NOTES TO
CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
Description of Operations
—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company engaged in the development, production, acquisition and exploration of crude oil, NGLs and natural gas primarily in the Rocky Mountains region of the United States. Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting Resources Corporation and Whiting Programs, Inc.
Condensed Consolidated
Financial Statements
—The unaudited
condensed
consolidated financial statements include the accounts of Whiting Petroleum Corporation and its consolidated subsidiaries. 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. These financial statements have been prepared in accordance with GAAP and the SEC rules and regulations for interim financial reporting. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The
condensed
consolidated financial statements and related notes included in this Quarterly Report on Form 10-Q should be read in conjunction with Whiting’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2016. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to consolidated financial statements included in the Company’s 2016 Annual Report on Form 10
‑K.
Reclassifications
—Certain prior period balances in the
condensed
consolidated balance sheets
and statements of operations
have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
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 2015-14, 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 an increase in the assets and liabilities recorded on its consolidated balance sheet. As of
March
31, 201
7
, the Company had approximately
$100
million of contractual obligations related to its non-cancelable leases, drilling rig contracts and pipeline transportation agreements, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASU 2016-02.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09,
Improvements To Employee Share-Based Payment Accounting
(“ASU 2016-09”). The objective of this ASU
is
to simplify several aspects of the accounting for employee share-based payment transactions, including income tax consequences,
forfeitures,
classification of awards as either equity or liabilities and classification in the statement of cash flows. Portions of this ASU must be applied prospectively while other portions may be applied either prospectively or retrospectively.
ASU 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 31, 2016, and the Company adopted this standard on January 1, 2017
.
Upon adoption of ASU 2016-09, (i) the Company recorded $70 million of previously unrecognized
excess tax benefits
on a modified retrospective basis with a full valuation allowance, resulting in a net cumulative-effect adjustment to retained earnings of zero, (ii) the Company prospectively
removed excess tax benefits from its calculation of diluted shares, which had no impact on the Company’s diluted earnings per share for the three months ended March 31, 2017, and (iii) the Company elected to account for forfeitures of share-based awards as they occur, rather than by applying an estimated forfeiture rate to determine compensation expense, the effect of which was recognized using a modified retrospective approach and resulted in an immaterial cumulative-effect adjustment to retained earnings and additional paid-in capital.
2.
OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at
March 31, 2017
and
December 31, 2016
are as follows (in thousands):
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March 31,
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|
December 31,
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|
|
2017
|
|
2016
|
Proved leasehold costs
|
|
$
|
3,343,114
|
|
$
|
3,330,928
|
Unproved leasehold costs
|
|
|
368,998
|
|
|
392,484
|
Costs of completed wells and facilities
|
|
|
9,140,838
|
|
|
9,016,472
|
Wells and facilities in progress
|
|
|
542,474
|
|
|
490,967
|
Total oil and gas properties, successful efforts method
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|
|
13,395,424
|
|
|
13,230,851
|
Accumulated depletion
|
|
|
(4,429,143)
|
|
|
(4,170,237)
|
Oil and gas properties, net
|
|
$
|
8,966,281
|
|
$
|
9,060,614
|
3.
ACQUISITIONS AND DIVESTITURES
2017 Acquisitions and Divestitures
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
$375
million (before closing adjustments). The Company used the net proceeds from this transaction to repay a portion of the debt
outstanding under its credit agreement.
The following table shows the components of assets and liabilities classified as held for sale as of December 31, 2016 (in thousands):
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Carrying Value as of
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December 31, 2016
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Assets
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Oil and gas properties, net
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$
|
347,817
|
Other property and equipment, net
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|
475
|
Total property and equipment, net
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|
348,292
|
Other long-term assets
|
|
|
854
|
Total assets held for sale
|
|
$
|
349,146
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|
|
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|
Liabilities
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|
|
Asset retirement obligations
|
|
$
|
131
|
Other long-term liabilities
|
|
|
407
|
Total liabilities related to assets held for sale
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|
$
|
538
|
There were no significant acquisitions during the three months ended March 31, 2017.
2016 Acquisitions and Divestitures
In July 2016, the Company completed the sale of its interest in its enhanced oil recovery project in the North Ward Estes field in Ward and Winkler counties of Texas, including Whiting’s interest in certain CO
2
properties in the McElmo Dome field in Colorado
and certain other related
assets and liabilities (the “North Ward Estes Properties”)
for a cash purchase price of
$300
million (before closing adjustments)
. The sale was effective July 1, 2016 and resulted
in a pre-tax loss on sale of
$
18
7
million
.
The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
In addition to the cash purchase price, the buyer 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
$39
million. Refer to the “Derivative Financial Instruments” and “Fair Value Measurements” footnotes for more information on this embedded derivative
instrument
.
There were no significant acquisitions during the
year
ended
December 31
, 2016.
4
. LONG-TERM DEBT
Long-term debt consisted of the following at
March 31, 2017
and
December 31, 2016
(in thousands):
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March 31,
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December 31,
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|
2017
|
|
2016
|
Credit agreement
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$
|
450,000
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|
$
|
550,000
|
6.5%
Senior Subordinated Notes due 2018
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-
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275,121
|
5.0%
Senior Notes due 2019
|
|
|
961,409
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|
|
961,409
|
1.25%
Convertible Senior Notes due 2020
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|
|
562,075
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|
|
562,075
|
5.75%
Senior Notes due 2021
|
|
|
873,609
|
|
|
873,609
|
6.25%
Senior Notes due 2023
|
|
|
408,296
|
|
|
408,296
|
Total principal
|
|
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3,255,389
|
|
|
3,630,510
|
Unamortized debt discounts and premiums
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(66,347)
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|
(71,340)
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Unamortized debt issuance costs on notes
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(20,783)
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|
(23,867)
|
Total long-term debt
|
|
$
|
3,168,259
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|
$
|
3,535,303
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Credit Agreement
Whiting Oil and Gas, the Company’s wholly
owned subsidiary, has a credit agreement with a syndicate of banks that as of
March 31, 2017
had a borrowing
base
and
aggregate commitments of
$2.5
billion.
As of
March 31, 2017
, the Company had
$2.0
billion of available borrowing capacity, which was net of
$450
million in borrowings and
$9
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.
In April 2017, the lenders under the credit agreement reaffirmed the
$2.5
billion borrowing base in connection with the May 1, 2017 regular borrowing base redetermination.
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
March 31, 2017
,
$41
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 interest expense.
At
March 31, 2017 and December 31, 2016
, the weighted average interest rate on the outstanding principal balance under the credit agreement
was
3.0
%
and
4.0
%
, respectively
.
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Applicable
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Applicable
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Margin for Base
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Margin for
|
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Commitment
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Ratio of Outstanding Borrowings to Borrowing Base
|
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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
March 31, 2017
, 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
March 31, 2017
.
The obligations of Whiting Oil and Gas under the credit agreement are
collateralized
by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties. The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee.
Senior Notes, Convertible Senior Notes and Senior Subordinated Notes
The following table summarizes the material terms of the Company’s senior notes and convertible senior notes outstanding at
March 31, 2017
.
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2020
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2019
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Convertible
|
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2021
|
|
2023
|
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
Outstanding principal (in thousands)
|
|
$
|
961,409
|
|
$
|
562,075
|
|
$
|
873,609
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$
|
408,296
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Interest rate
|
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|
5.0%
|
|
|
1.25%
|
|
|
5.75%
|
|
|
6.25%
|
Maturity date
|
|
|
Mar 15, 2019
|
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|
Apr 1, 2020
|
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|
Mar 15, 2021
|
|
|
Apr 1, 2023
|
Interest payment dates
|
|
|
Mar 15, Sep 15
|
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Apr 1, Oct 1
|
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Mar 15, Sep 15
|
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Apr 1, Oct 1
|
Make-whole redemption date
(1)
|
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Dec 15, 2018
|
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|
N/A
(2)
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Dec 15, 2020
|
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Jan 1, 2023
|
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(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.
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(2)
|
|
The indenture governing our 1.25% Convertible Senior Notes due 2020 do
es
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
. O
n 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 Con
vertible 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.
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.
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.
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.
As a result of the redemption, Whiting recognized a
$2
million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs on the notes.
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”
) f
or 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, t
he Company exchanged
$559
million aggregate principal amount of its 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes. Refer to “Mandatory Convertible Notes” below for more information on these exchange transactions.
For the remaining $
562
million aggregate principal amount of 2020 Convertible Senior Notes
outstanding as of March 31, 2017
, t
he Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the
2020
Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the
2020
Convertible Senior Notes will be convertible
at the holder’s option
only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least
20
trading days (whether or not consecutive) during the period of
30
consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130%
of the conversion price on each applicable trading day; (ii) during the
five
business day period after any
five
consecutive trading day period (the “measurement period”) in which the trading price per
$1,000
principal amount of the
2020
Convertible Senior Notes for each trading day of the measurement period is less than
98%
of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the
2020
Convertible Senior Notes will be convertible at any time until the second
scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at 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
March 31, 2017
, 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
interest
expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity.
The
2020
Convertible Senior Notes consist of the following at
March 31, 2017
and
December 31, 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
|
2017
|
|
2016
|
Liability component
|
|
|
|
|
|
|
Principal
|
|
$
|
562,075
|
|
$
|
562,075
|
Less: unamortized note discount
|
|
|
(67,492)
|
|
|
(72,622)
|
Less: unamortized debt issuance costs
|
|
|
(5,538)
|
|
|
(5,988)
|
Net carrying value
|
|
$
|
489,045
|
|
$
|
483,465
|
Equity component
(1)
|
|
$
|
136,522
|
|
$
|
136,522
|
|
(1)
|
|
Recorded in additional paid-in capital, net of
$5
million of issuance costs and
$
50
million of deferred taxes as of
March 31, 2017
and
December 31, 2016
.
|
I
nterest expense recognized on the
2020
Convertible Senior Notes
related to the stated interest rate and amortization of the debt discount
totaled
$
7
and
$15
million
for the
three months ended March 31, 2017 and 2016, respectively
.
Mandatory Convertible Notes
—
O
n 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”). O
n
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 Note
s”), (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 p
rincipal amount of new
5.75%
Mandatory
Convertible Senior Notes due 2021 (the “202
1 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, 2019
Mandatory
Convertible Notes
, 2020 Mandatory Convertible Notes
and 2021
Mandatory
Convertible Notes, the “
Mandatory
Convertible Notes”).
These transactions were accounted for as extinguishment
s
of debt for the portion
s
of Senior Notes, 2020 Convertible Senior Notes and 2018 Senior Subordina
ted Notes that were exchanged.
During the
second half
of 2016, the
entire
$1,093
million aggregate principal amount of the Mandatory Convertible Notes
were
converted into approximately
115.7
million shares of the Company’s common stock
pursuant to the terms of the
notes
.
As of December 31, 2016,
no
Mandatory Convertible Notes remained outstanding.
Security and Guarantees
The Senior Notes and
the
2
020 Convertible Senior Notes
a
re unsecured obligations of Whiting Petroleum Corporation and these unsecured obligations are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and
Gas’ credit agreement.
The Company’s obligations under
the Senior Notes and the
2020
Convertible
Senior
Notes
are guaranteed by the Company’s
100%
-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S
‑X of the SEC. Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.
5
. ASSET RETIREMENT OBLIGATIONS
The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws. The current portions at
March 31, 2017
and
December 31, 2016
were
$6
million and
$8
million, respectively, and have been included in accrued liabilities and other
in the consolidated balance sheets
. The following table provides a reconciliation of the Company’s asset retirement obligations for the
three months ended March 31, 2017
(in thousands):
|
|
|
|
|
|
|
|
Asset retirement obligation at January 1, 2017
|
|
$
|
177,004
|
Additional liability incurred
|
|
|
690
|
Revisions to estimated cash flows
|
|
|
805
|
Accretion expense
|
|
|
3,505
|
Obligations on sold properties
|
|
|
(93)
|
Liabilities settled
|
|
|
(766)
|
Asset retirement obligation at March 31, 2017
|
|
$
|
181,145
|
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 crude oil costless collars
, swaps
and 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
March 31, 2017
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
Apr - Dec 2017
|
|
9,450,000
|
|
$34.76
-
$45.00
-
$60.26
|
|
|
Jan - Dec 2018
|
|
2,400,000
|
|
$40.00
-
$50.00
-
$61.40
|
Collars
|
|
Apr - Dec 2017
|
|
2,250,000
|
|
$53.00
-
$70.44
|
|
|
Total
|
|
14,100,000
|
|
|
|
(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.
|
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
March 31, 2017
and
December 31, 2016
, the estimated fair value of this derivative contract was a liability of
$66
million
and
$9
million, respectively
.
Embedded
Derivative
s
—
In 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
t
he fair value of these embedded derivatives as of March 31, 2017 and 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 has therefore bifurcated this embedded feature and reflected it
at fair value in the consolidated financial statements. As of
March 31, 2017 and December 31, 2016
, the estimated fair value of this embedded derivative was an asset of $
37
million
and $51 million, respectively
.
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
three months ended March 31, 2017 and 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gain) Loss Recognized in Income
|
Not Designated as
|
|
Statement of Operations
|
|
Three Months Ended March 31,
|
ASC 815 Hedges
|
|
Classification
|
|
2017
|
|
2016
|
Commodity contracts
|
|
Derivative loss, net
|
|
$
|
23,351
|
|
$
|
(16,745)
|
Embedded derivatives
|
|
Derivative loss, net
|
|
|
13,226
|
|
|
21,506
|
Total
|
|
|
|
$
|
36,577
|
|
$
|
4,761
|
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 pr
ovide 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
(1)
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
Gross
|
|
Fair Value
|
Not Designated as
|
|
|
|
Assets/
|
|
Amounts
|
|
Assets/
|
ASC 815 Hedges
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
Offset
|
|
Liabilities
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Prepaid expenses and other
|
|
$
|
23,523
|
|
$
|
(11,616)
|
|
$
|
11,907
|
Commodity contracts - non-current
|
|
Other long-term assets
|
|
|
9,756
|
|
|
(8,216)
|
|
|
1,540
|
Embedded derivatives - non-current
|
|
Other long-term assets
|
|
|
37,406
|
|
|
-
|
|
|
37,406
|
Total derivative assets
|
|
|
|
$
|
70,685
|
|
$
|
(19,832)
|
|
$
|
50,853
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
34,925
|
|
$
|
(11,616)
|
|
$
|
23,309
|
Commodity contracts - non-current
|
|
Other long-term liabilities
|
|
|
51,031
|
|
|
(8,216)
|
|
|
42,815
|
Total derivative liabilities
|
|
|
|
$
|
85,956
|
|
$
|
(19,832)
|
|
$
|
66,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
(1)
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
Gross
|
|
Fair Value
|
Not Designated as
|
|
|
|
Assets/
|
|
Amounts
|
|
Assets/
|
ASC 815 Hedges
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
Offset
|
|
Liabilities
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Prepaid expenses and other
|
|
$
|
21,405
|
|
$
|
(21,405)
|
|
$
|
-
|
Commodity contracts - non-current
|
|
Other long-term assets
|
|
|
9,495
|
|
|
(9,495)
|
|
|
-
|
Embedded derivatives - non-current
|
|
Other long-term assets
|
|
|
50,632
|
|
|
-
|
|
|
50,632
|
Total derivative assets
|
|
|
|
$
|
81,532
|
|
$
|
(30,900)
|
|
$
|
50,632
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
39,033
|
|
$
|
(21,405)
|
|
$
|
17,628
|
Commodity contracts - non-current
|
|
Other long-term liabilities
|
|
|
19,724
|
|
|
(9,495)
|
|
|
10,229
|
Total derivative liabilities
|
|
|
|
$
|
58,757
|
|
$
|
(30,900)
|
|
$
|
27,857
|
|
(1)
|
|
Because counterparties to the Company’s financial derivative contracts
subject to master netting arrangements
are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in 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 n
otes
and
senior subordinated n
otes
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 March 31, 2017 and December 31, 2016 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
|
Value
(1)
|
|
Value
(2)
|
|
Value
(1)
|
|
Value
(2)
|
6.5% Senior Subordinated Notes due 2018
|
|
$
|
-
|
|
$
|
-
|
|
$
|
275,121
|
|
$
|
273,506
|
5.0%
Senior Notes due 2019
|
|
|
956,602
|
|
|
957,123
|
|
|
961,409
|
|
|
956,607
|
1.25%
Convertible Senior Notes due 2020
|
|
|
491,113
|
|
|
489,045
|
|
|
503,057
|
|
|
483,465
|
5.75%
Senior Notes due 2021
|
|
|
869,241
|
|
|
868,661
|
|
|
868,149
|
|
|
868,460
|
6.25%
Senior Notes due 2023
|
|
|
408,296
|
|
|
403,430
|
|
|
408,296
|
|
|
403,265
|
Total
|
|
$
|
2,725,252
|
|
$
|
2,718,259
|
|
$
|
3,016,032
|
|
$
|
2,985,303
|
|
(1)
|
|
Fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.
|
|
(2)
|
|
Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums.
|
The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterpart
y
, 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
March 31, 2017
and
December 31, 2016
, 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
|
|
March 31, 2017
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
11,907
|
|
$
|
-
|
|
$
|
11,907
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
1,540
|
|
|
-
|
|
|
1,540
|
Embedded derivatives – non-current
|
|
|
-
|
|
|
37,406
|
|
|
-
|
|
|
37,406
|
Total financial assets
|
|
$
|
-
|
|
$
|
50,853
|
|
$
|
-
|
|
$
|
50,853
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
218
|
|
$
|
23,091
|
|
$
|
23,309
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
-
|
|
|
42,815
|
|
|
42,815
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
218
|
|
$
|
65,906
|
|
$
|
66,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
December 31, 2016
|
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Embedded derivatives – non-current
|
|
$
|
-
|
|
$
|
50,632
|
|
$
|
-
|
|
$
|
50,632
|
Total financial assets
|
|
$
|
-
|
|
$
|
50,632
|
|
$
|
-
|
|
$
|
50,632
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
14,664
|
|
$
|
2,964
|
|
$
|
17,628
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
3,979
|
|
|
6,250
|
|
|
10,229
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
18,643
|
|
$
|
9,214
|
|
$
|
27,857
|
The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are measured on a recurring basis:
Commodity Derivatives
.
Commodity derivative instruments consist mainly of costless collars for crude oil. The Company’s costless collars are valued based on an income approach.
T
he option model consider
s
various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
In addition, the Company 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 does not meet the “normal purchase normal sale” exclusion, and has therefore reflected this contract at fair value in its consolidated financial statements.
This commodity derivative was valued based on a
probability-weighted
income approach which considers various assumptions, including quoted
spot
prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of the crude oil sales and delivery
contract include certain market differential metrics that were unobservable during the term of the contract.
Such unobservable inputs were significant to the contract valuation methodology, and the
contract’s
fair value was therefore designated as Level 3 within the valuation hierarchy.
Embedded Derivatives
. The
Company had
em
bedded 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 accordingly, the embedded derivatives were 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 Company reviews these valuations
,
including the related 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
three months ended March 31, 2017 and 2016
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Fair value liability, beginning of period
|
|
$
|
(9,214)
|
|
$
|
(4,027)
|
Recognition of embedded derivatives associated with convertible note issuances
|
|
|
-
|
|
|
(89,884)
|
Unrealized losses on embedded derivatives included in earnings
(1)
|
|
|
-
|
|
|
(21,506)
|
Unrealized losses on commodity derivative contracts included in earnings
(1)
|
|
|
(56,692)
|
|
|
(3,210)
|
Transfers into (out of) Level 3
|
|
|
-
|
|
|
-
|
Fair value liability, end of period
|
|
$
|
(65,906)
|
|
$
|
(118,627)
|
|
(1)
|
|
Included in derivative loss
, net in the
condensed
consolidated statements of operations.
|
Quantitative Information about Level 3 Fair Value Measurements.
The significant unobservable inputs used in the fair value measurement of the Company’s
commodity derivative instrument
designated as Level 3 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instrument
|
|
Valuation Technique
|
|
Unobservable Input
|
|
Amount
|
Commodity derivative contract
|
|
Probability-weighted income approach
|
|
Market differential for crude oil
|
|
$3.93
-
$4.79
per Bbl
|
Sensitivity to Changes I
n Significant Unobservable Inputs.
As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contract are the market differentials for crude oil over the term of the contract. Significant increases or decreases in these unobservable inputs in isolation would result in a significantly lower
or higher, respectively, fair value liability measurement.
Non-recurring Fair Value Measurements
—
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.
The Company did
not
recognize any impairment write-downs with respect to its proved property during the 2017 or 2016 reporting periods presented.
8
. NONCONTROLLING INTEREST
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Balance at beginning of period
|
|
$
|
7,962
|
|
$
|
7,984
|
Net loss
|
|
|
(14)
|
|
|
(10)
|
Balance at end of period
|
|
$
|
7,948
|
|
$
|
7,974
|
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,
in conjunction with the acquisition of Kodiak,
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
a
cquisition. 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, more than
600,000
shares of restricted stock
, more than 600,000 restricted stock units, more than 600,000 performance shares, or more than 600,000 performance units
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, more than
100,000
shares of restricted stock
, or more than 100,000 restricted stock units
during any calendar year.
As of
March 31, 2017
,
5,103,199
shares of common stock remained available for grant under the
amended
2013 Equity Plan.
Restricted
Stock and Performance
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
performance share
awards to executive officers that are subject to market-based
vesting criteria as well as a
three
-year service period.
Upon adoption of ASU 2016-09 on January 1, 2017, the Company elected to account for forfeitures of awards granted under these plans as they occur in determining compensation expense
. The Company recognizes compensation expense for all awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
T
he grant date fair value
of restricted stock
is determined based on the closing bid price of the Company’s common stock on the grant date. The weighted average grant date fair value of restricted stock was
$11.86
per share
and
$6.75
per share
for the three months ended March 31, 2017 and 2016
, respectively.
In January 201
7
and 201
6
,
633,479
and
1,073,143
performance
shares, respectively
,
subject to certain market-based vesting criteria were granted to executive officers under the 2013 Equity Plan. These market-based awards cliff vest on the third anniversary of the grant date, and the number of shares that will vest at the end of that
three
-year performance period
is
determined based on the rank of Whiting’s cumulative stockholder return compared to the stockholder return of a peer group of companies over the same three-
year period. The number of shares earned could range from
zero
up to
two
times the number of shares initially granted.
For awards subject to market conditions, the grant date fair value
i
s estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility
i
s calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the
se
market-based
awards
were as follows:
|
|
|
|
|
|
|
201
7
|
|
201
6
|
Number of simulations
|
|
2,500,000
|
|
2,500,000
|
Expected volatility
|
|
82.44%
|
|
60.8%
|
Risk-free interest rate
|
|
1.52%
|
|
1.13%
|
Dividend yield
|
|
-
|
|
-
|
The grant date fair value of the market-based
awards
as determined by the Monte Carlo valuation model was
$16.36
per share
and
$6.39
per share in January 201
7
and 201
6
, respectively.
In January 2014,
750,681
performance shares
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
wa
s subject to the condition that Whiting’s stock price increase
d
by a greater percentage (or decrease
d
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
the remaining
awards were therefore cancelled and are available for future issuance under the 2013 Equity Plan.
The following table shows a summary of the Company’s restricted stock
and performance share
activity
for the three months ended
March
31, 201
7
:
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average
|
|
|
Service-Based
|
|
Market-Based
|
|
Grant Date
|
|
|
Restricted Stock
|
|
Performance Shares
|
|
Fair Value
|
Nonvested awards, January 1, 201
7
|
|
3,067,804
|
|
2,092,810
|
|
$
|
13.55
|
Granted
|
|
1,476,772
|
|
633,479
|
|
|
13.21
|
Vested
|
|
(1,080,279)
|
|
-
|
|
|
13.04
|
Forfeited
|
|
(141,526)
|
|
(738,750)
|
|
|
22.48
|
Nonvested awards,
March
31, 201
7
|
|
3,322,771
|
|
1,987,539
|
|
$
|
12.04
|
As of
March
31, 201
7
, there was
$37
million of total unrecognized compensation cost related to unvested
shares
granted under the stock incentive plans. That cost is expected to be recognized over a weighted average period of
2.2
years. For the
three months
ended
March
31, 201
7
and 201
6
, the total fair value of restricted stock
and performance shares
vested was
$13
million and
$3
million, respectively.
Stock Options—
There was no significant stock option activity during the three months ended March 31, 2017
and 2016.
For the three months ended March 31, 2017 and 2016, total stock compensation expense recognized for restricted shares and stock options was
$6
million and
$7
million, respectively.
10
. INCOME TAXES
Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes for the
three months ended March 31, 2017 and 2016
differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of
35%
to pre-tax income primarily because of state income taxes and estimated permanent differences.
The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary differences, and the likelihood of recovering deferred tax assets generated in the current year. The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is obtained, additional information becomes known or as the tax environment changes.
Upon adoption of ASU 2016-09
on January 1, 2017
, the Company
recorded
$70 million of previously unrecognized excess tax benefits
related to stock-based compensation
,
for which a full valuation
allowance
was also recognized.
11
. EARNINGS PER SHARE
The reconciliations between basic and diluted loss per share are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Basic Loss Per Share
|
|
|
|
|
|
|
Net loss attributable to common shareholders
|
|
$
|
(86,957)
|
|
$
|
(171,748)
|
Weighted average shares outstanding
|
|
|
362,610
|
|
|
204,367
|
Loss per common share
|
|
$
|
(0.24)
|
|
$
|
(0.84)
|
|
|
|
|
|
|
|
Diluted Loss Per Share
|
|
|
|
|
|
|
Adjusted net loss attributable to common shareholders
|
|
$
|
(86,957)
|
|
$
|
(171,748)
|
Weighted average shares outstanding
|
|
|
362,610
|
|
|
204,367
|
Loss per common share
|
|
$
|
(0.24)
|
|
$
|
(0.84)
|
During the
three months ended March 31, 2017
, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes the anti-dilutive
effect of
1,787,563 shares of service-based restricted stock and
4,880
stock options. In addition, the diluted earnings per share calculation for the
three months ended March 31, 2017
excludes the effect of
1,363,136
common shares for stock options that were out-of-the-money
and
354,485
shares of restricted stock that did not meet its market-based vesting criteria as of
March 31, 2017.
During the three months ended March 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
4,137,880
shares issuable for
c
onvertible
n
otes prior to their conversions under the if-converted method and
4,144
stock options. In addition, the diluted earnings per share calculation for the three months ended March 31, 2016 excludes the
effect of
3,080,193
common shares for stock options that were out-of-the-money
and
1,121,721
sh
ares of restricted stock that did not meet its market-based vesting criteria as of March 31, 2016.
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
March 31
, 201
7
would be convertible into approximately
21.9
million shares of the Company’s common stock. However,
t
he 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
March 31, 2017 and 2016
, 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 th
ose
period
s
.
Item
2
.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwi
se requires, the terms “Whiting
”
, “we
”
, “us
”
,
“our” or “ours” when used in this Item refer to Whiting Petroleum Corporation, together with its consolidated subsidiaries, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), Whiting US Holding Company, Whiting Canadian Holding Company ULC (formerly Kodiak Oil & Gas Corp., “Kodiak”), Whiting Resources Corporation and Whiting Programs, Inc. When the context requires, we refer to these entities separately. This document contains forward-looking statements, which give our current expectations or forecasts of future events. Please refer to “Forward-Looking Statements” at the end of this Item for an explanation of these types of statements.
Overview
We are an independent oil and gas company engaged in development, production
,
acquisition and
exploration
activities primarily in the Rocky Mountain
s
region of the United States.
Our current operations and capital programs are focused
on organic drilling
opportunities
and on the development of previously acquired properties, specifically on projects that we believe provide the
greatest potential
for repeatable success and production growth
, while selectively pursuing acquisitions that complement our existing core properties
.
As a result of lower crude oil prices during 2015 and 2016, we significantly reduced our level of capital spending to more closely align with our cash flows generated from operations and have focused our drilling activity on projects that provide the highest rate of return. In response to higher crude oil prices during the fourth quarter of 2016 and continuing into 2017, we plan to increase our level of capital spending and shift our focus to adding production and reserves through a capital-efficient program that includes increased drilling and completion activity in the Williston Basin and the resumption of completion activity at our Redtail field, which activity
had
been suspended since the second quarter of 2016. In addition, w
e continually evaluate our property portfolio and sell properties when we believe that the sales price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own
, such as the asset sales discussed below under “Acquisition and Divestiture Highlights” and in the “Acquisitions and Divestitures” footnote in the notes to
condensed
consolidated financial statements.
Our revenue, profitability and future growth rate depend on many factors which are beyond our control, such as
oil and gas prices,
economic, political
and regulatory developments,
competition from other sources of energy
, and the other items discussed under the caption “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the period ended December 31, 2016
. Oil and gas prices historically have been volatile and may fluctuate widely in the future.
The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas prices since the first quarter of 201
5
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
2016
|
|
2017
|
|
|
Q1
|
|
Q2
|
|
Q3
|
|
Q4
|
|
Q1
|
|
Q2
|
|
Q3
|
|
Q4
|
|
Q1
|
Crude oil
|
|
$
|
48.57
|
|
$
|
57.96
|
|
$
|
46.44
|
|
$
|
42.17
|
|
$
|
33.51
|
|
$
|
45.60
|
|
$
|
44.94
|
|
$
|
49.33
|
|
$
|
51.86
|
Natural gas
|
|
$
|
2.99
|
|
$
|
2.61
|
|
$
|
2.74
|
|
$
|
2.17
|
|
$
|
2.06
|
|
$
|
1.98
|
|
$
|
2.93
|
|
$
|
2.98
|
|
$
|
3.07
|
Lower oil
, NGL
and natural gas prices may not only decr
ease our revenues
on a per unit basis
, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentiall
y lower our oil and gas reserve quantities
.
S
ubstantial
and
extended decline
s
in oil
, NGL
and
natural gas prices may result in impairments of our proved oil and gas properties
or undeveloped acreage
and may materially and adversely affect our future business, financial condition, cash flows, results of operations, liquidity or ability to finance planned capital expenditures.
In addition,
l
ower
commodity
prices
may reduce
the amount of our borrowing base under our
credit agreement, which is determined at the discretion of
our
lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under our credit agreement.
Alternatively
, higher oil prices may result in significant mark-to-market losses being incurred on our commodity-ba
sed derivatives.
201
7
Highlights and Future Considerations
Operational Highlights
Northern Rocky Mountains – Williston Basin
Our properties in the Williston Basin of North Dakota and Montana target the Bakken and Three Forks formations. Net production from the Williston Basin averaged 109.1 MBOE/d for the first quarter of 2017, representing a slight increase from 108.9 MBOE/d in the fourth quarter of 2016. As of March 31, 2017, we had four rigs active in the Williston Basin, and we added a fifth rig in April 2017.
Across our acreage in the Williston Basin, we
have implemented new completion design
s which utilize
cemented liners, plug-and-perf technology
,
significantly
higher sand volumes
, new diversion technology and
both hybrid and slickwater fracture stimulation methods
, which have resulted
in improved initial production rates.
Central Rocky Mountains – Denver Julesburg Basin
Our Redtail field in the Denver Julesb
u
rg Basin (“DJ Basin”) in Weld County, Colorado targets the Niobrara
and Codell/Fort Hays
formation
s
.
N
et production from the Redtail field averaged
7.6
MBOE/d
i
n the
first
quarter of 201
7
, representing a
17
%
de
crease
from
9.2
MBOE/d in the
fourth
quarter of 201
6
.
We have established production in the Niobrara “A”, “B” and “C” zones and the Codell/Fort Hays formations. We have implemented a new wellbore configuration in this area, which significantly reduces drilling times.
As of
March 31, 2017
, we had
one
drilling rig operating in
the DJ Basin. In response to low commodity prices, we suspended completion operations in this area beginning in the second quarter of 2016; however, we resumed completion activity during the first quarter of 2017 and
added
a second completion crew in April. During 2017, we plan to complete our entire drilled uncompleted well inventory from yearend 2016.
Our Redtail gas plant processes the associated gas produced from our wells in this area, and has a current
inlet capacity
of
50
MMcf/d.
As of March 31, 2017, the plant was processing over 15 MMcf/d.
Financing
Highlights
On January 3, 2017, the trustee under the indenture governing our 6.5% Senior Subordinated Notes due 2018 (the “2018 Senior Subordinated Notes”) provided notice to the holders of such notes that we elected to redeem all of the remaining $275 million aggregate principal amount of our 2018 Senior Subordinated Notes on February 2, 2017, and on that date, we paid $281 million consisting of the 100% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with borrowings under our credit agreement.
Refer to the “Long-Term Debt” footnote in the notes to
condensed
consolidated financial statements for more information on this financing transaction.
Acquisition and Divestiture Highlights
On January 1, 2017, we completed the sale of our 50% interest in the Robinson Lake gas processing plant located in Mountrail County, North Dakota and our 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). We used the net proceeds from this transaction to repay a portion of the debt outstanding under our credit agreement.
Results of Operations
Three Months Ended March 31, 2017
Compared to
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Net production
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
|
7.3
|
|
|
10.0
|
NGLs (MMBbl)
|
|
|
1.6
|
|
|
1.6
|
Natural gas (Bcf)
|
|
|
9.9
|
|
|
10.5
|
Total production (MMBOE)
|
|
|
10.6
|
|
|
13.4
|
Net sales (in millions)
|
|
|
|
|
|
|
Oil
(1)
|
|
$
|
320.5
|
|
$
|
269.7
|
NGLs
|
|
|
28.6
|
|
|
9.0
|
Natural gas
|
|
|
22.2
|
|
|
11.0
|
Total oil, NGL and natural gas sales
|
|
$
|
371.3
|
|
$
|
289.7
|
Average sales prices
|
|
|
|
|
|
|
Oil (per Bbl)
(1)
|
|
$
|
43.92
|
|
$
|
27.07
|
Effect of oil hedges on average price (per Bbl)
|
|
|
0.20
|
|
|
5.54
|
Oil net of hedging (per Bbl)
|
|
$
|
44.12
|
|
$
|
32.61
|
Weighted average NYMEX price (per Bbl)
(2)
|
|
$
|
51.87
|
|
$
|
33.52
|
NGLs (per Bbl)
|
|
$
|
17.69
|
|
$
|
5.48
|
Natural gas (per Mcf)
|
|
$
|
2.25
|
|
$
|
1.05
|
Weighted average NYMEX price (per MMBtu)
(2)
|
|
$
|
3.06
|
|
$
|
2.05
|
Costs and expenses (per BOE)
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
8.56
|
|
$
|
8.56
|
Production taxes
|
|
$
|
3.03
|
|
$
|
1.94
|
Depreciation, depletion and amortization
|
|
$
|
22.76
|
|
$
|
23.38
|
General and administrative
|
|
$
|
2.90
|
|
$
|
3.35
|
|
(1)
|
|
Before consideration of hedging transactions.
|
|
(2)
|
|
Average NYMEX pricing weighted for monthly production volumes.
|
Oil, NGL and Natural Gas Sale
s
. Our oil, NGL and natural gas sales revenue
in
creased
$82
million to
$371
m
illion when comparing
the first
quarter
of 201
7
to
the same period in
201
6
. Sales revenue is a function of oil, NGL and gas volumes sold and average commodity prices realized. Our oil
, NGL and natural gas
sales volumes
de
creased
27%
,
1%
and
6%
, respectively,
between period
s. The oil volume decrease between periods
was
primarily
attributable to
normal field production decline across several of our areas
resulting from reduced drilling and completion activity during 2016 in response to the depressed commodity price environment. In addition, we completed
certain
non-core oil and gas
property divestitures
during 2016,
which negatively impacted oil production in the first
quarter
of 201
7
by
705
MBbl
. These decreases were partially offset by new wells drilled and completed in the Williston
B
asin
which added
1,480
MBbl
of oil production during the first
quarter
of 201
7
as compared to the first
quarter
of 201
6
.
T
he gas volume
de
crease between periods
was
primarily
due to
normal field production decline across several of our areas
, as well as 2016 property divestitures which negatively impacted gas production in the first quarter of 201
7
by 190 MMcf.
Th
ese
de
crease
s
w
ere
partially
offset by
drilling success at our Williston Basin properties which resulted in
2,090
MMcf of additional gas volumes during the first
quarter
of 201
7
as compared to the first
quarter
of 201
6
.
These
production-related
de
creases in net revenue
were
offset by
in
creases
in the average sales price realized for
oil, NGLs and
natural gas in
the first
quarter
of
201
7
compared to 201
6
.
Our average price for oil
(
before the effects of hedging
), NGLs and natural gas
in
creased
62%
,
223%
and
114%
, respectively,
between periods.
Lease Operating Expenses
. Our lease operating expenses (“LOE”) during the first
quarter
of 201
7
were
$90
million, a
$24
million de
crease over the same period in 201
6
.
This decrease was
primarily
due to
a decline in the costs of oilfield goods and services
resulting from
the general downturn in the oil and gas industry as well as
cost reduction measures we have implemented and $7
million of lower LOE attributable to properties that we divested
during 2016
and the first quarter of 2017
.
Our lease operating expenses on a BOE basis
, however, remained consistent at
$8.56
during the first
quarter
of 201
7
and
201
6
, as the overall decrease in LOE expense discussed above was offset by
lower
overall production volumes between periods.
Production Taxes
. Our production taxes during the first
quarter
of 201
7
were
$32
million, a
$6
million
in
crease over the same period in 201
6
, which
in
crease was primarily due to
higher
oil, NGL and natural gas sales between periods. Our production taxes, however, are generally calculated as a percentage of net sales revenue before the effects of hedging, and this percentage on a company-wide basis was
8.6%
and
8.9%
for the first
quarter
of 201
7
and 201
6
, respectively.
Depreciation, Depletion and Amortization
. Our depreciation, depletion and amortization (“DD&A”) expense
decreased
$72
million in 201
7
as compared to the first
quarter
of 201
6
. The components of our DD&A expense were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Depletion
|
|
$
|
235,032
|
|
$
|
306,611
|
Depreciation
|
|
|
1,870
|
|
|
2,102
|
Accretion of asset retirement obligations
|
|
|
3,505
|
|
|
3,579
|
Total
|
|
$
|
240,407
|
|
$
|
312,292
|
DD&A
decreased between periods
due to $
72
million in
lower
depletion expense.
This decrease was attributable to a $
62
million
de
crease
due to lower
overall production volumes during the first
quarter
of 201
7
,
as well as
a
$
10
million
de
crease in expense
related to
a
lowe
r depletion rate between periods
. On a BOE basis, our overall DD&A r
ate of
$22.76
for the first
quarter
of 201
7
was
3%
lower
than the rate of
$23.38
for the same period in 201
6
. The primary factor
s
contributing to
this
lower
DD&A rate
were
an in
crease to proved and proved developed reserves over the last twelve months
(excluding the effect of divestitures)
mainly due
to
higher
average oil and natural gas prices used to calculate our reserves
and property divestitures over the past twelve months
.
These factors that positively
impacted our DD&A rate were partially offset by $411 million in drilling and development expenditures over the past twelve months.
Exploration and Impairmen
t
Cos
t
s
. Our exploration and impairment costs
de
creased
$15
m
illion for the first
quarter
of 201
7
as compared to the same period in 201
6
. The components of our exploration and impairment
expense
w
ere as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Exploration
|
|
$
|
6,138
|
|
$
|
20,519
|
Impairment
|
|
|
14,703
|
|
|
14,972
|
Total
|
|
$
|
20,841
|
|
$
|
35,491
|
Exploration costs
de
creased $
14
million during the first
quarter
of 201
7
as compared to the same period in 201
6
primarily due to
lower rig termination fees incurred between periods
.
R
ig termination fees
amounted
to $
14
million during the first
quarter
of 201
6
, whereas we incurred no rig termination fees during the first quarter of 2017
.
Impairment expense for the first
quarter
of 201
7
and 2016
related to the amortization of leasehold costs associated with individually insignificant unproved properties.
General and Administrative
Expenses
. We report general and administrative
(“G&A”)
expenses net of third-party reimbursements and internal allocations. The components of our
G&A
expenses were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
General and administrative expenses
|
|
$
|
56,990
|
|
$
|
77,334
|
Reimbursements and allocations
|
|
|
(26,373)
|
|
|
(32,538)
|
General and administrative expenses, net
|
|
$
|
30,617
|
|
$
|
44,796
|
G&A
expense before reimb
ursements and allocations
de
creased
$
20
million during the
first
quarter
of 201
7
as compared to the same period in 201
6
primarily due to lower employee compensation. Employee compensation decreased $
18
million for the first
quarter
of 201
7
as compared to the same period in 201
6
primarily
due to reductions in personnel over the past twelve months.
The
de
crease in reimbursements
and allocations for the first
quarter
of 201
7
was
the result of
a
lower
number of field workers on Whiting-operated properties
associated with
reduced drilling activity
, as well as
property divestitures over the past twelve months
.
Our general and administrative expenses on a BOE basis
also de
creased when comparing the first
quarter
of 201
7
to the same 201
6
period. G&A expense per BOE amounted to
$2.90
during the first
quarter
of 201
7
, which represents a
de
crease of
$0.45
per BOE (or
13%
) from the first
quarter
of 201
6
. This
de
crease was mainly due to
lower employee compensation
, partially offset by
lower overall production volumes between periods
.
Derivative
Loss
, Net.
O
ur commodity derivative contracts
and
embedded derivatives are marked
to
market each quarter with fair value gains and losses recognized immedia
tely in earnings as derivative (
gain
) loss
, net. Cash flow, however, is only impacted to the extent that settlements under these contracts result in making or receiving a paym
ent to or from
the counterparty.
Derivative
loss
, net amounted to a
loss
of
$37
million for the
three
months ended
March 31
, 201
7, which consisted of
a $57 million fair value loss on our
long-term crude oil sales
and delivery contract
and
a
$
13
million
fair value loss on embedded derivatives, partially offset by a
$
33
million
gain
on
our costless collar
commodity derivative contracts resulting from
the
downward
shift in the futures curve of forecasted commodity prices (“forward price curve”) for crude oil from January 1, 201
7
(or the 201
7
date on which new contracts were entered into)
to
March 31
, 201
7
. Derivative
loss
, net
amounted to a loss of $5 million
for the
three
months ended
March 31
, 201
6, which
consisted of
a
$
22
million
fair value loss on embedded derivatives, partially offset by a $17 million
gain
on commodity derivative contracts
resulting from
the
less significant
downward
sh
ift in the same forward price curve from January 1, 201
6
(or the 201
6
date on which prior year contracts
were entered into) to
March 31
, 201
6
.
Refer to
Item 3, “Quantitative and Qualitativ
e Disclosures about Market Risk
”
,
for a list of our outstanding
commodity
derivative
contracts
as of
March 3
1
, 201
7
.
Interest Expense
. The components of our interest expense were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Notes
|
|
$
|
34,252
|
|
$
|
52,313
|
Amortization of debt issue costs, discounts and premiums
|
|
|
7,605
|
|
|
21,369
|
Credit agreement
|
|
|
5,813
|
|
|
7,868
|
Other
|
|
|
353
|
|
|
412
|
Capitalized interest
|
|
|
(12)
|
|
|
(55)
|
Total
|
|
$
|
48,011
|
|
$
|
81,907
|
The
de
crease in interest expen
se of
$34
million between periods was mainly attributable to
lower
interest costs incurred on our notes
and a
de
crease in amortization of debt issue costs, discounts and premiums
during the first
quarter
of 201
7
as compared to the first
quarter
of 201
6
. The
$
18
million de
crease in note interest
was
primarily
due to
(i) the conversions of the
New Convertible Notes i
n May 2016 and the
Mandatory Convertible Notes
in
the second half of
2016, resulting in
a $
15
million decrease in note interest
during the first quarter of 2017, and (ii)
the redemption of the 2018 Senior Subordinated Notes in February 2017, resulting in
a $
3
million decrease
between periods
.
Refer to the “Long-Term Debt” footnote in the notes to
condensed
consolidated financial statements for more information on these debt transactions.
The
de
crease in amortization of debt issue costs, discounts and premiums of $
14
million
wa
s primarily due to
(i) the conversions of the
New Convertible Notes i
n May 2016 and the
Mandatory Convertible Notes
in
the second half of
2016, resulting in
a
$7 million decrease in amortization
expense
during the first quarter of 2017, and (ii) a
$6 million
non-cash charge
for the acceleration of unamortized debt issuance costs in connection with a reduction of the aggregate commitments under our credit agreement in March 2016.
Our weighted average debt outstanding during the first
quarter
of 201
7
was $
3.3
billion versus $5.
6
billion for the first
quarter
of 201
6
. Our weighted average effective cash interest rate was
4.9
% during the first
quarter
of 201
7
compared to
4.3
% for the first
quarter
of 201
6
.
Gain
(
Loss
)
on Extinguishment of Debt.
During the first quarter of
2017, we
redeemed all of the remaining $275 million aggregate principal amount of 2018 Senior Subordinated Notes
and recognized a $
2
million loss on extinguishment of debt.
During the first quarter of
2016, we completed the exchange of $477 million aggregate principal amount of our senior notes and senior subordinated notes
for
the same aggregate principal amount o
f New Convertible Notes, and
recognized a $91 million gain on extinguishment of
debt. Refer to the “Long-Term Debt” footnote in the notes to
condensed
consolidated financial statements for more information on these debt transactions.
Income Tax
Benefit
.
Income tax
benefit
for the first
quarter
of 201
7
totaled
$39
million as compared to
$65
million for the first
quarter
of 201
6
, a
de
crease of
$26
million that was mainly related to
$110
m
illion in lower pre-tax loss between periods
, partially offset by $15 million of permanent tax differences
recognized during the first quarter of 2016
associated with the
issuance of the New Convertible Notes.
Our effective tax rates for the periods ending
March 31
, 201
7
and 201
6
differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes and permanent taxable differences.
O
ur overall effective tax rate
in
creased from
27.5%
for the first
quarter
of 201
6
to
31.2%
for the first
quarter
of 201
7
. This
in
crease is mainly the result of
$
15
million
of
permanent tax differences
recognized during the first quarter of 2016
associated with the issuance of the New Convertible Notes.
Liquidity and Capital Resources
Overvie
w
. At
March 31, 2017
, we had $
16
million of cash on hand and $
5.1
billion of equity, while at
December 31, 2016
, we had $
5
6
million of cash on hand and $
5.1
billion of equity.
One of the primary sources of variability in our cash flows from operating activities is commodity price volatility, which we partially mitigate through the use of commodity hedge contracts. Oil accounted for
69
% and
75
% of our total production in the first
quarter
of 201
7
and 201
6
, respectively
. As a result, our operating cash flows are more sensitive to fluctuations in oil prices than they are to fluctuations in NGL or natural gas prices.
As of
March 31
, 201
7
, we had derivative contracts covering the sale of approximately
48%
of our forecasted oil production volumes for the remainder of 201
7
.
For a list of all of our outstanding derivatives as of
March 31
, 201
7
, refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”.
During the first
quarter
of 201
7
, we generated $
80
million of cash provided by operating activities, a
n
in
crease of $
34
million over the same period in 201
6
. Cash provided by operating activities
in
creased primarily due to
higher
realized sales prices for
oil
, NGLs
and natural gas
, as well as
lower lease operating expenses,
cash interest expense
,
exploration costs
and general and administrative expenses
during
the first
quarter
of 201
7
as compared to the same period in 201
6
.
These
positive
factors were partially offset by
lower
crude oil,
NGL and natural gas
production volumes
and a decrease in cash settlements received on our derivative contracts
, as well as
higher
production taxes during the first
quarter
of 201
7
. Refer to “Results of Operations” for more information on the impact of
volumes
and
prices
on revenues and for more information on increases and decreases in certain expenses between periods.
During the first
quarter
of 201
7
, cash flows from operating activities
and cash on hand
plus
$
378
million in proceeds from the sale of oil and gas properties were used to finance
the redemption of the remaining $275 million of our 2018 Senior Subordinated Notes
,
$
133
m
illion of drilling and development expenditures
and
$
100
million
of
net repayments under our credit
agreement
.
Exploration and Development Expenditures
.
The following
table
details our exploration
and
development expenditures incurred by
core area
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2017
|
|
2016
|
Northern Rocky Mountains
|
|
$
|
132,536
|
|
$
|
198,150
|
Central Rocky Mountains
|
|
|
53,045
|
|
|
52,533
|
Permian Basin
(1)
|
|
|
-
|
|
|
15,058
|
Other
(2)
|
|
|
210
|
|
|
1,553
|
Total incurred
|
|
$
|
185,791
|
|
$
|
267,294
|
|
(1)
|
|
I
n July 2016, we sold our
enhanced oil recovery
project at North Ward Estes
.
|
|
(2)
|
|
Other primarily includes non-core oil and gas properties located in Colorado, Mississippi, North Dakota, Texas and Wyoming.
|
We continually evaluate our capital needs and compare them to our capital resources.
Our
201
7
exploration and development
(“E&D”)
budget
is
$
1.1
b
illion, which we expect to fund substantially with net cash provided by operating activities,
proceeds from property divestitures
,
borrowings under our credit facility
or by accessing the capital markets
.
The
2017 E&D budget
represents a
n
in
crease
over
the $
554
m
illion
i
ncurred on
E&D
expenditures during 201
6
. This
increased
capital budget is in response to the
higher
crude oil prices experienced during
the fourth quarter of
201
6
and continuing into 201
7.
A portion of the 2017 budget will be used to resume comple
tions at our Redtai
l field in early 2017, as this activity had been suspended in th
is
area since the second quarter of 2016
. We believe that should additional attractive acquisition opportunities arise or
E&D
expenditures exceed $
1.1
b
illion, we will be able
to finance additional capital expenditures
through
agree
ments with industry partners,
divestitures of certain oil and gas property interests
, borrowings under our credit agreement or by accessing the capital markets
. Our level of
E&D
expenditures is largely discretionary and the amount of funds
we
devote to any particular activity may increase or decre
ase significantly depending on
commodity prices, cash flows
, available opportunities
and development results, among other factors. We believe that we have sufficient liquidity and capital resources to execute our business plan
over the next 12 months and for the foreseeable future.
With our expected cash flow streams, commodity price hedging strategies, current liquidity levels
(including availability under our credit agreement)
, access to debt and equity markets and flexibility to modify future capital expenditure programs, we expect to be able to fund all planned capital programs and debt repayments, comply with our debt covenants, and meet other obligations that may arise from our oil and gas operations.
Credit Agreement
. Whiting
Oil and Gas, our wholly
owned subsidiary, has a credit agreement with a syndicate of banks that as of
March 31, 2017
had a borrowing base
and
aggregate commitments of
$2.5
billion.
As of
March 31, 2017
, we had
$2.0
billion of available borrowing capacity, which was net of
$450
million in borrowings and
$9
million in letters of credit outstanding.
The borrowing base under the credit agreement is determined at the discretion of
our
lenders, based on the collateral value of our 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 bas
e.
Because oil and gas prices are principal inputs into the valuation of our reserves, if
current
or
projected
oil and gas prices
decline from their current levels
, our borrowing base could be reduced at the next redetermination date
, which is scheduled for
November
1, 2017,
or during future redeterminations. Upon a redetermination of our borrowing base, either on a periodic or special redetermination date,
if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement.
In April 2017, the lenders under our credit agreement reaffirmed the $2.5 billion borrowing base in connection with the May 1, 2017 regular borrowing base redetermination.
A portion of the revolving credit facility in an aggr
egate amount not to exceed $
50
million may b
e used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of ours. As of
March 31, 2017
,
$41
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 our 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, we also incur 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.
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Applicable
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Applicable
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Margin for Base
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Margin for
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Commitment
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Ratio of Outstanding Borrowings to Borrowing Base
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Rate Loans
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Eurodollar Loans
|
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Fee
|
Less than 0.25 to 1.0
|
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1.00%
|
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2.00%
|
|
0.50%
|
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
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1.25%
|
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2.25%
|
|
0.50%
|
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
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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
|
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2.00%
|
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3.00%
|
|
0.50%
|
The credit agreement contains restrictive covenants that may limit our 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 our lenders.
However, the credit agreement permits us and certain of our 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 our ability to make any dividend payments or distributio
ns on our common stock. These restrictions apply to all of
our restricted
subsidiaries
(as defined in the credit agreement)
. The credit agreement requires us, 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 th
an 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).
We were in compliance with our covenants under the credit agreement as of
March 31, 2017
.
However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these covenants in the future.
For further information on the loan security related to our credit agreement, refer to the
“
Long-Term Debt
”
footnote in the notes to
condensed
consolidated financial statements.
Senior Notes and Senior Subordinated Notes
. In March 2015, we issued at par $750 million of 6.25% Senior Notes due April 2023 (the “2023 Senior Notes”). In September 2013, we 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” and together with the 2023 Senior Notes and the 2019 Senior Notes, the “Senior Notes”). In September 2010, we issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).
Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes.
During
2016, we exchange
d (i) $75
million aggregate principal amount of our 2018 Senior Subordinated Notes, (ii) $
139
million aggregate principal amount of our 2019 Senior Notes, (iii) $
326
million aggregate principal amount of our 2021 Senior Notes, and (iv) $
342
million aggregate principal amount of our 2023 Senior Notes, for
the same
aggregate principal amount of
convertible notes
.
Subsequently d
uring 2016, all $
882
million aggregate principal amount of the
se
c
onvertible
n
otes
was converted into
approximately
8
6
.4
million shares of our common stock
pursuant to the terms of the
notes
.
Redemption of 2018 Senior Subordinated Notes.
On January 3, 2017, the trustee under the indenture governing our 2018 Senior Subordinated Notes provided notice to the holders of such notes that we elected to redeem all of the remaining $275 million aggregate principal amount of our 2018 Senior Subordinated Notes on February 2, 2017, and on that date, we paid $281 million consisting of the 100% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with borrowings under our credit agreement.
2020 Convertible Senior Notes.
In March 2015, we issued at par $1,250 million of 1.25% Convertible Senior Notes due April 2020 (the “2020 Convertible Senior Notes”).
During
2016, we exchange
d
$
688
million aggregate principal amount of our 2020 Convertible Senior Notes for the same aggregate principal amount of new mandatory convertible senior notes
. Subsequently during 2016, all $688 million aggregate principal amount of these mandatory convertible senior notes was converted into approximately
71
.1
million shares of our common stock
pursuant to the terms of the
notes
.
For the remaining $562 million aggregate principal amount of 2020 Convertible Senior Notes, we have the option to settle conversions of the these notes with cash, shares of common stock or a combination of cash and common stock at our election. Our 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 our 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 our 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 our 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, we 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
March 31
, 201
7
, none of the contingent conditions allowing holders of the 2020 Convertible Senior Notes to convert these notes had been met.
Note Covenants.
The indentures governing the
Senior
Notes
restrict us from incurring additional indebtedness, subject to certain exceptions, unless our fixed charge coverage ratio (as defined in the indentures) is at least 2.0 to 1. If we were in violation of
this covenant
, then we may not be able to incur additional indebtedness, including under Whiting Oil and Gas’ credit agreement. Additionally, the
se
indentures contain restrictive covenants that may limit our ability to, among other things, pay cash dividends, make certain other restricted payments, redeem or repurchase our capital stock, make investments or issue preferred stock, sell assets, consolidate, merge or transfer all or substantially all of the assets of ours and our restricted subsidiaries taken as a whole, and enter into hedging contracts. These covenants may potentially limit the discretion of our management in certain respects.
We were in compliance with these covenants as o
f
March 31, 2017
. However, a substantial or extended decline in oil, NGL or natural gas prices may adversely affect our ability to comply with these cove
nants in the future.
Contractual Obligations and Commitments
Schedule of Contractual Obligations
. The following table summarizes our obligations and commitments as of
March 31, 2017
to m
ake future payments under certain contracts, aggregated by category of contractual obligation, for
the time periods
specified
below.
Th
is
table does not include
amounts payable under contracts where we cannot predict with accuracy the amount and timing of such payments, including any amounts we may be obligated to pay under our derivative contracts
,
as such payments are dependent upon the price of crude oil in effect at the time of settlement
,
and
any penalties that may be incurred
for underdelivery
under
our physical delivery contracts
.
For further information on these contracts refer to the “Derivative Financial Instruments” footnote in the notes to consolidated financial statements and “Delivery Commitments” in Item 2 of our Annual Report on Form 10-K for the period ended
December 31, 2016
.
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Payments due by period
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(in thousands)
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Less than 1
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More than 5
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Contractual Obligations
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Total
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|
year
|
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1-3 years
|
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3-5 years
|
|
years
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Long-term debt
(1)
|
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$
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3,255,389
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$
|
-
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|
$
|
1,411,409
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|
$
|
1,435,684
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$
|
408,296
|
Cash interest expense on debt
(2)
|
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502,996
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144,267
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234,173
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99,037
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25,519
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Asset retirement obligations
(3)
|
|
|
181,145
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6,477
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|
33,295
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|
13,104
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|
128,269
|
Water disposal agreement
(4)
|
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|
133,495
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|
|
16,481
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|
39,331
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|
39,808
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|
|
37,875
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Purchase obligations
(5)
|
|
|
28,710
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|
|
7,656
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|
|
15,312
|
|
|
5,742
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|
-
|
Pipeline transportation agreements
(6)
|
|
|
61,972
|
|
|
9,235
|
|
|
18,772
|
|
|
18,457
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|
|
15,508
|
Drilling rig contracts
(7)
|
|
|
17,998
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|
|
17,998
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|
|
-
|
|
|
-
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|
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-
|
Leases
(8)
|
|
|
20,247
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|
|
7,475
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|
|
12,323
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|
|
449
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-
|
Total
|
|
$
|
4,201,952
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|
$
|
209,589
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|
$
|
1,764,615
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|
$
|
1,612,281
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$
|
615,467
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(1)
|
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Long-term debt consists of the principal amounts of
the
Senior
Notes
and
the 2020 Convertible Senior Notes, as well as the outstanding borrowings under our credit agreement
.
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(2)
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Cash interest expense on
the
Senior
Notes
is estimated assuming no principal repayment until the
due dates of the instruments. Cash interest expense on the 2020 Convertible Senior Notes is estimated assuming no principal repayments or conversions prior to maturity. Cash interest expense on the credit agreement is estimated assuming no principal repayment until the December
2019 instrument due date and a fixed interest rate of
3.0
%.
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(3)
|
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Asset retirement obligations represent the present value of estimated amounts expected to be incurred in the future to plug and abandon oil and gas wells, remediate oil and gas properties and dismantle their related plants
,
facilities
and offshore platforms
.
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(4)
|
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We have one water disposal agreement which expires in 2024, whereby we have contracted for the transportation and disposal of the produced water from our Redtail field. Under the terms of the agreement, we are obligated to provide a minimum volume of produced water or else pay for any deficiencies at the price stipulated in the contract. The obligations reported above represent our minimum financial commitments pursuant to the terms of this contract, however, our actual expenditures under this contract may exceed the minimum commitments presented above.
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(5)
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We have
one
take-or-pay purchase agreement which expires in 20
20, whereby
we have committed to buy certain volumes of water for use in the fracture stimulation process
on wells we complete
in our Redtail field. Under the terms of the
agreement
, we are obligated to purchase a minimum volume of water or else pay for any deficiencies at the price stipulated in the contract. The purchasing obligations reported above represent our minimum financial commitments pursuant to the terms of th
is
contract, however, our actual expenditures under th
is
contract
may
exceed the minimum commitments presented above.
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(6)
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W
e have
three
pipeline transportation agreements with
two
different
sup
plier
s
, expiring in
2022,
2024 and
2025. Under two of these contracts,
we have committed to pay fixed monthly reservation fees on dedicated pipelines from our Redtail field for natural gas and NGL transportation capacity, plus a variable charge based on actual transportation volumes.
The remaining contract contains
a
commitment to transport
a minimum volume of crude oil via a certain
oil gathering system
or else pay for any deficiencies at a price stipulated in the contract.
The obligations reported above represent our minimum financial commitments pursuant to the terms of
this
contract, however, our actual expenditures under
this
contract may exceed the minimum commitments presented above.
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(7)
|
|
As of
March 31, 2017
, we had
four
drilling rigs under long-term contract
, all of which
expire in 2017.
As of
March 31, 2017
, e
arly termination of
these
contracts would require
termination
penalties of $
16
million, which would be in lieu of paying the remaining drilling commitments under these contracts.
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(8)
|
|
We lease
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 i
n 2020.
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Based on current oil and natural gas prices and anticipated levels of production, we believe that the estimated net cash generated from operations, together with cash on hand and amounts available under our credit agreement, will be adequate to meet future liquidity needs, including satisfying our financial obligations and funding our operati
ng,
development and exploration activities.
New Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to
“
Adopted and Recently Issued Accounting Pronouncements
”
within the “Basis of Presentation”
footnote in the notes to
condensed
consolidated financial statements.
Critical Accounting Policies and Estimates
Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10
‑K for the fiscal year ended
December 31, 2016
.
The following is a material update to such critical accounting policies and estimates:
Derivative and Embedded Derivative Instruments
. 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. We do not currently apply hedge accounting to any of our outstanding derivative instruments, and as a result, all changes in derivative fair values are recognized currently in earnings.
We determine the recorded amounts of our derivative instruments measured at fair value utilizing third-party valuation specialists. We review these valuations, including the related model inputs and assumptions, and analyze changes in fair value measurements between periods. We corroborate such inputs, calculations and fair value changes using various methodologies, and review unobservable inputs for reasonableness utilizing relevant information from other published sources. When available, we utilize counterparty valuations to assess the reasonableness of our valuations. The values we report in our financial statements change as the assumptions used in these valuations are revised to reflect changes in market conditions (particularly those for oil and natural gas futures) or other factors, many of which are beyond our control.
We periodically enter into commodity derivative contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize costless collars which are generally placed with major financial institutions, as well as swaps and crude oil sales and delivery contracts. We use hedging to help ensure that we have adequate cash flow to fund our capital programs and manage returns on our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. We evaluate the ability of our counterparties to perform at the inception of a hedging relationship and on a periodic basis as appropriate.
We value our costless collars and swaps using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and contractual prices for the underlying instruments, as well as other relevant economic measures. We value our long-term crude oil sales and delivery contracts based on a
probability-weighted
income approach which considers various assumptions, including quoted
spot
prices for commodities, market differentials for crude oil and U.S. Treasury rates. The discount rates used in the fair values of these instruments include a measure of nonperformance risk by the counterparty or us, as appropriate.
In addition, we evaluate the terms of our convertible debt and other contracts, if any, to determine whether they contain embedded components that are required to be bifurcated and accounted for separately as derivative financial instruments.
We valued the embedded derivatives related to our convertible notes using a binomial lattice model which considered various inputs including (i) our 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 our common stock.
We also have an embedded derivative related to our purchase and sale agreement with the buyer of the North Ward Estes Properties, which includes a contingent payment linked to NYMEX crude oil prices. We value this embedded derivative using a modified Black-Scholes swaption pricing model which considers various assumptions, including quoted forward prices for commodities, time value and volatility factors.
The discount rate used in the fair value of this instrument includes a measure of the counterparty’s nonperformance risk.
Effects of Inflation and Pricing
As a result of the sustained depressed commodity price environment d
uring 201
6
and continuing into 201
7
, w
e
have
experienced
lower
costs due to
a decrease
in
demand for oil field products and services. The oil and gas industry is very cyclical, and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and not adjust downward in proportion to prices. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties
and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase
in the near term
, higher
demand in the industry
could result in increases in the costs of materials, services and personnel.
Forward-Looking Statements
This report contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this r
eport, words such as we “expect
”
, “intend
”
, “plan
”
, “estimate
”
, “anticipate
”
,
“believe” or “should” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.
These risks and uncertainties include, but are not limited to: declines in
, or extended periods of low
oil, NGL or natural gas prices; our level of success in exploration, development and production activities; risks related to our level of indebtedness
, ability to comply with debt covenants
and periodic redeterminations of the borrowing base under our credit agreement; impacts to financial statements as a result of impairment write-downs; our ability to successfully complete asset dispositions and the risks related thereto; revisions to reserve estimates as a result of changes in commodity prices, regulation and other factors;
adverse weather conditions that may negatively impact development or production activities; the timing of our exploration and development expenditures; inaccuracies of our reserve estimates or our assumptions underlying them; risks relating to any unforeseen liabilities of ours; our ability to generate sufficient cash flows from operations to meet the internally funded portion of our capital expenditures budget; our ability to obtain external capital to finance exploration and development operations; federal and state initiatives relating to the regulation of hydraulic fracturing
and air emissions
; unforeseen underperformance of or liabilities associated with acquired properties; the impacts of hedging on our results of operations; failure of our properties to yield oil or gas in commercially viable quantities; availability of, and risks associated with, transport of oil and gas; our ability to drill producing wells on undeveloped acreage prior to its lease expiration; shortages of or delays in obtaining qualified personnel or equipment, including drilling rigs and completion services; uninsured or underinsured losses resulting from our oil and gas operations; our inability to access oil and gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and gas operations;
the potential impact of changes in laws, including tax reform, that could have a negative effect on the oil and gas industry;
our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and gas industry; cyber security attacks or failures of our telecommunication systems;
and other risks described under the caption “Risk Factors”
in Item 1A of
our Annual Report on Form 10
‑K for the period ended
December 31, 2016
. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.