivative instruments on the consolidated statements of operations for the years ended December 31, 201
7
, 201
6
and 201
5
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) Loss Recognized in Income
|
Not Designated as
|
|
Statement of Operations
|
|
Year Ended December 31,
|
ASC 815 Hedges
|
|
Classification
|
|
2017
|
|
2016
|
|
2015
|
Commodity contracts
|
|
Derivative (gain) loss, net
|
|
$
|
104,138
|
|
$
|
58,771
|
|
$
|
(217,972)
|
Embedded derivatives
|
|
Derivative (gain) loss, net
|
|
|
18,709
|
|
|
(59,358)
|
|
|
-
|
Total
|
|
|
|
$
|
122,847
|
|
$
|
(587)
|
|
$
|
(217,972)
|
Offsetting of Derivative Assets and Liabilities.
The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all
the Company’s
derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
(1)
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
Gross
|
|
Fair Value
|
Not Designated as
|
|
|
|
Assets/
|
|
Amounts
|
|
Assets/
|
ASC 815 Hedges
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
Offset
|
|
Liabilities
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Prepaid expenses and other
|
|
$
|
9,829
|
|
$
|
(9,829)
|
|
$
|
-
|
Total derivative assets
|
|
|
|
$
|
9,829
|
|
$
|
(9,829)
|
|
$
|
-
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
142,354
|
|
$
|
(9,829)
|
|
$
|
132,525
|
Total derivative liabilities
|
|
|
|
$
|
142,354
|
|
$
|
(9,829)
|
|
$
|
132,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
(1)
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
Gross
|
|
Fair Value
|
Not Designated as
|
|
|
|
Assets/
|
|
Amounts
|
|
Assets/
|
ASC 815 Hedges
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
Offset
|
|
Liabilities
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Prepaid expenses and other
|
|
$
|
21,405
|
|
$
|
(21,405)
|
|
$
|
-
|
Commodity contracts - non-current
|
|
Other long-term assets
|
|
|
9,495
|
|
|
(9,495)
|
|
|
-
|
Embedded derivatives - non-current
|
|
Other long-term assets
|
|
|
50,632
|
|
|
-
|
|
|
50,632
|
Total derivative assets
|
|
|
|
$
|
81,532
|
|
$
|
(30,900)
|
|
$
|
50,632
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
39,033
|
|
$
|
(21,405)
|
|
$
|
17,628
|
Commodity contracts - non-current
|
|
Other long-term liabilities
|
|
|
19,724
|
|
|
(9,495)
|
|
|
10,229
|
Total derivative liabilities
|
|
|
|
$
|
58,757
|
|
$
|
(30,900)
|
|
$
|
27,857
|
_____________________
|
(1)
|
|
Because counterparties to the Company’s financial derivative contracts subject to master netting arrangements are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in these tables.
|
Contingent Features in Financial Derivative Instruments
.
None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under Whiting’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.
7. FAIR VALUE MEASUREMENTS
The Company follows FASB ASC Topic 820,
Fair Value Measurement and Disclosure
, which
establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy
categorizes
assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
|
·
|
|
Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
|
|
·
|
|
Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
|
|
·
|
|
Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
|
A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.
Cash
,
cash equivalents
, restricted cash
, accounts receivable and accounts payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments. The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is
tied to current market rates and the applicable margins represent market rates.
The Company’s senior notes and senior subordinated notes are recorded at cost,
and the Company’s convertible senior notes are recorded at fair value at the date of issuance. The following table summarizes the fair values and carrying values of these instruments as of December 31, 2017 and 2016 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
|
Value
(1)
|
|
Value
(2)
|
|
Value
(1)
|
|
Value
(2)
|
6.5% Senior Subordinated Notes due 2018
|
|
$
|
-
|
|
$
|
-
|
|
$
|
275,121
|
|
$
|
273,506
|
5.0%
Senior Notes due 2019
|
|
|
985,444
|
|
|
958,713
|
|
|
961,409
|
|
|
956,607
|
1.25%
Convertible Senior Notes due 2020
|
|
|
517,109
|
|
|
506,231
|
|
|
503,057
|
|
|
483,465
|
5.75%
Senior Notes due 2021
|
|
|
897,633
|
|
|
869,284
|
|
|
868,149
|
|
|
868,460
|
6.25%
Senior Notes due 2023
|
|
|
418,503
|
|
|
403,940
|
|
|
408,296
|
|
|
403,265
|
6.625%
Senior Notes due 2026
|
|
|
1,025,000
|
|
|
985,261
|
|
|
-
|
|
|
-
|
Total
|
|
$
|
3,843,689
|
|
$
|
3,723,429
|
|
$
|
3,016,032
|
|
$
|
2,985,303
|
|
(1)
|
|
Fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.
|
|
(2)
|
|
Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.
|
The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance ri
sk or that of its counterparty
, as appropriate.
The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 201
7
and 201
6
, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
December 31, 2017
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
69,247
|
|
$
|
63,278
|
|
$
|
132,525
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
69,247
|
|
$
|
63,278
|
|
$
|
132,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
December 31, 2016
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Embedded derivatives – non-current
|
|
$
|
-
|
|
$
|
50,632
|
|
$
|
-
|
|
$
|
50,632
|
Total financial assets
|
|
$
|
-
|
|
$
|
50,632
|
|
$
|
-
|
|
$
|
50,632
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
14,664
|
|
$
|
2,964
|
|
$
|
17,628
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
3,979
|
|
|
6,250
|
|
|
10,229
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
18,643
|
|
$
|
9,214
|
|
$
|
27,857
|
The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are measured on a recurring basis:
Commodity Derivatives
.
Commodity derivative instruments consist mainly of costless collars for crude oil. The Company’s costless collars are valued based on an income approach.
T
he option model consider
s
various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
In addition, the Company ha
d
a
long-term crude oil sales
and delivery contract, whereby it
had
committed to deliver certain fixed volumes of crude oil through
April
2020.
Whiting determined that the contract
did
not meet the “normal purchase normal sale” exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements.
This commodity derivative was valued based on a
probability-weighted
income approach which considers various assumptions, including quoted
spot
prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The assumptions used in the valuation of the crude oil sales and delivery
contract include certain market differential metrics that were unobservable during the term of the contract.
Such unobservable inputs were significant to the contract valuation methodology, and the
contract’s
fair value was therefore designated as Level 3 within the valuation hierarchy.
On February 1, 2018, Whiting paid
$61
million to the counterparty to settle all future minimum volume commitments under this agreement
. Accordingly, this derivative was settled
in its entirety
as of that date.
Embedded Derivatives
. The Company had embedded derivatives related to its convertible notes that were issued in March 2016. The notes contained debtholder conversion options which the Company determined were not clearly and closely related
to the debt host contracts and the Company therefore bifurcated these embedded features and reflected them at fair value in the consolidated financial statements
. Prior to their settlements, the fair values of these embedded derivatives were determined using a binomial lattice model which considered various inputs including (i) Whiting’s common stock price, (ii) risk-free rates based on U.S. Treasury rates, (iii) recovery rates in the event of default, (iv) default intensity, and (v) volatility of Whiting’s common stock. The expected volatility and default intensity used in the valuation were unobservable in the marketplace and significant to the valuation methodology, and the embedded derivatives’ fair value was therefore designated as Level 3 in the valuation hierarchy. During the second quarter of 2016, the entire aggregate principal amount of these convertible notes was converted into shares of the Company’s common stock. Accordingly, the embedded derivatives were settled in their entirety as of June 30, 2016.
The Company had an embedded derivative related to its purchase and sale agreement with the buyer of the North Ward Estes Properties. The agreement included a Contingent Payment linked to NYMEX crude oil prices which the Company determined was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it at fair value in the consolidated financial statements prior to settlement. The fair value of this embedded derivative was determined using a modified Black-Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value and volatility factors. These assumptions were observable in the marketplace throughout the full term of the financial instrument
, could be derived from observable data or were supported by observable levels at which transactions are executed in the marketplace, and were therefore designated as Level 2 within the valuation hierarchy. The discount rate used in the fair value of this instrument included a measure of the counterparty’s nonperformance risk. On July 19, 2017, the buyer paid
$35
million to Whiting in satisfaction of this Contingent Payment. Accordingly, the embedded derivative was settled in its entirety as of that date.
Level 3 Fair Value Measurements
—
A third-party valuation specialist is utilized
in
determin
ing
the fair value of the
Company’s
derivative instruments designated as Level 3. The Co
mpany reviews these valuations,
including the relat
ed model inputs and assumptions,
and analyzes changes in fair value measurements between periods. The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.
T
he following table presents a reconciliation of changes in the fair value of financial assets or liabilities designated as Level 3 in the valuation hierarchy for the years ended December 31, 201
7
and 201
6
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
Fair value liability, beginning of period
|
|
$
|
(9,214)
|
|
$
|
(4,027)
|
Recognition of embedded derivatives associated with convertible note issuances
|
|
|
-
|
|
|
(89,884)
|
Unrealized gains on embedded derivatives included in earnings
(1)
|
|
|
-
|
|
|
47,965
|
Settlement of embedded derivatives upon conversion of convertible notes
|
|
|
-
|
|
|
41,919
|
Unrealized losses on commodity derivative contracts included in earnings
(1)
|
|
|
(54,064)
|
|
|
(5,187)
|
Transfers into (out of) Level 3
|
|
|
-
|
|
|
-
|
Fair value liability, end of period
|
|
$
|
(63,278)
|
|
$
|
(9,214)
|
_____________________
|
(1)
|
|
Included in derivative
(
gain
) loss
, net in the consolidated statements of operations.
|
Quantitative Information
a
bout Level 3 Fair Value Measurements.
The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative
instrument
designated as Level 3 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instrument
|
|
Valuation Technique
|
|
Unobservable Input
|
|
Amount
|
Commodity derivative contract
|
|
Probability-weighted i
ncome approach
|
|
Market differential for crude oil
|
|
$
4.08
-
$
4.9
2
per Bbl
|
Sensitivity to Changes
i
n Significant Unobservable Inputs.
As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contract are the market differentials for crude oil over the term of the contract. Significant increases or decreases in these unobservable inputs in isolation would result in a significantly
lower
or
higher
, respectively, fair value liability measurement.
Non-recurring Fair Value Measurements
—
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.
The Company did
not
recognize any impairment write-downs with respect to its proved property during the year ended December 31, 2016.
The following
table presents
information about the Company’s non-financial assets measured at fair value on a non-recurring basis for the year ended December 31, 2017, and indicates the fair value hierarchy
of the valuation techniques utilized by the Company to determine such fair value (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (Before
|
|
|
Net Carrying
|
|
|
|
|
|
|
|
|
|
|
Tax) Year
|
|
|
Value as of
|
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
December 31,
|
|
Fair Value Measurements Using
|
|
December 31,
|
|
|
2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
2017
|
Proved property
(1)
|
|
$
|
389,390
|
|
$
|
-
|
|
$
|
-
|
|
$
|
389,390
|
|
$
|
834,950
|
_____________________
|
(1)
|
|
During the fourth quarter of 2017, proved oil and gas properties at the Redtail field in the
Denver Julesb
u
rg Basin (
the
“
DJ Basin
”)
in Weld County, Colorado, with a previous carrying amount of
$1.2
billion were written down to their fair value as of December
31, 2017 of $
389
million, resulting in a non-cash impairment charge of $
83
5
m
illion which was recorded within exploration and impairment expense.
|
The following methods and assumptions were used to estimate the fair values of the non-financial assets in the table above:
Proved Property Impairments
.
The Company tests proved property for impairment whenever events or changes in circumstances indicate that the fair value of these assets may be reduced below their carrying value.
Based on recent well performance results in the DJ Basin, the Company reduced its reserves at its Redtail field during the fourth quarter of 2017, and
performed a proved property impairment test as of December 31, 2017. The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing property and related assets. The discounted cash flows were based on management’s expectations for the future. Unobservable inputs included estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on sales contract terms or forward price curves (adjusted for basis differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which were designated as Level 3 inputs within the fair value hierarchy). The impairment test indicated that a proved property impairment had occurred, and the Company therefore recorded a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value at
December 31, 2017
.
8
. SHAREHOLDERS
’
EQUITY AND NONCONTROLLING INTEREST
Common Stock
Reverse Stock Split.
On November 8, 2017
and following approval by the Company’s stockholders of an amendment to its certificate of incorporation to effect a reverse stock split,
the Company’s Board of Directors approved a reverse stock split of Whiting’s common stock at a ratio of
one
-for-four and a reduction in the number of authorized shares of the Company’s common stock from
600,000,000
shares to
225,000,000
. Whiting’s common stock began trading on a split-adjusted basis on November 9, 2017 upon opening of the markets. All
share
and per share amounts in these consolidated financial statements and related notes for periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split.
Common Stock Offering.
In March 2015, the Company completed a public offering of its common stock, selling
8,750,000
shares of common stock at a price of
$
12
0.00
per share and providing net proceeds of approximately
$1.0
billion after underwriter’s fees. In addition, the Company granted the underwriter a
30
-day option to purchase up to an additional
1,312
,
5
00
shares of common stock.
On April 1, 2015, the underwriter exercised its right to purchase an additional
5
00,000
shares of common stock, providing additional net proceeds of
$61
million.
Noncontrolling Interest
—The Company’s noncontrolling interest represent
ed
an unrelated third party’s
25%
ownership interest in Sustainable Water Resources, LLC
(“SWR”)
.
During the third quarter of 2017, the third party’s ownership interest in SWR was assigned back to SWR.
The
table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
Balance at beginning of period
|
|
$
|
7,962
|
|
$
|
7,984
|
Net loss
|
|
|
(14)
|
|
|
(22)
|
Conveyance of ownership interest
|
|
|
(7,948)
|
|
|
-
|
Balance at end of period
|
|
$
|
-
|
|
$
|
7,962
|
9. STOCK-BASED COMPENSATION
Equity Incentive Plan
—
T
he Company
maintains the
Whiting Petroleum Corporation 2013 Equity Incentive Plan
, as amended and restated
(the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and include
s
the authority to issue
1,375,000
shares of the Company’s common stock. Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited under the 2003 Equity Plan and any shares forfeited under the 2013 Equity Plan will be available for future issuance under the 2013 Equity Plan. However, shares netted for tax withholding under the 2013 Equity
Plan will be cancelled and will not be available for future issuance.
Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than
225,000
shares of common stock, stock appreciation rights relating to more than
225,000
shares of common stock, more than
150,000
shares of restricted stock, more than
150,000
restricted stock units, more than
150,000
performance shares, or more than
150,000
performance units during any calendar year. In addition, no non-employee director participant may be granted options for more than
25,000
shares of common stock, stock appreciation rights relating to more than
25,000
shares of common stock, more than
25,000
shares of restricted stock, or more than
25,000
restricted stock units during any calendar year.
As of December 31, 2017,
1,137,723
shares of common stock remained available for grant under the 2013 Equity Plan.
Restricted
Stock, Restricted Stock Units and Performance
Shares
—The Company grants service-based restricted stock awards
and restricted stock units
to executive officers and employees, which generally vest ratably over a
three
-
year
service period
.
The Company also grants service-based restricted stock awards
to directors, which generally vest over a
one
-year service period. In addition, the Company grants
performance share
awards to executive officers that are subject to market-based vesting criteria as well as a
three
-year service period.
Upon adoption of ASU 2016-09 on January 1, 2017, the Company elected to account for forfeitures of awards granted under these plans as they occur in determining compensation expense.
The Company recognizes compensation expense for all awards subject to market
-based vesting
conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
During 2017, 2016 and 2015,
538,194
,
737,912
and
205,971
shares, respectively, of service-based restricted stock awards were granted to
employees, executive officers and directors under the 2013 Equity Plan. The grant date fair value of restricted stock
awards
is determined based on the closing bid price of the Company’s common stock on the grant date. The weighted average grant date fair value of restricted stock
awards
was
$40.66
per share,
$27.82
per share and
$123.72
per
share for the years ended December 31, 2017, 2016, and 2015, respectively.
During
2017,
201
6 and
2015,
168,466
,
268,278
and
97,937
performance shares
, respectively, subject to
certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third anniversary of the grant date, and the number of shares that will vest at the end of that
three
-year performance period
is
determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies over the same three-year period. The number of shares earned could range from
zero
up to
two
times the number of shares initially granted.
For awards subject to market conditions, the grant date fair value
is
estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility
i
s calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the
se
market-based
awards
were as follows:
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
Number of simulations
|
|
2,500,000
|
|
2,500,000
|
|
2,500,000
|
Expected volatility
|
|
82.44%
|
|
60.8%
|
|
40.3%
|
Risk-free interest rate
|
|
1.52%
|
|
1.13%
|
|
0.99%
|
Dividend yield
|
|
-
|
|
-
|
|
-
|
The
weighted average
grant date fair value of the
market-based awards as determined by the Monte Carlo valuation model was
$63.04
per share,
$25.56
per share and
$133.00
per share in
201
7
, 201
6
and 201
5
, respectively.
The following table shows a summary of the Company’s restricted stock
award (“RSA”), restricted stock unit (“RSU”) and performance share activity for the year ended
December 31, 201
7
:
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Awards
|
|
Weighted
Average
|
|
|
Service-Based
|
|
Service-Based
|
|
Market-Based
|
|
Grant Date
|
|
|
RSAs
|
|
RSUs
|
|
Performance Awards
|
|
Fair Value
|
Nonvested awards, January 1
|
|
766,818
|
|
-
|
|
523,172
|
|
$
|
54.19
|
Granted
|
|
538,194
|
|
39,619
|
|
168,466
|
|
|
44.89
|
Vested
|
|
(339,199)
|
|
-
|
|
-
|
|
|
51.23
|
Forfeited
|
|
(67,392)
|
|
-
|
|
(194,111)
|
|
|
81.97
|
Nonvested awards, December 31
|
|
898,421
|
|
39,619
|
|
497,527
|
|
$
|
44.99
|
As of December 31, 201
7
, there was
$18
million of total unrecognized compensation cost related to unvested
awards
granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of
2.0
years.
For the years ended December
31, 201
7
, 201
6
and 201
5
, the total fair value of restricted stock vested was
$15
million,
$5
million and
$4
million, respectively.
Stock Options
—Stock
options may be granted to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date. There were no stock options granted under the 2013 Equity Plan during 201
7
, 201
6
or 201
5
. The Company’s stock options vest ratably over a
three
-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.
The following table shows a summary of the Company’s stock options outstanding as of December 31, 201
7
as w
ell as activity during the year
then ended
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
Weighted
|
|
Aggregate
|
|
Remaining
|
|
|
|
|
Average
|
|
Intrinsic
|
|
Contractual
|
|
|
Number of
|
|
Exercise Price
|
|
Value
|
|
Term
|
|
|
Options
|
|
per Share
|
|
(in thousands)
|
|
(in years)
|
Options outstanding at January 1
|
|
128,524
|
|
$
|
158.17
|
|
|
|
|
|
Granted
|
|
-
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
-
|
|
|
-
|
|
$
|
-
|
|
|
Forfeited or expired
|
|
(6,490)
|
|
|
207.86
|
|
|
|
|
|
Options outstanding at December 31
|
|
122,034
|
|
$
|
154.32
|
|
$
|
28
|
|
2.4
|
Options vested at December 31
|
|
122,034
|
|
$
|
154.32
|
|
$
|
28
|
|
2.4
|
Options exercisable at December 31
|
|
122,034
|
|
$
|
154.32
|
|
$
|
28
|
|
2.4
|
There was
no
unrecognized compensation cost related to unvested stock option awards as of December 31, 201
7
.
There were
no
stock options exercised during the years ended December 31, 2017 or 2016.
For the year ended December 31, 201
5
, the
aggregate
intrinsic value of stock options exercised
was
$
2
million.
For the years ended December 31, 201
7
, 201
6
and 201
5
, total stock compensation expense recognized for restricted share awards and stock options was
$22
million,
$26
million and
$28
million, respectively.
10.
INCOME TAXES
Income
tax benefit consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Current income tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(7,305)
|
|
$
|
(7,340)
|
|
$
|
-
|
State
|
|
|
14
|
|
|
150
|
|
|
(357)
|
Total current income tax benefit
|
|
|
(7,291)
|
|
|
(7,190)
|
|
|
(357)
|
Deferred income tax benefit
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(398,686)
|
|
|
(65,130)
|
|
|
(736,520)
|
State
|
|
|
(77,002)
|
|
|
(15,326)
|
|
|
(37,350)
|
Total deferred income tax benefit
|
|
|
(475,688)
|
|
|
(80,456)
|
|
|
(773,870)
|
Total
|
|
$
|
(482,979)
|
|
$
|
(87,646)
|
|
$
|
(774,227)
|
Income tax benefit differed from amounts that would result from applying the U.S. statutory income tax rate (
35%)
to income before income taxes as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
U.S. statutory income tax benefit
|
|
$
|
(602,219)
|
|
$
|
(499,370)
|
|
$
|
(1,047,723)
|
State income taxes, net of federal benefit
|
|
|
(39,557)
|
|
|
(33,050)
|
|
|
(44,654)
|
Valuation allowance
|
|
|
120,880
|
|
|
-
|
|
|
-
|
Federal tax reform
|
|
|
(42,033)
|
|
|
-
|
|
|
-
|
Impairment charge after enactment of federal tax reform
|
|
|
114,293
|
|
|
-
|
|
|
-
|
IRC Section 382 limitation
|
|
|
(45,899)
|
|
|
259,494
|
|
|
-
|
Non-deductible convertible debt expenses
|
|
|
-
|
|
|
174,071
|
|
|
-
|
Goodwill impairment
|
|
|
-
|
|
|
-
|
|
|
305,820
|
Market-based equity awards
|
|
|
7,003
|
|
|
8,352
|
|
|
2,690
|
Enacted changes in state tax laws
|
|
|
-
|
|
|
5,020
|
|
|
7,350
|
Other
|
|
|
4,553
|
|
|
(2,163)
|
|
|
2,290
|
Total
|
|
$
|
(482,979)
|
|
$
|
(87,646)
|
|
$
|
(774,227)
|
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 201
7
and 201
6
were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
Deferred income tax assets
|
|
|
|
|
|
|
Net operating loss carryforward
|
|
$
|
828,617
|
|
$
|
1,248,034
|
Derivative instruments
|
|
|
31,567
|
|
|
6,145
|
Asset retirement obligations
|
|
|
16,138
|
|
|
21,398
|
Restricted stock compensation
|
|
|
9,704
|
|
|
12,171
|
EOR credit carryforwards
|
|
|
7,946
|
|
|
7,946
|
Alternative minimum tax credit carryforwards
|
|
|
-
|
|
|
7,847
|
Other
|
|
|
11,549
|
|
|
19,356
|
Total deferred income tax assets
|
|
|
905,521
|
|
|
1,322,897
|
Less valuation allowance
|
|
|
(271,300)
|
|
|
(264,461)
|
Net deferred income tax assets
|
|
|
634,221
|
|
|
1,058,436
|
Deferred income tax liabilities
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
566,747
|
|
|
1,412,781
|
Trust distributions
|
|
|
54,980
|
|
|
94,120
|
Discount on convertible senior notes
|
|
|
12,494
|
|
|
27,224
|
Total deferred income tax liabilities
|
|
|
634,221
|
|
|
1,534,125
|
Total net deferred income tax liabilities
|
|
$
|
-
|
|
$
|
475,689
|
The Company’s July 1, 2016 note exchange transactions triggered an ownership shift within the meaning of Section 382 of the Internal Revenue Code (“IRC”) due to the “deemed share issuance” that resulted from the note exchanges. The ownership shift will limit Whiting’s usage of certain of its net operating losses and tax credits in the future. Accordingly, the Company recognized valuation allowances on its deferred tax assets totaling
$259
million.
In
the third quarter of
2017 there was a partial release of this valuation allowance in the amount of
$41
million
associated with
built-on gains
on
the sale of the FBIR Assets.
As of December 31, 201
7
, the Company had federal net operating loss (“NOL”) carryforwards of
$2.9
billion
, which was net of the IRC Section 382 limitation
. The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the federal NOL will expire
between 2023 and
203
7
, and the state NOLs will expire between 201
8
and 203
7
.
EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed enhanced tertiary recovery methods. As of December 31, 201
7
, the Company
had recognized aggregate EOR credits of $8 million. As a result of the IRC Section 382 limitation in July 2016, the Company recorded a full valuation allowance on these credits
.
The Company
was
subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions.
For 2017, the Company expects to forego bonus depreciation and claim a refund under the Protecting Americans from Tax Hikes Act for its AMT credits and has recognized a
$7
million current benefit.
As of December 31, 201
7
, the Company had
no remaining
AMT credits available to offset future regular federal income taxes.
On December 22, 2017, Congress passed the Tax Cuts and Jobs Act (the “TCJA”). The new legislation significantly changes the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. FASB ASC Topic 740,
Income Taxes
, requires companies to recognize the impact of the changes in tax law in the period of enactment.
The SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used to account for business combinations, however, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 outlines a three-step process to be applied at each reporting period to account for and qualitatively disclose (i) the effects of the change in tax law for which accounting is complete, (ii) provisional amounts (or adjustments to provisional amounts) for the effects of the change in tax law where accounting is not complete, but where a reasonable estimate has been made, and (iii) areas affected by
the change in tax law where a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the TCJA.
Amounts recorded during the year ended December 31, 2017 related to the TCJA principally relate to the reduction in the U.S. corporate income tax rate to 21%, which resulted in (i) income tax expense of
$5
1
million from the revaluation of the Company’s deferred tax assets and liabilities as of the date of enactment and (ii) an income tax benefit totaling $93 million related to a reduction in the Company’s existing valuation allowances. Reasonable estimates were made based on the Company’s analysis of the remeasurement of its deferred tax assets and liabilities and valuation allowances under tax reform. These provisional amounts may be adjusted in future periods if additional information is obtained or further clarification and guidance is issued by regulatory authorities regarding the application of the law.
Other provisions of the TCJA that do not impact 2017, but may impact income taxes in future years include (i) a limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, (ii) a limitation on the usage of NOLs generated after 2017 to 80% of taxable income, (iii) additional limitations on certain meals and entertainment expenses, (iv) the inclusion of performance based compensation in determining the excessive compensation limitation, and (v) the unlimited carryforward of NOLs.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion, or all, of the Company’s deferred tax assets will not be realized.
In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance.
At December 31, 2017, after considering the impact of the federal tax rate reduction
resulting from
the enactment of the
TCJA
,
the Company
had a valuation allowance totaling $
27
1
million, comprised of
$138
million of NOL carryforward limitations under Section 382 of the IRC,
$8
million of EOR credits, which will expire between 2023 and 2025,
$5
million of
Canadian NOL carryforwards, which will expire between
2034
and
2035, and
$1 million of short-term capital loss carryforwards that are not expected to be realized
.
In addition, the Company has determined that it does not expect the carrying value of its deferred tax assets to be realized, and accordingly, has recorded a full valuation allowance totaling
$11
9
million on its net deferred tax assets as of December 31, 2017.
At December 31, 2016, the Company had a valuation allowance totaling $265 million, comprised of
$251
million of NOL carryforward limitations under Section 382 of the IRC,
$8
million of EOR credits, and
$5
million of Canadian NOL carryforwards.
These valuation allowances
were
recorded because the Company determined it was more likely than not that the benefit from these deferred tax assets
would
not be realized due to the
IRC Section 382 limitation on the NOL carryforward and the EOR credit carryforwards, as well as the
divestiture of all foreign operations.
In 2014, the Company acquired
Kodiak
Oil & Gas Corp. (“Kodiak”)
, which is a Canadian entity that is disregarded for U.S. tax purposes. Kodiak holds an interest in Whiting Resources Corporation, a U.S. entity. Canadian taxes have not been recognized
as the tax basis exceeds the book basis in the associated assets.
U.S. income taxes on Kodiak and its subsidiary, Whiting Resources Corporation, however, have been fully recognized on their cumulative losses to date.
The
TCJA
provides for a one-time
“
deemed repatriation
”
of accumulated foreign earnings for the year ended December 31, 2017. We do not expect to pay U.S. federal cash taxes on the deemed repatriation due to an estimated accumulated deficit in foreign earnings for tax purposes.
As of
December 31,
2017
and 2016,
the
C
ompany did
not
have any uncertain tax positions.
During the year ended December 31, 2016, t
he Company
reversed
an
unrecognized tax benefit of
$170,000
as a result of the IRC Section 382 limitation, which resulted in the Company recording a full valuation allowance on its EOR credits, the underlying asset generating the uncertain tax position
. For the years ended December 31, 201
7
, 201
6
and 201
5
, the Company did
not
recognize any interest or penalties with respect to unrecognized tax benefits,
nor
did the Company have any such interest or penalties previously accrued. The Company believes that it is reasonably possible that no increases to unrecognized tax benefits will occur in the next twelve months.
The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 201
4
through 201
7
tax years generally remain subject to examination by federal and state tax authorities. Additionally, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 201
2
through 201
7
tax years.
11.
EARNINGS PER SHARE
The reconciliations between basic and diluted loss per share are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Basic Loss Per Share
(1)
|
|
|
|
|
|
|
|
|
|
Net loss attributable to common shareholders
|
|
$
|
(1,237,648)
|
|
$
|
(1,339,102)
|
|
$
|
(2,219,182)
|
Weighted average shares outstanding
|
|
|
90,683
|
|
|
62,967
|
|
|
48,868
|
Loss per common share
|
|
$
|
(13.65)
|
|
$
|
(21.27)
|
|
$
|
(45.41)
|
|
|
|
|
|
|
|
|
|
|
Diluted Loss Per Share
(1)
|
|
|
|
|
|
|
|
|
|
Adjusted net loss attributable to common shareholders
|
|
$
|
(1,237,648)
|
|
$
|
(1,339,102)
|
|
$
|
(2,219,182)
|
Weighted average shares outstanding
|
|
|
90,683
|
|
|
62,967
|
|
|
48,868
|
Loss per common share
|
|
$
|
(13.65)
|
|
$
|
(21.27)
|
|
$
|
(45.41)
|
_____________________
|
(1)
|
|
All share and per share numbers have been retroactively adjusted for the 2015 and 2016 periods to reflect the Company’s one-for-four reverse stock split in November 2017, as described in Note 8 to these consolidated financial statements.
|
For the year ended December 31, 2017, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of
509,744
shares of service-based restricted stock,
22,946 shares of
market-based restricted stock
and
1,083
stock options.
In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the effect of
554,580
common shares for stock options that were out-of-the-money and
5,447
shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2017.
For the year ended December 31, 2016, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of (i)
10,820,758
shares issuable for convertible notes prior to their conversions under the if-converted method, (ii)
444,646
shares of service-based restricted stock, and (iii)
1,158
stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 excludes the effect of
479,452
common shares for stock options that were out-of-the-money and
92,548
shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2016.
For the year
ended December 31, 2015, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive effect of
129,034
shares of
service-based
restricted stock and
21,391
stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2015 excludes the effect of
169,069
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2015 and
128,689
common shares for stock options that were out-of-the-money.
Refer to the “Stock-Based Compensation” footnote for further information on the Company’s restricted stock and stock options.
As discussed in the “Long-Term Debt” footnote, the Company has the option to settle the 2020 Convertible Senior Notes with cash, shares of common stock or any combination thereof upon conversion. Based on the
current
conversion price, the entire outstanding principal amount of the 2020 Convertible Senior Notes as of December 31, 2017 would be convertible into
approximately
3.6
million
shares of the Company’s common stock. However, the Company’s intent is to settle the principal amount of the notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (the “conversion spread”) is considered in the diluted earnings per share computation under the treasury stock method. As of December 31, 2017, 2016 and 2015, the conversion value did not exceed the principal amount of the notes. Accordingly, there was no impact to diluted earnings per share or the related disclosures for those periods.
1
2
. COMMITMENTS AND CONTINGENCIES
The table below shows the Company’s minimum future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 201
7
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
|
Total
|
Non-cancelable leases
|
|
$
|
7,502
|
|
$
|
6,399
|
|
$
|
802
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
14,703
|
Drilling rig contracts
|
|
|
19,442
|
|
|
300
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
19,742
|
Pipeline transportation agreements
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
11,481
|
|
|
38,326
|
Total
|
|
$
|
32,313
|
|
$
|
12,068
|
|
$
|
6,171
|
|
$
|
5,369
|
|
$
|
5,369
|
|
$
|
11,481
|
|
$
|
72,771
|
Non-cancelable Leases
—The Company leases
222,900
square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019,
44,500
square feet of office space in Midland, Texas expiring in 2020
,
and
36,500
square feet of office space in Dickinson, North Dakota expiring in 20
20
. Rental expense for 201
7
, 201
6
and 201
5
amounted to
$8
million,
$9
million and
$9
million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 201
7
are shown in the table above.
The Company has sublet the majority of its office space in Midland, Texas to a third party for the remaining lease term. The offsetting rental income has not been included in the table above.
Drilling Rig Contracts
—As of December 31, 201
7
, the Company had
three
drilling
rigs under long-term contract
s, of which two drilling rigs expire in 2018 and one expires in 2019
. The Company’s minimum drilling commitments under the terms of
these
contracts as of December 31, 201
7
are shown in the table above. As of December 31, 201
7
, early termination of the
se
contracts would require termination penalties of
$11
million, which would be in lieu of paying the remaining drilling commitments under these contracts. During 201
7
, 201
6
and 201
5
, the Company made payments of
$29
million,
$31
million and
$18
million, respectively, under these long-term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense.
Pipeline Transportation Agreements—
T
he Company has
three
pipeline transportation agreements with
two
different suppliers
, expiring in
2022,
2024 and 2025
. Under two of these contracts
,
the Company
has committed to pay fixed monthly reservation fees on dedicated pipelines
from its Redtail field
for natural gas and NGL transportation capacity, plus a variable charge based on actual transportation volumes.
These fixed monthly reservation fees totaling approximately $
38
million have been included in the table above.
The remaining contract contains a commitment to transport a minimum volume of crude oil via a certain oil gathering system or else pay for any deficiencies at a price stipulated in the contract.
Although minimum
annual
quantities are specified in the agreement, the actual
oil
volumes
transported
and their corresponding unit prices are variable over the term of the contract. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 201
7
, the Company estimated the minimum future commitments under
this
transportation
agreement to approximate
$17
million through 2022.
During 201
7
, 201
6
and 201
5
, transportation of crude oil, natural gas
and
NGLs under these contracts amounted to
$7
million,
$5
million and
$3
million, respectively.
Purchase Contracts
—The Company has
one
take-or-pay purchase agreement
which
expires
in
2020
, whereby
the Company has committed to buy certain volumes of water for use in the fracture stimulation process of wells
the Company completes
in its Redtail field. Under the terms of the agreement, the Company is obligated to purchase a minimum volume of water or else pay for any deficiencies at the price stipulated in the contract. Although minimum daily quantities are specified in the agreement, the actual water volumes purchased and their corresponding unit prices are variable over the term of the contract. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 201
7
, the Company estimated the minimum future commitments under
this
purchase agreement to approximate
$23
million through 2020.
As a result of the Company’s reduced development operations at its Redtail field, Whiting expects to make periodic deficiency payments under this contract during the remaining term.
During 201
7 and
201
6,
purchases of water amounted to
$22
million
and
$1
million, respectivel
y, which included insignificant deficiency payments for the year ended December 31, 2017
.
Water Disposal Agreement
—The Company has
one
water disposal agreement which expires in 2024, whereby it has contracted for the transportation and disposal of the produced water from
its
Redtail field. Under the terms of the agreement, the Company is obligated to provide a minimum volume of produced water or else pay for any deficiencies at the price stipulated in the contract. Although minimum monthly quantities are specifi
ed in the agreement
, the actual water volumes disposed of and their corresponding unit prices are variable
over the term of the contract. As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above. As of December 31, 201
7
, the Company estimated the minimum future commitments under this disposal agreement to approximate
$122
m
illion through 2024.
As a result of the Company’s reduced development operations at its Redtail field, Whiting has made and expects to make periodic deficiency payments under this contract. During 2017 and 2016, transportation and disposal of produced water amounted to
$16
and
$8
million, respectively, which includes
$4
million and
$2
million of deficiency payments, respectively.
There were
no
water disposal costs incurred under this contract
during
2015.
Delivery Commitments
—The Company has various physical delivery contracts which require the Company to deliver fixed volumes of crude oil.
One
of these delivery commitments
became effective on June 1, 2017 upon completion of the Dakota Access Pipeline, and it
is tied to crude oil production
from
Whiting’s Sanish field in Mountrail County, North Dakota
. Under the terms of the agreement, Whiting has committed to deliver
15
MBbl/d for a term of
seven
years.
The Company believes its production and reserves
at the Sanish field
are sufficient to fulfill th
is
delivery commitment
, and therefore expects to avoid any payments for deficiencies under this contract
.
The remaining
two
delivery contracts
are
tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado.
On February 1, 2018, the Company paid
$61
million to the counterparty to
one
of these contracts to settle all future minimum volume commitments under the agreement.
As of December 31, 201
7
,
these contracts contain remaining
delivery commitments of
14.8
MMBbl,
16.0
MMBbl and
4.1
MMBbl of crude oil
for the years ended December 31, 201
8
through 2020, respectively
, which commitments have been reduced to reflect the contract settlement on February 1, 2018
. The Company has determined that it is not probable that future oil production from its Redtail field will be sufficient to meet the minimum volum
e requirements specified in
these
physical delivery contract
s
, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes.
During
2017, 2016 and
2015, total deficiency payments under these contracts amounted to
$66
million,
$43
million and
$15
million
, respectively
. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
Litigation
—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. The Company accrues a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations. Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 201
7
or 201
6
.
1
3
.
CAPITALIZED EXPLORATORY WELL COSTS
Exploratory well costs that are incurred and expensed in the same annual period have not been included in the table below. The net changes in capitalized exploratory well costs were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Beginning balance at January 1
|
|
$
|
-
|
|
$
|
-
|
|
$
|
14,293
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
|
13,894
|
|
|
-
|
|
|
54,707
|
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
|
|
-
|
|
|
-
|
|
|
(63,352)
|
Capitalized exploratory well costs charged to expense
|
|
|
-
|
|
|
-
|
|
|
(5,648)
|
Ending balance at December 31
|
|
$
|
13,894
|
|
$
|
-
|
|
$
|
-
|
At December 31, 201
7
, the Company had
no
costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.
1
4
.
SUBSEQUENT EVENTS
Redemption of
2019 Senior N
otes
—On December
27
, 2017, the trustee under the indenture governing the Company’s 2019 Senior Notes provided notice to the holders of such notes that Whiting elected to redeem all of the remaining
$961
million aggregate principal amount of the 2019 Senior Notes on January 26, 2018, and on that date, Whiting paid
$
1.0
b
illion consisting of the
102.976
%
redemption
price plus all accrued and unpaid interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes
and borrowings under its credit agreement
.
Termination of Redtail Delivery Commitment
—On February 1, 2018, the Company paid
$61
million to the counterparty to one of its
physical
delivery contracts for crude oil
production
at its Redtail field in Weld County, Colorado to settle all future minimum commitments under this agreement.
Refer to the “Commitments and Contingencies” footnote for further information on the Company’s delivery commitments.
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Oil and Gas Producing Activities
Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
Proved oil and gas properties
|
|
$
|
10,911,167
|
|
$
|
12,347,400
|
Unproved oil and gas properties
|
|
|
382,483
|
|
|
883,451
|
Accumulated depletion
|
|
|
(4,185,301)
|
|
|
(4,170,237)
|
Oil and gas properties, net
|
|
$
|
7,108,349
|
|
$
|
9,060,614
|
The Company’s oil and gas activities for 201
7
, 201
6
and 201
5
were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Development
(1)
|
|
$
|
799,462
|
|
$
|
518,585
|
|
$
|
2,137,755
|
Proved property acquisition
|
|
|
4,075
|
|
|
797
|
|
|
-
|
Unproved property acquisition
|
|
|
17,629
|
|
|
3,642
|
|
|
29,050
|
Exploration
|
|
|
50,218
|
|
|
45,846
|
|
|
192,422
|
Total
|
|
$
|
871,384
|
|
$
|
568,870
|
|
$
|
2,359,227
|
_____________________
|
(1)
|
|
Development costs include
non-cash
downward adjustments
to oil and gas properties of
$
45
million
for 2017 and
non-cash additions to oil and gas properties
of
$
15
million and
$
48
million
for 2016 and 2015
, respectively, which relate to estimated future plugging and abandonment
costs
of the Company’s oil and gas wells.
|
Oil and Gas Reserve Quantities
For all years presented,
the Company’s
independent petroleum engineers independently estimated all of the proved reserve quantities included in this Annual Report on Form 10-K. In connection with
the
external petroleum engineers performing their independent reserve estimations,
Whiting
furnish
es
them with the following information
for their
review: (
i
) technical support data, (
ii
) technical analysis of geologic and engineering support information, (
iii
) economic and production data
,
and (
iv
)
the Company’s
well ownership interests. The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated
100%
of
the Company’s
estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 201
7
. Proved reserve estimates included herein conform to the definitions prescribed by the SEC. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
As of December 31, 201
7
, all of the Company’s oil and gas reserves are attributable to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 201
5
, 201
6
and 201
7
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBOE)
|
Proved reserves
|
|
|
|
|
|
|
|
|
Balance—January 1, 2015
|
|
643,629
|
|
54,684
|
|
492,020
|
|
780,316
|
Extensions and discoveries
|
|
131,134
|
|
26,074
|
|
192,575
|
|
189,304
|
Sales of minerals in place
|
|
(33,767)
|
|
(3,240)
|
|
(96,891)
|
|
(53,156)
|
Production
|
|
(47,176)
|
|
(5,539)
|
|
(41,129)
|
|
(59,570)
|
Revisions to previous estimates
|
|
(97,143)
|
|
40,968
|
|
119,085
|
|
(36,327)
|
Balance—December 31, 2015
|
|
596,677
|
|
112,947
|
|
665,660
|
|
820,567
|
Extensions and discoveries
|
|
48,208
|
|
12,980
|
|
93,070
|
|
76,700
|
Sales of minerals in place
|
|
(95,294)
|
|
(16,795)
|
|
(13,797)
|
|
(114,388)
|
Production
|
|
(33,992)
|
|
(6,642)
|
|
(41,438)
|
|
(47,540)
|
Revisions to previous estimates
|
|
(120,832)
|
|
(997)
|
|
12,164
|
|
(119,802)
|
Balance—December 31, 2016
|
|
394,767
|
|
101,493
|
|
715,659
|
|
615,537
|
Extensions and discoveries
|
|
30,076
|
|
14,512
|
|
82,391
|
|
58,320
|
Sales of minerals in place
|
|
(42,137)
|
|
(5,263)
|
|
(18,116)
|
|
(50,419)
|
Purchases of minerals in place
|
|
157
|
|
29
|
|
283
|
|
233
|
Production
|
|
(29,261)
|
|
(6,978)
|
|
(41,261)
|
|
(43,115)
|
Revisions to previous estimates
|
|
(16,019)
|
|
35,156
|
|
107,521
|
|
37,056
|
Balance—December 31, 2017
|
|
337,583
|
|
138,949
|
|
846,477
|
|
617,612
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
333,593
|
|
28,935
|
|
298,237
|
|
412,234
|
December 31, 2015
|
|
298,444
|
|
55,437
|
|
300,631
|
|
403,986
|
December 31, 2016
|
|
183,165
|
|
51,888
|
|
337,860
|
|
291,363
|
December 31, 2017
|
|
179,829
|
|
76,957
|
|
473,829
|
|
335,758
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
310,036
|
|
25,749
|
|
193,783
|
|
368,082
|
December 31, 2015
|
|
298,233
|
|
57,510
|
|
365,029
|
|
416,581
|
December 31, 2016
|
|
211,602
|
|
49,605
|
|
377,799
|
|
324,174
|
December 31, 2017
|
|
157,754
|
|
61,992
|
|
372,648
|
|
281,854
|
Notable changes in proved reserves for the year ended December 31, 201
7
included
the following
:
|
·
|
|
Extensions and discoveries.
In 2017, t
otal extensions and discoveries of
58.3
MMBOE were primarily attributable to successful drilling in the Williston Basin.
Both the n
ew wells drilled in th
is
area as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.
|
|
·
|
|
Sales of minerals in place.
S
ales of minerals in place
totaled
50.4
MMBOE
during 2017 and
were primarily attributable to
the disposition of the FBIR Assets
as further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements
.
|
|
·
|
|
Revisions to previous estimates.
In 201
7
, revisions to previous estimates
in
creased proved developed and undeveloped reserves by a net amount of
37.1
MMBOE. Included in these revisions were
(i) 88.7
MMBOE of
up
ward adjustments caused by
higher
crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 201
7
as compared to December 31, 201
6
and (ii)
51.6
MMBOE of
down
ward adjustments
primarily
attributable to reservoir analysis and well performance
in the Redtail field
.
|
Notable changes in proved reserves for the year ended December 31, 201
6
included
the following
:
|
·
|
|
Extensions and discoveries.
In 2016, t
otal extensions and discoveries of
76.7
MMBOE were primarily attributable to successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.
|
|
·
|
|
Sales of minerals in place.
S
ales of minerals in place
totaled
114.4
MMBOE
during 2016 and
were primarily attributable to the disposition of
the North Ward Estes Properties
as further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements
.
|
|
·
|
|
Revisions to previous estimates.
In 201
6
, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of
119.8
MMBOE. Included in these revisions were (i)
121.6
MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 201
6
as compared to December 31, 201
5
and (ii)
1.8
MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
|
Notable changes in proved reserves for the year ended December 31, 2015 included
the following
:
|
·
|
|
Extensions and discoveries.
In 2015, total extensions and discoveries of 189.3 MMBOE were primarily attributable to successful drilling in the Williston Basin and DJ Basin. Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.
|
|
·
|
|
Sales of minerals in place.
S
ales of minerals in place
totaled
53.2 MMBOE
during 2015 and
were primarily attributable to the disposition of various non-core properties across all
of the Company’s
operating areas as further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements
.
|
|
·
|
|
Revisions to previous estimates.
In 2015, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 36.3 MMBOE. Included in these
revisions were (i)
82.3
MMBOE of downward adjustments caused by lower crude oil, NGL and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2015 as compared to December 31, 2014 and (ii)
46.0
MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
|
Standardized Measure of Discounted Future Net Cash Flows
The
S
tandardized
M
easure relating to proved oil and gas reserves and changes in
the S
tandardized
M
easure relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932,
Extractive Activities
—
Oil and Gas
. Future cash
inflows as of December 31, 201
7
, 201
6
and 201
5
were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 201
7
, 201
6
and 201
5
, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the
S
tandardized
M
easure. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
The
S
tandardized
M
easure relating to proved oil and natural gas reserves is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Future cash flows
|
|
$
|
19,635,532
|
|
$
|
16,946,961
|
|
$
|
29,339,528
|
Future production costs
|
|
|
(7,874,590)
|
|
|
(7,266,435)
|
|
|
(12,344,463)
|
Future development costs
|
|
|
(3,022,841)
|
|
|
(3,605,977)
|
|
|
(6,166,397)
|
Future income tax expense
(1)
|
|
|
(474,646)
|
|
|
-
|
|
|
(388,072)
|
Future net cash flows
|
|
|
8,263,455
|
|
|
6,074,549
|
|
|
10,440,596
|
10% annual discount for estimated timing of cash flows
|
|
|
(4,395,897)
|
|
|
(3,376,463)
|
|
|
(5,866,225)
|
Standardized measure of discounted future net cash flows
|
|
$
|
3,867,558
|
|
$
|
2,698,086
|
|
$
|
4,574,371
|
_____________________
|
(1)
|
|
Based on the 12-month average oil and natural gas prices used in the computation of pre-tax PV10% as of December 31, 2016, Whiting’s future net income generated over the life of its proved reserves is expected to be less than its NOL carryforward deductions and therefore, under the Standardized Measure, there is no deduction for federal or state income taxes.
|
Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end. If the effects of hedging transactions were included in the computation, then undiscounted future cash
inflows would have increased by
$77
million and $71
million in 2016 and 2015, respectively
, and would have had no impact on
undiscounted future cash
inflows
in 2017.
The changes in the
S
tandardized
M
easure relating to proved oil and natural gas reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Beginning of year
|
|
$
|
2,698,086
|
|
$
|
4,574,371
|
|
$
|
10,843,420
|
Sale of oil and gas produced, net of production costs
|
|
|
(991,069)
|
|
|
(781,132)
|
|
|
(1,354,054)
|
Sales of minerals in place
|
|
|
(312,346)
|
|
|
(1,434,545)
|
|
|
(1,414,511)
|
Net changes in prices and production costs
|
|
|
994,749
|
|
|
(1,594,183)
|
|
|
(11,001,949)
|
Extensions, discoveries and improved recoveries
|
|
|
437,459
|
|
|
730,396
|
|
|
2,078,071
|
Previously estimated development costs incurred during the period
|
|
|
542,746
|
|
|
477,830
|
|
|
1,625,160
|
Changes in estimated future development costs
|
|
|
50,215
|
|
|
1,722,897
|
|
|
102,499
|
Purchases of minerals in place
|
|
|
1,748
|
|
|
-
|
|
|
-
|
Revisions of previous quantity estimates
|
|
|
277,967
|
|
|
(1,502,416)
|
|
|
(966,713)
|
Net change in income taxes
|
|
|
(101,806)
|
|
|
47,431
|
|
|
3,578,106
|
Accretion of discount
|
|
|
269,809
|
|
|
457,437
|
|
|
1,084,342
|
End of year
|
|
$
|
3,867,558
|
|
$
|
2,698,086
|
|
$
|
4,574,371
|
Future net revenues included in the
S
tandardized
M
easure relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 201
7
, 201
6
and 201
5
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
Oil (per Bbl)
|
|
$
|
47.16
|
|
$
|
35.60
|
|
$
|
43.07
|
NGLs (per Bbl)
|
|
$
|
14.74
|
|
$
|
10.09
|
|
$
|
15.53
|
Natural Gas (per Mcf)
|
|
$
|
1.97
|
|
$
|
2.61
|
|
$
|
2.83
|
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended
December 31, 201
7
and 201
6
(in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
2017
|
|
2017
|
|
2017
|
|
2017
|
Oil, NGL and natural gas sales
|
|
$
|
371,317
|
|
$
|
311,515
|
|
$
|
324,191
|
|
$
|
474,412
|
Gross profit (loss)
(1)
|
|
$
|
8,461
|
|
$
|
(21,855)
|
|
$
|
(6,769)
|
|
$
|
62,296
|
Net loss
|
|
$
|
(86,971)
|
|
$
|
(65,981)
|
|
$
|
(286,432)
|
|
$
|
(798,278)
|
Basic loss per share
(2)
|
|
$
|
(0.96)
|
|
$
|
(0.73)
|
|
$
|
(3.16)
|
|
$
|
(8.80)
|
Diluted loss per share
(2)
|
|
$
|
(0.96)
|
|
$
|
(0.73)
|
|
$
|
(3.16)
|
|
$
|
(8.80)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
2016
|
|
2016
|
|
2016
|
|
2016
|
Oil, NGL and natural gas sales
|
|
$
|
289,697
|
|
$
|
337,036
|
|
$
|
315,554
|
|
$
|
342,695
|
Gross loss
(1)
|
|
$
|
(162,898)
|
|
$
|
(98,978)
|
|
$
|
(83,369)
|
|
$
|
(45,205)
|
Net loss
|
|
$
|
(171,758)
|
|
$
|
(301,046)
|
|
$
|
(693,055)
|
|
$
|
(173,265)
|
Basic loss per share
(2)
|
|
$
|
(3.36)
|
|
$
|
(5.33)
|
|
$
|
(9.89)
|
|
$
|
(2.34)
|
Diluted loss per share
(2)
|
|
$
|
(3.36)
|
|
$
|
(5.33)
|
|
$
|
(9.89)
|
|
$
|
(2.34)
|
_____________________
|
(1)
|
|
Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.
|
|
(2)
|
|
All per share amounts have been retroactively
adjusted
to reflect the Company's one-for-four reverse stock split
in November 2017, as
described in Note
8
to these consolidated financial statements.
|
******