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 (formerly Kodiak Oil & Gas (USA) Inc.) 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 our
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.
Reclassification
s
—
The Company changed the presentation of its consolidated statements of operations and reclassified certain prior year balances to conform to such presentation.
The
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 relates to a deposit received in connection with the sale of our 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 “Subsequent Events” 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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|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Cash and cash equivalents
|
|
$
|
55,975
|
|
$
|
16,053
|
Restricted cash
|
|
|
17,250
|
|
|
-
|
Total cash, cash equivalents and restricted cash
|
|
$
|
73,225
|
|
$
|
16,053
|
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
6
and 201
5
, the Company had an allowance for doubtful accounts of
$10
million and
$12
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 $33 million and $69 million as of
December 31, 2016 and 2015, 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 $8 million as of December 31, 2016 and 2015
.
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
that were not being developed due to depressed oil and gas prices totaled $1.6 billion and $629 million for the years ended December 31, 2015 and 2014, 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
6
, 201
5
and 201
4
, the Company capitalized interest of
$0.1
million,
$4
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 $73 million, $135 million and $136 million for the years ended December 31, 2016, 2015 and 2014, 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 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.
Enhanced recovery activities
. The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Acquisition costs of tertiary injectants, such as purchased CO
2
, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred. After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project. As CO
2
is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO
2
recycling costs are expensed as incurred. Likewise costs incurred to maintain reservoir pressure are also 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 combination
s
. 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. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings.
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.
Derivative Instruments
—The Company enters into derivative contracts, primarily costless collars and swaps
as well as crude oil sales and delivery contracts
, 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
11,677,500
Trust I units and
18,400,000
Whiting USA Trust II (“Trust II”)
units, and is amortized to income based on the unit-of-production method. In January 2015, the deferred gain on sale related to Trust I was fully amortized in connection with the termination of the trust’s net profits interest.
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
6
and 201
5
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 restricted stock and stock option awards to employees and non-employee directors. The Company determines compensation expense for awards granted under these plans based on the grant date fair value net of estimated forfeitures, and such expense is recognized on a straight-line basis over the requisite service period of the award. 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 2016, 2015 and 2014 were
$8
million,
$12
million and
$9
million, respectively. Employees vest in employer contributions at
20%
per year of completed service.
A
cquisition 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 available 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 available 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 table
s
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
6 and 2014. 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, 2016:
|
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|
|
|
|
Tesoro Crude Oil Co
|
|
|
|
|
|
15%
|
Jamex Marketing LLC
|
|
|
|
|
|
12%
|
|
|
|
|
|
|
|
Year Ended December 31, 2014:
|
|
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|
|
|
|
Plains Marketing LP
|
|
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|
|
|
17%
|
Shell Trading US
|
|
|
|
|
|
10%
|
Bridger Trading LLC
|
|
|
|
|
|
10%
|
Commodity derivative contracts held by the Company are with
seven
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
6
, outstanding derivative contracts
with JP Morgan Chase Bank, N.A. and Wells Fargo Bank, N.A. represented
66%
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 ASU 2015-1
4, ASU 2016-08, ASU 2016-10,
ASU 2016-12
and ASU 2016-20
, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. These ASUs are effective for fiscal years, and interim periods within those years, beginning after December 31, 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 plans to adopt these ASUs effective January 1, 2018. Although the Company is still in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated financial statements other than additional disclosures.
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 a
n
increase in the assets and liabilities recorded on its consolidated balance sheet. As of December 31, 2016, the Company had approximately $97 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, classification of awards as either equity or liabilities and classification in the statement of cash flows. ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively. Early adoption is permitted. The Company
does not anticipate that the adoption of ASU 2016-09 will have a significant
impact on its consolidated financial statements
, as the Company will record a full valuation allowance on the excess tax benefits that will be recognized upon adoption of this ASU as a result of
the Internal Revenue Code Section 382 limitation that was triggered in 2016
.
Refer to the “Income Taxes” footnote for further information.
In November 2016, the FASB issued Accounting Standards Update No. 2016-18,
Statement of Cash Flows
:
Restricted Cash
(“ASU 2016-18”). This ASU amends ASC Topic 230,
Statement of Cash Flows
, to clarify guidance on the classification and presentation of restricted cash in the statement of cash flows. ASU 2016-18 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and must be applied retrospectively. Early adoption is permitted. The Company elected to adopt ASU 2016-18 as of December 31, 2016 on a retrospective basis, and as a result has included its restricted cash with cash and cash equivalents in the statement of cash flows. There was no impact to the statements of cash flows for the years ended December 31, 2015 and 2014 as the Company had no restricted cash balances during those periods.
2.
OIL AND GAS PROPERTIES
Net capitalized costs related to
the Company’s
oil and gas
producing activities
at
December 31, 201
6
and 201
5
are as follows
(in thousands)
:
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|
|
December 31,
|
|
|
2016
|
|
2015
|
Proved leasehold costs
|
|
$
|
3,330,928
|
|
$
|
3,206,237
|
Unproved leasehold costs
|
|
|
392,484
|
|
|
689,754
|
Costs of completed wells and facilities
|
|
|
9,016,472
|
|
|
9,503,020
|
Wells and facilities in progress
|
|
|
490,967
|
|
|
505,514
|
Total oil and gas properties, successful efforts method
|
|
|
13,230,851
|
|
|
13,904,525
|
Accumulated depletion
|
|
|
(4,170,237)
|
|
|
(3,279,156)
|
Oil and gas properties, net
|
|
$
|
9,060,614
|
|
$
|
10,625,369
|
3. ACQUISITIONS AND DIVESTITURES
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 has 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 Contingent Payment will be made at the option of the buyer either in cash on July 31, 2018 or in the form of a secured promissory note, accruing interest at
8%
per annum with a maturity date of July 29, 2022. The Company has determined that this Contingent Payment is an embedded derivative and has reflected it at fair value in the consolidated financial statements. The fair value of the Contingent Payment as of the closing date of this sale transaction was
$39
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, 201
6
.
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.
2014 Acquisitions
On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”). Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received
0.177
of a share of Whiting common stock in exchange for each share of Kodiak common stock they owned. Total consideration for the Kodiak Acquisition was $1.8 billion, consisting of
47,546,139
Whiting common shares issued at the market price of
$37.25
per share on the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting.
The aggregate purchase price of the transaction was
$4.3
billion,
which included
the assumption of Kodiak’s outstanding debt of
$2.5
billion as of December 8, 2014 and the net cash acquired of
$19
million.
Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in the Williston Basin region of the United States. As a result of the Kodiak Acquisition, Whiting acquired approximately
327,000
gross (
178,000
net) acres located primarily in North Dakota, including interests in
778
producing oil and gas wells and undeveloped acreage. Approximately
10,000
of the net acres acquired were located in Wyoming and Colorado.
The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations. Transaction costs relating to the Kodiak Acquisition were expensed as incurred. The allocation of the purchase price has been finalized, and is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed
on the acquisition date using currently available information.
The consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date are as follows (in thousands):
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|
|
Consideration:
|
|
|
|
Fair value of Whiting’s common stock issued
(1)
|
|
$
|
1,771,094
|
Fair value of Kodiak restricted stock units assumed by Whiting
(2)
|
|
|
9,596
|
Fair value of Kodiak options assumed by Whiting
|
|
|
7,523
|
Total consideration
|
|
$
|
1,788,213
|
|
|
|
|
Fair value of liabilities assumed:
|
|
|
|
Accounts payable trade
|
|
$
|
18,390
|
Accrued capital expenditures
|
|
|
97,848
|
Revenues and royalties payable
|
|
|
57,423
|
Accrued interest
|
|
|
18,070
|
Accrued liabilities and other
|
|
|
43,563
|
Taxes payable
|
|
|
12,807
|
Long-term debt
|
|
|
2,500,875
|
Deferred tax liability
|
|
|
31,034
|
Asset retirement obligations
|
|
|
8,646
|
Other long-term liabilities
|
|
|
15,735
|
Amount attributable to liabilities assumed
|
|
$
|
2,804,391
|
|
|
|
|
Fair value of assets acquired:
|
|
|
|
Cash and cash equivalents
|
|
$
|
18,879
|
Accounts receivable trade, net
|
|
|
215,654
|
Derivative assets
|
|
|
85,718
|
Prepaid expenses and other
|
|
|
8,523
|
Oil and gas properties, successful efforts method:
|
|
|
|
Proved properties
|
|
|
2,266,607
|
Unproved properties
|
|
|
1,000,396
|
Other property and equipment
|
|
|
11,347
|
Deferred tax asset
|
|
|
106,758
|
Other long-term assets
|
|
|
4,950
|
Amount attributable to assets acquired
|
|
$
|
3,718,832
|
Goodwill
|
|
$
|
873,772
|
_____________________
|
(1)
|
|
47,546,139
shares of Whiting common stock at
$37.25
per share (closing price as of December 5, 2014), based on Kodiak’s
268,622,497
common shares outstanding at closing.
|
|
(2)
|
|
257,601
shares of Whiting common stock issued at
$37.25
per share (closing price as of December 5, 2014), based on Kodiak’s
1,455,409
restricted stock units held by employees as of December 8, 2014.
|
Goodwill recognized as a result of the Kodiak Acquisition totaled $874 million,
none
of which was deductible for income tax purposes. Goodwill was primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including the employment of optimized completion techniques on Kodiak's undrilled acreage which improved hydrocarbon recovery, the realization of savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced oil and gas technical personnel.
During the third quarter of 2015, the Company determined that the goodwill recognized as a result of the Kodiak Acquisition had become fully impaired and wrote its carrying value down to
zero
. Refer to the “Fair Value Measurements” footnote for further information regarding goodwill impairment.
The changes in the carrying amount of goodwill as of December 31, 201
5
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Carrying Amount
|
|
Accumulated Impairment Losses
|
|
Net Carrying Amount
|
Balance, January 1, 2015
|
|
$
|
875,676
|
|
$
|
-
|
|
$
|
875,676
|
Adjustments to previously recorded goodwill
|
|
|
(1,904)
|
|
|
-
|
|
|
(1,904)
|
Impairment losses
|
|
|
-
|
|
|
(873,772)
|
|
|
(873,772)
|
Balance, December 31, 2015
|
|
$
|
873,772
|
|
$
|
(873,772)
|
|
$
|
-
|
The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately
$46
million of revenue and
$17
million of net income, have been included in Whiting’s consolidated statements of operations for the year ended December 31, 2014.
2014 Divestitures
In March 2014, the Company completed the sale of approximately
49,900
gross (
41,000
net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas fo
r aggregate sales proceeds of
$76
million resulting in a pre-tax gain on sale of
$12
million.
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined results of operations for the year ended December 31, 2014 are derived from the historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred on January 1, 2013
(in thousands, except per share data)
.
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
2014
|
Total operat
ing
revenues
and other income
|
|
$
|
4,141,046
|
Net income available to common shareholders
|
|
$
|
362,376
|
Earnings per common share:
|
|
|
|
Basic
|
|
$
|
2.18
|
Diluted
|
|
$
|
2.17
|
The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2014 were adjusted to exclude
$86
million of acquisition-related costs incurred by Whiting and Kodiak.
The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are they indicative of future results of operations. The unaudited pro forma combined financial information does not reflect future events that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating efficiencies from the Kodiak Acquisition.
4. LONG-TERM DEBT
Long-term debt consisted of the following at December 31, 2016 and 2015 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Credit agreement
|
|
$
|
550,000
|
|
$
|
800,000
|
6.5% Senior Subordinated Notes due 2018
|
|
|
275,121
|
|
|
350,000
|
5.0%
Senior Notes due 2019
|
|
|
961,409
|
|
|
1,100,000
|
1.25%
Convertible Senior Notes due 2020
|
|
|
562,075
|
|
|
1,250,000
|
5.75%
Senior Notes due 2021
|
|
|
873,609
|
|
|
1,200,000
|
6.25%
Senior Notes due 2023
|
|
|
408,296
|
|
|
750,000
|
Total principal
|
|
|
3,630,510
|
|
|
5,450,000
|
Unamortized debt discounts and premiums
|
|
|
(71,340)
|
|
|
(203,082)
|
Unamortized debt issuance costs on notes
|
|
|
(23,867)
|
|
|
(49,214)
|
Total long-term debt
|
|
$
|
3,535,303
|
|
$
|
5,197,704
|
The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31, 201
6
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
Long-term debt
|
|
$
|
-
|
|
$
|
275,121
|
|
$
|
1,511,409
|
|
$
|
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
6
had a borrowing base
and
aggregate commitments of
$2.5
billion. As of December 31, 201
6
, the Company had
$1.9
billion of available borrowing capacity, which was net of
$550
million in borrowings and
$11
million in letters of credit 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.
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
6
,
$39
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 and 2015
, the weighted average interest rate on the outstanding principal balance under the credit agreement was
4.0%
and
1.9%
, respectively
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
6
, 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
6
.
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, convertible senior notes and senior subordinated notes outstanding at December 31, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018 Senior
|
|
|
|
2020
|
|
|
|
|
|
|
Subordinated
|
|
2019
|
|
Convertible
|
|
2021
|
|
2023
|
|
|
Notes
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
Outstanding principal (in thousands)
|
|
$
|
275,121
|
|
$
|
961,409
|
|
$
|
562,075
|
|
$
|
873,609
|
|
$
|
408,296
|
Interest rate
|
|
|
6.5%
|
|
|
5.0%
|
|
|
1.25%
|
|
|
5.75%
|
|
|
6.25%
|
Maturity date
|
|
|
Oct 1, 2018
|
|
|
Mar 15, 2019
|
|
|
Apr 1, 2020
|
|
|
Mar 15, 2021
|
|
|
Apr 1, 2023
|
Interest payment dates
|
|
|
Apr 1, Oct 1
|
|
|
Mar 15, Sep 15
|
|
|
Apr 1, Oct 1
|
|
|
Mar 15, Sep 15
|
|
|
Apr 1, Oct 1
|
Make-whole redemption date
(1)
|
|
|
Oct 1, 2016
|
|
|
Dec 15, 2018
|
|
|
N/A
(2)
|
|
|
Dec 15, 2020
|
|
|
Jan 1, 2023
|
_____________________
|
(1)
|
|
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.
|
|
(2)
|
|
The indenture governing our 1.25% Convertible Senior Notes due 2020 do 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” and together with the 2019 Senior Notes and 2021 Senior Notes, the “
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 (i)
$49
million aggregate principal amount of new
6.5%
Convertible Senior Subordinated Notes due 2018 (the “2018 Convertible Senior Subordinated Notes”), (ii)
$97
million aggregate principal amount of new
5.0%
Convertible Senior Notes due 2019 (the “2019 Convertible Senior Notes”), (iii)
$152
million aggregate principal amount of new
5.75%
Convertible Senior Notes due 2021 (the “2021 Convertible Senior Notes”), and (iv)
$179
million aggregate principal amount of new
6.25%
Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes” and together with the 2018 Convertible Senior Subordinated Notes, the 2019 Convertible Senior Notes and the 2021 Convertible Senior Notes, the “New Convertible Notes”).
The redemption provisions, covenants, interest payments and maturity terms applicable to each series of New Convertible Notes were substantially identical to those applicable to the corresponding series of Senior Notes and 2018 Senior Subordinated 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 is 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. The debt discount and transaction costs of
$8
million attributable to the New Convertible Notes issuance were being amortized to interest expense over the respective terms of the notes using the effective interest method.
The New Convertible Notes were convertible, at the option of the holders, into shares of the Company’s common stock at an initial conversion rate of
86.9565
common shares per
$1,000
principal amount of the notes (representing an initial conversion price of
$11.50
per share) for the 2018 Convertible Senior Subordinated Notes, the 2021 Convertible Senior Notes and the 2023 Convertible Senior Notes and an initial conversion rate of
90.9091
common shares per
$1,000
principal amount of the notes (representing an initial conversion price of
$11.00
per share) for the 2019 Convertible Senior Notes. Upon exercise of this option, the holder was entitled to receive an early conversion cash payment as well as a cash payment of all accrued and unpaid interest through the conversion date.
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
41.8
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 Kodiak Acquisition, 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 January 3, 2017, the trustee under the indenture governing the 2018 Senior Subordinated Notes provided notice to the holders of such notes that the Company elected to redeem all of the remaining
$275
million aggregate principal amount of 2018 Senior Subordinated Notes on February 2, 2017, and on that date,
Whiting paid
$281
million consisting 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.
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, 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 an initial conversion rate of
25.6410
shares of Whiting’s common stock per
$1,000
principal amount of the notes, which is equivalent to an initial conversion price of approximately
$39.00
. 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
6
, 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
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 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 of the following at December 31, 201
6 and 2015
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Liability component:
|
|
|
|
|
|
|
Principal
|
|
$
|
562,075
|
|
$
|
1,250,000
|
Less: unamortized note discount
|
|
|
(72,622)
|
|
|
(205,572)
|
Less: unamortized debt issuance costs
|
|
|
(5,988)
|
|
|
(17,277)
|
Net carrying value
|
|
$
|
483,465
|
|
$
|
1,027,151
|
Equity component
(1)
|
|
$
|
136,522
|
|
$
|
237,500
|
|
(1)
|
|
Recorded in additional paid-in capital, net of
$5
million of issuance costs and
$50
million of deferred taxes as of December 31, 2016 and
$5
million of issuance costs and
$88
million of deferred taxes as of De
cember 31, 2015
.
|
Interest expense recognized
on the
2020
Convertible Senior Notes related to the stated interest rate and amortization
of the debt discount totaled $43 million and $44 million for
the year
s
ended December 31, 201
6 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 1.25% Mandatory Convertible Senior Notes due 2020, Series 2 (the “2020 Mandatory Convertible Notes, Series 2”). 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 (i)
$26
million aggregate principal amount of new
6.5%
Mandatory Convertible Senior Subordinated Notes due 2018 (the “2018 Mandatory Convertible Notes”), (ii)
$42
million aggregate principal amount of new
5.0%
Mandatory Convertible Senior Notes due 2019 (the “2019 Mandatory Convertible Notes”), (iii)
$559
million aggregate principal amount of new
1.25%
Mandatory Convertible Senior Notes due 2020, Series 1 (the “2020 Mandatory Convertible Notes, Series 1”, and together with the 2020 Mandatory Convertible Notes, Series 2, the “2020 Mandatory Convertible Notes”), (iv)
$174
million aggregate principal amount of new
5.75%
Mandatory Convertible Senior Notes due 2021 (the “2021 Mandatory Convertible Notes”), and (v)
$163
million aggregate principal amount of new
6.25%
Mandatory Convertible Senior Notes due 2023 (the “2023 Mandatory Convertible Notes” and, together with the 2018 Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2020 Mandatory Convertible Notes and the 2021 Mandatory Convertible Notes, the “Mandatory Convertible Notes”).
The redemption provisions, covenants, interest payments and maturity terms applicable to each series of Mandatory Convertible Notes were substantially identical to those applicable to the corresponding series of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordinated 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 respective terms of the notes using the effective interest method.
Transaction
costs of
$14
million attributable to these note issuances were recorded as a reduction to the carrying value of long-term debt on the consolidated balance sheet and were being amortized to interest expense over the respective terms 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.
The Mandatory Convertible Notes contained mandatory conversion features whereby
four
percent of the aggregate principal amount of the Mandatory Convertible Notes were converted into shares of the Company’s common stock for each day of the
25
trading day
period that commenced on June 23, 2016 (the “Observation Period”) if the daily volume weighted average price (the “Daily VWAP”) (as defined in the indentures governing the Mandatory Convertible Notes) of the Company’s common stock on such day, rounded to four decimal places for the 2020 Mandatory Convertible Notes and rounded to two decimal places for the 2018 Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2021 Mandatory Convertible Notes and the 2023 Mandatory Convertible Notes, was above
$8.75
(the “Threshold Price”). Upon conversion, the common stock issue price per share was equal to the higher of (i) the Daily VWAP for the Company’s common stock for such trading day multiplied by
one
plus
zero
for the 2018 Mandatory Convertible Notes,
one
plus
0.5%
for the 2019 Mandatory Convertible Notes,
one
plus
8.0%
for the 2020 Mandatory Convertible Notes,
one
plus
2.5%
for the 2021 Mandatory Convertible Notes and
one
plus
3.5%
for the 2023 Mandatory Convertible Notes or (ii)
$8.75
for the 2018 Mandatory Convertible Notes (equivalent to
114.29
common shares per
$1,000
principal amount of the notes),
$8.79
for the 2019 Mandatory Convertible Notes (equivalent to
113.72
common shares per
$1,000
principal amount of the notes),
$9.45
for the 2020 Mandatory Convertible Notes (equivalent to
105.82
common shares per
$1,000
principal amount of the notes),
$8.97
for the 2021 Mandatory Convertible Notes (equivalent to
111.50
common shares per
$1,000
principal amount of the notes) and
$9.06
for the 2023 Mandatory Convertible Notes (equivalent to
110.42
common shares per
$1,000
principal amount of the notes) (the “Minimum Conversion Prices”).
After the Observation Period, the Company had the right, which the Company exercised on December 9, 2016 as noted below, to mandatorily convert any remaining Mandatory Convertible Notes if the Daily VWAP of the Company’s common stock exceeded
$8.75
for at least
20
trading days during a
30
consecutive trading day period and holders had the right to convert the Mandatory Convertible Notes at any time. The conversion price after the Observation Period was the Minimum Conversion Price for each applicable series of Mandatory Convertible Notes.
During the Observation Period, the Daily VWAP of the Company’s common stock was above the Threshold Price (i) for
7
of the
25
trading days for the 2018 Mandatory Convertible Notes, the 2019 Mandatory Convertible Notes, the 2021 Mandatory Convertible Notes and the 2023 Mandatory Convertible Notes and (ii) for
8
of the
25
trading days for the 2020 Mandatory Convertible Notes. As a result,
$333
million aggregate principal amount of the Mandatory Convertible Notes were converted into approximately
33.2
million shares of the Company’s common stock, and the Company paid
$3
million in cash consisting of all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a
$3
million gain on extinguishment of debt, which was net of a non-cash charge for the acceleration of unamortized debt issuance costs and debt discount on the notes.
On August 12, 2016, the Company completed the exchange of (i)
$13
million aggregate principal amount of the 2018 Mandatory Convertible Notes which had a conversion price of $8.75 per share (equivalent to 114.29 common shares per $1,000 principal amount of the notes) for shares of the Company’s common stock at an issuance price of
$7.77
per share (equivalent to
128.69
common shares per
$1,000
principal amount of the notes) and (ii)
$25
million aggregate principal amount of the 2019 Mandatory Convertible Notes which had a conversion price of $8.79 per share (equivalent to 113.72 common shares per $1,000 principal amount of the notes) for shares of the Company’s common stock at an issuance price of $
7.80
per share (equivalent to
128.17
shares per
$1,000
principal amount of the notes). Upon acceptance of this inducement offer by the holders of the notes, such notes were immediately cancelled in exchange for approximately
4.9
million shares of the Company’s common stock and the Company paid
$1
million in cash consisting of all accrued and unpaid interest on such notes. As a result of the exchanges, Whiting recognized (i)
$4
million of debt inducement expense related to the fair value of the incremental shares issued in the inducement offer over the original conversion terms of the notes, which expense is included in loss on extinguishment of debt in the consolidated statements of operations, and (ii) a
$14
million non-cash charge for the acceleration of unamortized debt discount on the notes, which is included in interest expense in the consolidated statements of operations.
During the fourth quarter of 2016, the Daily VWAP of the Company’s common stock was above
$8.75
for
20
trading days during a
30
consecutive trading day period. As a result, on December 9, 2016, the Company provided notice to the holders of the remaining
$721
million aggregate principal amount of the Mandatory Convertible Notes of its intent to exercise its right to convert such notes on December 19, 2016 pursuant to the terms of the indentures. The notes were subsequently converted into approximately
77.6
million shares of the Company’s common stock, and upon conversion, the Company paid
$5
million in cash consisting of all accrued and unpaid interest on such notes. As a result of the conversions, Whiting recognized a
$244
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. 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 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Senior Notes, the
2020
Convertible Senior Notes and borrowings under Whiting Oil and Gas’ credit agreement.
The Company’s obligations under the
Senior Notes, the 2020
Convertible Senior Notes and the 2018 Senior Subordinated 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
6
and 201
5
were
$
8
million and
$
6
million, respectively, and have been included in accrued liabilities and other. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 201
6
and 201
5
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Asset retirement obligation at January 1
|
|
$
|
161,908
|
|
$
|
179,931
|
Additional liability incurred
|
|
|
3,238
|
|
|
9,208
|
Revisions to estimated cash flows
(1)
|
|
|
11,620
|
|
|
29,307
|
Accretion expense
|
|
|
13,800
|
|
|
20,274
|
Obligations on sold properties and assets held for sale
|
|
|
(4,771)
|
|
|
(69,601)
|
Liabilities settled
|
|
|
(8,791)
|
|
|
(7,211)
|
Asset retirement obligation at December 31
|
|
$
|
177,004
|
|
$
|
161,908
|
|
(1)
|
|
Revisions
to
estimated cash flows during the year ended December 31,
2016 and
2015 are primarily attributable to
the acceleration in the estimated timing of abandonment of a large number of our producing properties resulting from decreases in commodity prices used in the calculation of
the Company’s
reserves as of December 31, 2016 and 2015, respectively, 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 enters into derivative contracts such as costless collars, swaps and crude oil sales and delivery contracts to achieve a more predictable cash flow by reducing its exposure to commodity price volatility. Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage 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
6
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Whiting Petroleum Corporation
|
|
|
|
|
|
|
|
Derivative
|
|
|
|
Contracted Crude
|
|
Weighted Average NYMEX Price
|
Instrument
|
|
Period
|
|
Oil Volumes (Bbl)
|
|
Collar Ranges for Crude Oil (per Bbl)
|
Three-way collars
(1) (2)
|
|
Jan - Dec 2017
|
|
12,000,000
|
|
$34.50 - $44.75 - $60.01
|
|
|
Jan - Dec 2018
|
|
2,400,000
|
|
$40.00 - $50.00 - $61.40
|
Collars
|
|
Jan - Dec 2017
|
|
3,000,000
|
|
$53.00 - $70.44
|
|
|
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 year
-
end, the Company entered into additional three-way collar contracts
for
600,000
Bbl
of crude oil volumes
for the year ended December 31, 2017.
|
Crude Oil Sales and Delivery Contract.
The Company has 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 has committed to deliver certain fixed volumes of crude oil through
April
2020. The Company determined that 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, and accordingly, that 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
6
and 2015
, the estimated fair value of this derivative contract was a liability of $
9
million
and $4 million, respectively
.
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, 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 has 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 has determined that this NYMEX-linked Contingent Payment is 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. As of December 31, 2016, the estimated fair value of this embedded derivative was an asset of $51 million.
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
6
, 201
5
and 201
4
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) Loss Recognized in Income
|
Not Designated as
|
|
Statement of Operations
|
|
Year Ended December 31,
|
ASC 815 Hedges
|
|
Classification
|
|
2016
|
|
2015
|
|
2014
|
Commodity contracts
|
|
Derivative gain, net
|
|
$
|
58,771
|
|
$
|
(217,972)
|
|
$
|
(136,995)
|
Embedded derivatives
|
|
Derivative gain, net
|
|
|
(59,358)
|
|
|
-
|
|
|
36,416
|
Total
|
|
|
|
$
|
(587)
|
|
$
|
(217,972)
|
|
$
|
(100,579)
|
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, 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
|
|
Derivative assets
|
|
$
|
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
|
|
Accrued liabilities and other
|
|
$
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
(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
|
|
Derivative assets
|
|
$
|
258,778
|
|
$
|
(100,049)
|
|
$
|
158,729
|
Commodity contracts - non-current
|
|
Other long-term assets
|
|
|
31,415
|
|
|
(3,465)
|
|
|
27,950
|
Total derivative assets
|
|
|
|
$
|
290,193
|
|
$
|
(103,514)
|
|
$
|
186,679
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Accrued liabilities and other
|
|
$
|
101,214
|
|
$
|
(100,049)
|
|
$
|
1,165
|
Commodity contracts - non-current
|
|
Other long-term liabilities
|
|
|
6,327
|
|
|
(3,465)
|
|
|
2,862
|
Total derivative liabilities
|
|
|
|
$
|
107,541
|
|
$
|
(103,514)
|
|
$
|
4,027
|
_____________________
|
(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 the
se
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, 2016 and 2015 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
|
Value
(1)
|
|
Value
(2)
|
|
Value
(1)
|
|
Value
(2)
|
6.5% Senior Subordinated Notes due 2018
|
|
$
|
275,121
|
|
$
|
273,506
|
|
$
|
265,125
|
|
$
|
346,876
|
5.0% Senior Notes due 2019
|
|
|
961,409
|
|
|
956,607
|
|
|
830,500
|
|
|
1,092,219
|
1.25% Convertible Senior Notes due 2020
|
|
|
503,057
|
|
|
483,465
|
|
|
850,000
|
|
|
1,027,151
|
5.75% Senior Notes due 2021
|
|
|
868,149
|
|
|
868,460
|
|
|
870,000
|
|
|
1,191,861
|
6.25% Senior Notes due 2023
|
|
|
408,296
|
|
|
403,265
|
|
|
543,750
|
|
|
739,597
|
Total
|
|
$
|
3,016,032
|
|
$
|
2,985,303
|
|
$
|
3,359,375
|
|
$
|
4,397,704
|
|
(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
6
and 201
5
, 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, 2016
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
|
$
|
-
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
December 31, 2015
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
158,729
|
|
$
|
-
|
|
$
|
158,729
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
27,950
|
|
|
-
|
|
|
27,950
|
Total financial assets
|
|
$
|
-
|
|
$
|
186,679
|
|
$
|
-
|
|
$
|
186,679
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
-
|
|
$
|
1,165
|
|
$
|
1,165
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
-
|
|
|
2,862
|
|
|
2,862
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
-
|
|
$
|
4,027
|
|
$
|
4,027
|
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 has a
long-term crude oil sales
and delivery contract, whereby it has committed to deliver certain fixed volumes of crude oil through
April
2020.
Whiting has determined that the contract d
oes
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 an income approach which considers various assumptions, including quoted forward 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.
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, and these embedded derivatives were thereby settled in their entirety as of June 30, 2016.
The Company has an embedded derivative related to its purchase and sale agreement with the buyer of the North Ward Estes Properties. The agreement includes a Contingent Payment linked to NYMEX crude oil prices which the Company has determined is 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. 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 are observable in the marketplace throughout the full term of the financial instrument
, 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 rate used in the fair value of this instrument includes a measure of the counterparty’s nonperformance risk.
Level 3 Fair Value Measurements
—
A third-party valuation specialist is utilized to determine 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
6
and 201
5
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Fair value asset (liability), beginning of period
|
|
$
|
(4,027)
|
|
$
|
53,530
|
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 converti
ble
notes
|
|
|
41,919
|
|
|
-
|
Unrealized losses on commodity derivative contracts included in earnings
(1)
|
|
|
(5,187)
|
|
|
(24,018)
|
Settlement of commodity derivative contracts
|
|
|
-
|
|
|
(33,539)
|
Transfers into (out of) Level 3
|
|
|
-
|
|
|
-
|
Fair value liability, end of period
|
|
$
|
(9,214)
|
|
$
|
(4,027)
|
_____________________
|
(1)
|
|
Included in
derivative
gain, 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
|
|
Income approach
|
|
Market differential for crude oil
|
|
$4.91 per Bbl
|
Sensitivity to Changes In 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 higher or lower, 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 and goodwill. 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 or goodwill during the year ended December 31, 2016.
The following table present
s
information about the Company’s non-financial assets measured at fair value on a non-recurring basis
for the year ended
December 31, 2015, 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
|
|
|
September 30,
|
|
Fair Value Measurements Using
|
|
December 31,
|
|
|
2015
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
2015
|
Proved property
(1)
|
|
$
|
531,775
|
|
$
|
-
|
|
$
|
-
|
|
$
|
531,775
|
|
$
|
1,602,226
|
Goodwill
(2)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
873,772
|
Total non-recurring assets at fair value
|
|
$
|
531,775
|
|
$
|
-
|
|
$
|
-
|
|
$
|
531,775
|
|
$
|
2,475,998
|
_____________________
|
(1)
|
|
During the third quarter of 2015, proved oil and gas properties with a previous carrying amount of
$2.1
billion were written down to their fair value as of September 30, 2015 of
$531
million, resulting in a non-cash impairment charge of
$1.5
billion which was recorded within exploration and impairment expense. The impaired properties consisted of the North Ward Estes field in Texas and other non-core proved oil and gas properties primarily in Texas, Wyoming, North Dakota and Colorado that
we
re not being developed due to depressed oil and gas prices. Also during the third quarter of 2015, proved CO
2
properties at the Bravo Dome field in New Mexico and the McElmo Dome field in Colorado with a previous carrying amount of
$63
million were written down to their fair value as of September 30, 2015 of
$1
million, resulting in a non-cash impairment charge of
$62
million which was also recorded within exploration and impairment expense.
|
|
(2)
|
|
During 2015, goodwill related to the Kodiak Acquisition with a carrying amount of
$874
million was written down to its fair value of
zero
, resulting in a non-cash impairment charge of $874 million which was recorded as a separate line in the consolidated statements of operations.
|
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. As a result of the significant decrease in the forward price curves for crude oil and natural gas during the third quarter of 2015, and the associated decline in oil and gas reserves over th
at
same period, the Company performed
a
proved property impairment test as of September 30, 2015. The fair value was ascribed using income approach analyses based on the net discounted future cash flows from the producing property and a market approach analysis, which approaches
were
probability-weighted. The discounted cash flows
we
re based on management’s expectations for the future. Unobservable inputs include
d
estimates of future oil and gas or CO
2
production, as the case may be, 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
we
re 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 the measurement date.
Goodwill Impairment.
The Company test
ed
goodwill for impairment annually in the second quarter or whenever events or changes in circumstances indicate
d
that the fair value of its 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 fair value of the Company’s reporting unit was ascribed using an income approach analysis based on the Company’s net discounted future cash flows and a market approach analysis. The discounted cash flows
we
re based on management’s expectations for the future. Unobservable inputs include
d
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
we
re designated as Level 3 inputs within the fair value hierarchy). 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
.
8
. SHAREHOLDERS
’
EQUITY AND NONCONTROLLING INTEREST
Common Stock
—
In May 2016, Whiting’s shareholders approved an amendment to the Company’s Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 600,000,000 shares.
Common Stock Offering.
In March 2015, the Company completed a public offering of its common stock, selling
35,000,000
shares of common stock at a price of
$30.00
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
5,250,000
shares of common stock.
On April 1, 2015, the underwriter exercised its right to purchase an additional
2,000,000
shares of common stock, providing additional net proceeds of
$61
million.
Noncontrolling Interest
—The Company’s noncontrolling interest represents an unrelated third party’s
25%
ownership interest in Sustainable Water Resources, LLC. The
table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
Balance at beginning of period
|
|
$
|
7,984
|
|
$
|
8,070
|
Net loss
|
|
|
(22)
|
|
|
(86)
|
Balance at end of period
|
|
$
|
7,962
|
|
$
|
7,984
|
9. STOCK-BASED COMPENSATION
Equity Incentive Plan
—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and include
d
the authority to issue
5,300,000
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 after May 7, 2013 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.
On December
8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by
978,161
shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the Kodiak Acquisition. Any shares netted or forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan.
At the Company’s 2016 Annual Meeting held on May 17, 2016, shareholders approved an amendment and restatement of the 2013 Equity Plan which increased the total number of shares issuable under the plan by
5,500,000
and revised certain award limits for employees and non-employee directors. Under the amended and restated 2013 Equity Plan, no employee or officer participant may be granted options for more than
900,000
shares of common stock, stock appreciation rights relating to more than
900,000
shares of common stock, or more than
600,000
shares of restricted stock during any calendar year. In addition, no non-employee director participant may be granted options for more than
100,000
shares of common stock, stock appreciation rights relating to more than
100,000
shares of common stock, or more than
100,000
shares of restricted stock during any calendar year.
As of December 31, 201
6
,
6,333,174
shares of common stock remained available for grant under the
amended
2013 Equity Plan.
Equity Awards Assumed in Kodiak Acquisition
—Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s outstanding equity awards, including restricted stock awards, restricted stock units and stock options. Kodiak’s outstanding equity awards held by employees were converted into Whiting’s equity awards using a conversion ratio of
0.177
. The outstanding restricted stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value as of the closing date of the
257,601
shares of Whiting common stock issued to convert these awards was recorded as part of the purchase consideration.
The estimated fair value as of the closing date of the
673,235
Whiting options issued in exchange for Kodiak’s outstanding options was approximately $8 million, based on a Black-Scholes option-pricing model. Of this value, approximately
$7
million was attributable to service rendered prior to the date of acquisition and was recorded as part of the purchase consideration, and the remaining
$1
million will be expensed over the remaining service term of the replacement stock option awards. The unvested stock option awards will vest over a
one
to
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 summarizes the assumptions used to estimate the fair value of stock options assumed in the Kodiak Acquisition:
|
|
|
|
|
2014
|
Risk-free interest rate
|
|
0.08%
-
1.90%
|
Expected volatility
|
|
40.3%
-
49.7%
|
Expected term
|
|
2.0
yrs. -
6.1
yrs.
|
Dividend yield
|
|
-
|
The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was
$12.20
per share as of the December
8, 2014 closing date of the Kodiak Acquisition.
Restricted Shares
—The Company grants service-based restricted stock awards to executive officers and employees, which generally vest ratably over a
three
-year service period, and to directors, which generally vest over a
one
-year service period. In addition, the Company grants restricted stock awards to executive officers that are subject to market-based vesting criteria as well as a three-year service period. The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation cost.
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.
For service-based restricted stock awards, the grant date fair value 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 service-based restricted stock awards was
$6.95
per share,
$30.93
per share and
$60.22
per share for the years ended December 31, 2016, 2015, and 2014, respectively.
In January 201
6 and 2015
,
1,073,143
shares and
391,773
shares
, respectively
of restricted stock 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 will be 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.
In January 2014,
750,681
shares of restricted stock subject to certain market-based vesting criteria in addition to the standard
three
-year service condition were granted to executive officers under the 2013 Equity Plan. Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage (or decreases by a lesser percentage) than the average percentage increase (or decrease, respectively) of the stock prices of a peer group of companies.
As of January 8, 2017, the end of the three-year vesting
period, these market-based conditions had not been met and all of these awards were therefore cancelled and are available for future issuance under the 2013 Equity Plan
.
For awards subject to market conditions, the grant date fair value was 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 was 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 market-based restricted shares were as follows:
|
|
|
|
|
|
|
|
|
201
6
|
|
2015
|
|
2014
|
Number of simulations
|
|
2,500,000
|
|
2,500,000
|
|
65,000
|
Expected volatility
|
|
60.8%
|
|
40.3%
|
|
42.3%
|
Risk-free interest rate
|
|
1.13%
|
|
0.99%
|
|
0.86%
|
Dividend yield
|
|
-
|
|
-
|
|
-
|
The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was
$6.39
per share,
$33.25
per share and
$26.59
per share in January 201
6
, 201
5
and 201
4
, respectively.
The following table shows a summary of the Company’s restricted stock
activity for the year ended
December 31, 201
6
:
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average
|
|
|
Service-Based
|
|
Market-Based
|
|
Grant Date
|
|
|
Restricted Stock
|
|
Restricted Stock
|
|
Fair Value
|
Nonvested awards,
January
1, 201
6
|
|
892,693
|
|
1,400,963
|
|
$
|
30.03
|
Granted
|
|
2,952,193
|
|
1,073,143
|
|
|
6.80
|
Vested
|
|
(428,659)
|
|
-
|
|
|
32.41
|
Forfeited
|
|
(348,423)
|
|
(381,296)
|
|
|
17.08
|
Nonvested awards, December 31, 201
6
|
|
3,067,804
|
|
2,092,810
|
|
$
|
13.55
|
As of December 31, 201
6
, there was
$18
million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of
1.6
years.
For the years ended December 31, 201
6
, 201
5
and 201
4
, the total fair value of restricted stock vested was
$5
million,
$
4
million and
$31
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
6
, 201
5
or 201
4
, other than the
673,235
stock options assumed in connection with the Kodiak Acquisition
, as discussed above
. 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
6
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, 2016
|
|
588,175
|
|
$
|
41.35
|
|
|
|
|
|
Granted
|
|
-
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
-
|
|
|
-
|
|
$
|
-
|
|
|
Forfeited or expired
|
|
(73,741)
|
|
|
55.85
|
|
|
|
|
|
Options outstanding at December 31, 201
6
|
|
514,434
|
|
$
|
39.27
|
|
$
|
60
|
|
4.3
|
Options vested and expected to vest at December 31, 201
6
|
|
490,978
|
|
$
|
38.81
|
|
$
|
54
|
|
4.2
|
Options exercisable at December 31, 201
6
|
|
510,717
|
|
$
|
39.06
|
|
$
|
60
|
|
4.3
|
There was
no
unrecognized compensation cost related to unvested stock option awards as of December 31, 2016.
There were no stock options exercised during the year ended December 31, 2016.
For the years ended December 31, 201
5
and 201
4
, the
aggregate
intrinsic value of stock options exercised
was
$
2
million and
$6
million, respectively.
For the years ended December 31, 201
6
, 201
5
and 201
4
, total stock compensation expense recognized for restricted share awards and stock options was
$26
million,
$28
million and
$23
million, respectively.
10.
INCOME TAXES
Income
tax expense (benefit) consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Current income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(7,340)
|
|
$
|
-
|
|
$
|
(2,758)
|
State
|
|
|
150
|
|
|
(357)
|
|
|
5,383
|
Total current income tax expense (benefit)
|
|
|
(7,190)
|
|
|
(357)
|
|
|
2,625
|
Deferred income tax expense (benefit):
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(65,130)
|
|
|
(736,520)
|
|
|
65,522
|
State
|
|
|
(15,326)
|
|
|
(37,350)
|
|
|
11,023
|
Total deferred income tax expense (benefit)
|
|
|
(80,456)
|
|
|
(773,870)
|
|
|
76,545
|
Total
|
|
$
|
(87,646)
|
|
$
|
(774,227)
|
|
$
|
79,170
|
Income tax expense (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,
|
|
|
2016
|
|
2015
|
|
2014
|
U.S. statutory income tax expense (benefit)
|
|
$
|
(499,370)
|
|
$
|
(1,047,723)
|
|
$
|
50,371
|
State income taxes, net of federal benefit
|
|
|
(33,050)
|
|
|
(44,654)
|
|
|
12,705
|
Statutory depletion
|
|
|
(52)
|
|
|
(327)
|
|
|
(618)
|
Enacted changes in state tax laws
|
|
|
5,020
|
|
|
7,350
|
|
|
3,700
|
Market-based equity awards
|
|
|
8,352
|
|
|
2,690
|
|
|
2,805
|
Permanent items
|
|
|
783
|
|
|
5,071
|
|
|
3,504
|
IRC Section 382 limitation
|
|
|
259,494
|
|
|
-
|
|
|
-
|
Non-deductible convertible debt expenses
|
|
|
174,071
|
|
|
-
|
|
|
-
|
Transaction costs
|
|
|
-
|
|
|
-
|
|
|
6,936
|
Goodwill impairment
|
|
|
-
|
|
|
305,820
|
|
|
-
|
Other
|
|
|
(2,894)
|
|
|
(2,454)
|
|
|
(233)
|
Total
|
|
$
|
(87,646)
|
|
$
|
(774,227)
|
|
$
|
79,170
|
The principal components of the Company’s deferred income tax assets and liabilities at December 31, 201
6
and 201
5
were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
Deferred income tax assets:
|
|
|
|
|
|
|
Net operating loss carryforward
|
|
$
|
1,248,034
|
|
$
|
835,995
|
Derivative instruments
|
|
|
6,145
|
|
|
-
|
Asset retirement obligations
|
|
|
21,398
|
|
|
18,896
|
Underwriter fees
|
|
|
5,134
|
|
|
6,060
|
Restricted stock compensation
|
|
|
12,171
|
|
|
17,675
|
EOR credit carryforwards
|
|
|
7,946
|
|
|
7,946
|
Alternative minimum tax credit carryforwards
|
|
|
7,847
|
|
|
15,694
|
Transaction costs
|
|
|
4,786
|
|
|
6,395
|
Other
|
|
|
9,436
|
|
|
11,110
|
Total deferred income tax assets
|
|
|
1,322,897
|
|
|
919,771
|
Less valuation allowance
|
|
|
(264,461)
|
|
|
(5,061)
|
Net deferred income tax assets
|
|
|
1,058,436
|
|
|
914,710
|
Deferred income tax liabilities:
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
1,412,781
|
|
|
1,264,598
|
Trust distributions
|
|
|
94,120
|
|
|
101,665
|
Discount on convertible senior notes
|
|
|
27,224
|
|
|
76,475
|
Derivative instruments
|
|
|
-
|
|
|
65,764
|
Total deferred income tax liabilities
|
|
|
1,534,125
|
|
|
1,508,502
|
Total net deferred income tax liabilities
|
|
$
|
475,689
|
|
$
|
593,792
|
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 not
e
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 allowance
s
on
its
deferred tax assets totaling
$
259
million.
As of December 31, 201
6
, the Company had federal net operating loss (“NOL”) carryforwards of
$
2.
7
billion
, which was
net of the IRC
Section 382 limitation
. Of this amount,
$
70
million in NOL carryforwards relate to tax deductions for stock compensation that exceed stock compensation costs recognized for financial statement purposes. The benefit of these excess tax deductions
has
not be
en
recognized as
of December 31, 2016
. 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
in
203
6
, and the state NOLs will expire between 201
7
and 203
6
.
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
6
, 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 is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions.
The
C
ompany 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
6
, the Company had AMT credits totaling
$
8
million that are available to offset future regular federal income taxes. These credits do not expire and can be carried forward indefinitely.
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, 201
6
, 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
,
which will expire between 2023 and 2025
,
and
$5
million of
Canadian NOL carryforwards, which will expire between
2034
and
2035
.
At December 31, 2015, the Company had a valuation allowance totaling $5 million on Canadian NOL carryforwards.
These valuation allowances have been recorded because the Company determined it was more likely than not that the benefit from
these deferred tax assets will 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.
The Company expects the carrying value of its
remaining
deferred tax assets at December 31, 2016 and 2015 to be realized based on the anticipated reversal of existing temporary differences, and accordingly
,
the Company has not recorded a
dditional
valuation
allowance as of December 31, 2016 or 2015.
In conjunction with the Kodiak Acquisition, the Company acquired 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 on the excess of the amount for financial reporting over the tax basis of the investment in Kodiak that is indefinitely reinvested outside the United States. This amount becomes taxable in Canada upon a repatriation of assets from the Canadian subsidiary or a sale or liquidation of the subsidiary. The amount of such temporary differences totaled
$
698
million as of December 31, 201
6
. Determination of the amount of any unrecognized deferred Canadian tax liability on this temporary difference is not practicable. U.S. income taxes on Kodiak and its subsidiary, Whiting Resources Corporation, however, have been fully recognized on their cumulative losses to date.
During the year ended December 31, 2016, t
he Company
derecognized
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 year
s
ended December 31, 201
6
,
201
5
and 201
4
,
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
3
through 201
6
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
1
through 201
6
tax years.
11.
EARNINGS PER SHARE
The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Basic Earnings (Loss) Per Share
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shareholders, basic
|
|
$
|
(1,339,102)
|
|
$
|
(2,219,182)
|
|
$
|
64,807
|
Denominator:
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding, basic
|
|
|
251,869
|
|
|
195,472
|
|
|
122,138
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings (Loss) Per Share
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
Adjusted net income (loss) available to common shareholders, diluted
|
|
$
|
(1,339,102)
|
|
$
|
(2,219,182)
|
|
$
|
64,807
|
Denominator:
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding, basic
|
|
|
251,869
|
|
|
195,472
|
|
|
122,138
|
Restricted stock and stock options
|
|
|
-
|
|
|
-
|
|
|
381
|
Weighted average shares outstanding, diluted
|
|
|
251,869
|
|
|
195,472
|
|
|
122,519
|
Earnings (loss) per common share, basic
|
|
$
|
(5.32)
|
|
$
|
(11.35)
|
|
$
|
0.53
|
Earnings (loss) per common share, diluted
|
|
$
|
(5.32)
|
|
$
|
(11.35)
|
|
$
|
0.53
|
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)
43,283,035
shares issuable for the convertible notes prior to their conversions under the if-converted method, (ii)
1,778,587
shares of service-based restricted stock, and (iii)
4,635
stock options. In addition, the diluted earnings per share calculation for the year ended December 31, 2016 excludes the dilutive effect of
1,917,811
common shares for stock options that were out-of-the-money and
370,195
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
516,139
shares of
service-based
restricted stock and
85,564
stock options. In addition, the
diluted earnings per share calculation for the year ended December 31, 2015 excludes (i) the anti-dilutive effect of
676,277
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2015
,
and (ii) the dilutive effect of
514,757
common shares for stock options that were out-of-the-money.
For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of
803,902
incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-dilutive effect of
791
common shares for stock optio
ns 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 initial conversion price, the entire outstanding principal amount of the 2020 Convertible Senior Notes as of December 31, 2016 would be convertible into approximately
21.9
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, 2016 and 2015, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share or the related disclosures for those periods.
12. RELATED PARTY TRANSACTIONS
Whiting USA Trust I
—
Whiting had a
retained ownership of
15.8%
, or
2,186,389
units in
Trust I
, and it was therefore a related party of the Company. On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated causing such interest in the underlying properties to revert back to Whiting, and Trust I was no longer a related party.
Tax Sharing Liability
—Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a related party of the Company. As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party.
In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting. Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from 2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases. In 2014, Whiting was obligated to pay Alliant the present value of
90%
of the remaining tax benefits expected to result from its increased tax bases, which payout assumes all such tax benefits will be realized in future years.
In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling
$26
million, including
$3
million of interest.
Alliant Energy Guarantee
—The Company holds a
6%
working interest in
three
offshore platforms in California and the related onshore plant and equipment. Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.
1
3. 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
6
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
|
Total
|
Non-cancelable leases
|
|
$
|
7,502
|
|
$
|
7,460
|
|
$
|
6,368
|
|
$
|
801
|
|
$
|
-
|
|
$
|
-
|
|
$
|
22,131
|
Drilling rig contracts
|
|
|
30,717
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
30,717
|
Pipeline transportation agreements
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
5,369
|
|
|
16,849
|
|
|
43,694
|
Total
|
|
$
|
43,588
|
|
$
|
12,829
|
|
$
|
11,737
|
|
$
|
6,170
|
|
$
|
5,369
|
|
$
|
16,849
|
|
$
|
96,542
|
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
6
, 201
5
and 201
4
amounted to
$9
million,
$9
million and
$7
million, respectively. Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 201
6
are shown in the table above.
Drilling Rig Contracts
—As of December 31, 201
6
, the Company had
five
drilling rigs under long-term contract
, all of which expire in 2017
. The Company’s minimum drilling commitments under the terms of
these
contracts as of December 31, 201
6
are shown in the table above. As of December 31, 201
6
, early termination of the
se
contracts would require termination penalties of
$2
7
million, which would be in lieu of paying the remaining drilling commitments under these contracts. During 201
6
, 201
5
and 201
4
, the Company made payments of
$66
million,
$161
million and
$106
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
two
pipeline transportation agreements with
one
supplier, expiring in 2024 and 2025, whereby it 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 $
44
million have been included in the table above.
During the second quarter of 2016, the Company terminated
two
ship-or-pay agreements to transport crude oil and water via certain pipelines expiring in 2026, and incurred termination penalties totaling
$1
million.
In conjunction with the sale of its interest in the North Ward Estes field in Texas on July 27, 2016, the Company transferred to the buyer of the properties a ship-or-pay agreement expiring in 2017 to transport a minimum daily volume of CO
2
via certain pipelines.
During 201
6
, 201
5
and 201
4
, transportation of crude oil, natural gas, NGLs, CO
2
and water under these contracts amounted to
$8
million,
$15
million and
$13
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
6
, the Company estimated the minimum future commitments under
this
purchase agreement to approximate
$31
million through 2020.
I
n conjunction with the sale of the North Ward Estes field in Texas on July 27, 2016
,
the Company transferred to the buyer of the properties a take-or-pay purchase agreement
expiring
in 2017 to buy certain volumes of CO
2
for use in the North Ward Estes EOR project.
During 201
6
, 201
5
and 201
4
, purchases of CO
2
and water amounted to
$37
million,
$88
million and
$105
million, respectively.
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
6
, the Company estimated the minimum future commitments under this disposal agreement to approximate
$137
m
illion through 2024.
During 2016, transportation and disposal of produced water amounted to
$8
million.
There were
no
water disposal costs incurred under this contract
during
2015
or 2014
.
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 is tied to crude oil production at Whiting’s Sanish field in Mountrail County, North Dakota
and requires delivery of
15
MBbl/d for a term of
seven
years. The effective date of this contract is contingent upon the completion of the Dakota Access Pipeline, the timing of which is currently unknown.
The Company believes its production and reserves are sufficient to fulfill the delivery commitment at the Sanish field in North Dakota
, and therefore expects to avoid any payments for deficiencies under this contract
.
The remaining
two
delivery commitments
are tied to crude oil production at Whiting’s Redtail field in Weld County, Colorado. As of December 31, 201
6
,
these two contracts contain
delivery commitments of
1
9.6
MMB
bl,
21.5
MMBbl,
23.3
MMBbl and
6.6
MMBbl of crude oil
for the years ended December 31, 2017 through 2020, respectively. 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 contracts, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes. During
2016 and
2015, total deficiency payments under these contracts amounted to
$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
6
or 201
5
.
14.
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,
|
|
|
2016
|
|
2015
|
|
2014
|
Beginning balance at January 1
|
|
$
|
-
|
|
$
|
14,293
|
|
$
|
85,378
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
|
-
|
|
|
54,707
|
|
|
145,336
|
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
|
|
-
|
|
|
(63,352)
|
|
|
(200,869)
|
Capitalized exploratory well costs charged to expense
|
|
|
-
|
|
|
(5,648)
|
|
|
(15,552)
|
Ending balance at December 31
|
|
$
|
-
|
|
$
|
-
|
|
$
|
14,293
|
At December 31, 201
6
, the Company had
no
costs capitalized for exploratory wells in progress for a period of greater than one year after the completion of drilling.
15.
SUBSEQUENT EVENTS
Gas Plant Sale
—
On January 1, 2017, the Company completed the sale of Whiting’s
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
|
Redemption of 2018 Senior Subordinated Notes
—
On January 3, 2017, the trustee under the indenture governing the Company’s 2018 Senior Subordinated Notes provided notice to the holders of such notes that Whiting elected to redeem all of the remaining
$275
million aggregate principal amount of the 2018 Senior Subordinated Notes on February 2, 2017,
and on that date, Whiting paid
$281
million consisting 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.
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,
|
|
|
2016
|
|
2015
|
Proved oil and gas properties
|
|
$
|
12,347,400
|
|
$
|
12,709,257
|
Unproved oil and gas properties
|
|
|
883,451
|
|
|
1,195,268
|
Accumulated depletion
|
|
|
(4,170,237)
|
|
|
(3,279,156)
|
Oil and gas properties, net
|
|
$
|
9,060,614
|
|
$
|
10,625,369
|
The Company’s oil and gas activities for 201
6
, 201
5
and 201
4
were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Development
(1)
|
|
$
|
518,585
|
|
$
|
2,137,755
|
|
$
|
2,891,893
|
Proved property acquisition
(2)
|
|
|
797
|
|
|
-
|
|
|
2,278,855
|
Unproved property acquisition
(2)
|
|
|
3,642
|
|
|
29,050
|
|
|
1,035,439
|
Exploration
|
|
|
45,846
|
|
|
192,422
|
|
|
216,587
|
Total
|
|
$
|
568,870
|
|
$
|
2,359,227
|
|
$
|
6,422,774
|
_____________________
|
(1)
|
|
During 201
6
, 201
5
and 201
4
, non-cash additions to oil and gas properties of
$
15
million,
$4
8
million and
$
45
million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above.
|
|
(2)
|
|
During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.
|
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
6
. 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
6
, 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
4
, 201
5
and 201
6
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcf)
|
|
(MBOE)
|
Balance—January 1, 2014
|
|
347,421
|
|
44,869
|
|
277,514
|
|
438,542
|
Extensions and discoveries
|
|
146,122
|
|
12,947
|
|
94,452
|
|
174,811
|
Sales of minerals in place
|
|
(1,642)
|
|
-
|
|
(2,925)
|
|
(2,130)
|
Purchases of minerals in place
|
|
169,586
|
|
-
|
|
156,140
|
|
195,609
|
Production
|
|
(33,485)
|
|
(3,283)
|
|
(30,218)
|
|
(41,804)
|
Revisions to previous estimates
|
|
15,627
|
|
151
|
|
(2,943)
|
|
15,288
|
Balance—December 31, 2014
|
|
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
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
198,204
|
|
23,721
|
|
183,129
|
|
252,446
|
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
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
149,217
|
|
21,148
|
|
94,385
|
|
186,096
|
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
|
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.
|
Notable changes in proved reserves for the year ended December
31, 2014 included
the following
:
|
·
|
|
Extensions and discoveries.
In 2014, total extensions and discoveries of 174.8 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
2.1 MMBOE
during 2014 and
were primarily attributable to the disposition of properties in the Big Tex prospect
as
further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements
, as well as other property divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields.
|
|
·
|
|
Purchases of minerals in place.
In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to the Kodiak Acquisition, whereby
the Company
acquired interests in 778 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the “Acquisitions and Divestitures” footnote
in the notes to the consolidated financial statements
.
|
|
·
|
|
Revisions to previous estimates.
R
evisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 15.3 MMBOE
in 2014
. Included in these revisions were (i)
15.6
MMBOE of net upward adjustments attributable to reservoir analysis and well performance and (ii)
0.3
MMBOE of downward adjustments caused by lower crude oil prices
incorporated into the Company’s reserve estimates
at December 31, 2014 as compared to December 31, 2013.
|
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
6
, 201
5
and 201
4
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
6
, 201
5
and 201
4
, 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,
|
|
|
2016
|
|
2015
|
|
2014
|
Future cash flows
|
|
$
|
16,946,961
|
|
$
|
29,339,528
|
|
$
|
59,949,707
|
Future production costs
|
|
|
(7,266,435)
|
|
|
(12,344,463)
|
|
|
(20,772,234)
|
Future development costs
|
|
|
(3,605,977)
|
|
|
(6,166,397)
|
|
|
(7,924,573)
|
Future income tax expense
(1)
|
|
|
-
|
|
|
(388,072)
|
|
|
(8,579,237)
|
Future net cash flows
|
|
|
6,074,549
|
|
|
10,440,596
|
|
|
22,673,663
|
10% annual discount for estimated timing of cash flows
|
|
|
(3,376,463)
|
|
|
(5,866,225)
|
|
|
(11,830,243)
|
Standardized measure of discounted future net cash flows
|
|
$
|
2,698,086
|
|
$
|
4,574,371
|
|
$
|
10,843,420
|
_____________________
|
(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 decreased by
$7
million in
2014.
The changes in the
S
tandardized
M
easure relating to proved oil and natural gas reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Beginning of year
|
|
$
|
4,574,371
|
|
$
|
10,843,420
|
|
$
|
6,593,861
|
Sale of oil and gas produced, net of production costs
|
|
|
(781,132)
|
|
|
(1,354,054)
|
|
|
(2,274,682)
|
Sales of minerals in place
|
|
|
(1,434,545)
|
|
|
(1,414,511)
|
|
|
(48,532)
|
Net changes in prices and production costs
|
|
|
(1,594,183)
|
|
|
(11,001,949)
|
|
|
81,522
|
Extensions, discoveries and improved recoveries
|
|
|
730,396
|
|
|
2,078,071
|
|
|
3,950,413
|
Previously estimated development costs incurred during the period
|
|
|
477,830
|
|
|
1,625,160
|
|
|
1,149,926
|
Changes in estimated future development costs
|
|
|
1,722,897
|
|
|
102,499
|
|
|
(3,382,849)
|
Purchases of minerals in place
|
|
|
-
|
|
|
-
|
|
|
4,420,417
|
Revisions of previous quantity estimates
|
|
|
(1,502,416)
|
|
|
(966,713)
|
|
|
345,775
|
Net change in income taxes
|
|
|
47,431
|
|
|
3,578,106
|
|
|
(651,817)
|
Accretion of discount
|
|
|
457,437
|
|
|
1,084,342
|
|
|
659,386
|
End of year
|
|
$
|
2,698,086
|
|
$
|
4,574,371
|
|
$
|
10,843,420
|
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
6
, 201
5
and 201
4
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
Oil (per Bbl)
|
|
$
|
35.60
|
|
$
|
43.07
|
|
$
|
84.69
|
NGLs (per Bbl)
|
|
$
|
10.09
|
|
$
|
15.53
|
|
$
|
46.59
|
Natural Gas (per Mcf)
|
|
$
|
2.61
|
|
$
|
2.83
|
|
$
|
5.88
|
QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited quarterly financial data for the years ended
December 31, 201
6
and 201
5
(in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
(0.84)
|
|
$
|
(1.33)
|
|
$
|
(2.47)
|
|
$
|
(0.59)
|
Diluted loss per share
|
|
$
|
(0.84)
|
|
$
|
(1.33)
|
|
$
|
(2.47)
|
|
$
|
(0.59)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
|
2015
|
|
2015
|
|
2015
|
|
2015
|
Oil, NGL and natural gas sales
|
|
$
|
519,848
|
|
$
|
650,527
|
|
$
|
504,155
|
|
$
|
417,952
|
Gross profit (loss)
(1)
|
|
$
|
25,586
|
|
$
|
128,012
|
|
$
|
18,130
|
|
$
|
(60,966)
|
Net loss
|
|
$
|
(106,128)
|
|
$
|
(149,295)
|
|
$
|
(1,865,118)
|
|
$
|
(98,727)
|
Basic loss per share
|
|
$
|
(0.63)
|
|
$
|
(0.73)
|
|
$
|
(9.14)
|
|
$
|
(0.48)
|
Diluted loss per share
|
|
$
|
(0.63)
|
|
$
|
(0.73)
|
|
$
|
(9.14)
|
|
$
|
(0.48)
|
_____________________
|
(1)
|
|
Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.
|
******