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, 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, 2017. 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 2017 Annual Report on Form 10
‑K.
Reclassifications
—
Certain prior period balances in the
condensed
consolidated balance sheets have been reclassified to conform to the current year presentation. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
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 FASB subsequently issued
various ASUs
which deferred the effective date of ASU 2014-09 and provided additional implementation guidance
,
and these ASUs
collectively make up FASB ASC Topic 606 –
Revenue from
C
ontracts with
C
ustomers
(“ASC 606”)
. The objective of
ASC 606
is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.
ASC 606 is
effective for fiscal years, and interim periods within those years, beginning after December
15
, 2017.
The standard permit
s
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 adopted
ASC 606
effective January 1, 2018 using the modified retrospective approach. The adoption
did
not have an impact on the Company’s net income
or cash flows
,
and
the Company did not record a cumulative-effect adjustment to retained earnings as a result
.
H
owever, t
he adoption
did
result in changes to the classification of
certain
fees incurred under pipeline gathering and transportation agreements and gas processing agreements, as well as certain costs attributable to non-operated properties
, which led to
an overall decrease in total revenues with a corresponding decrease in lease operating expenses under the new standard
.
Refer to the “Revenue
Recognition
” footnote for further information on the Company’s
implementation
of th
is standard
.
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
.
The FASB subsequently issued various ASUs which provided additional implementation guidance.
ASU 2016-02
and its amendments are
effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018 and should be applied using a modified retrospective approach. Early adoption is permitted. Although the Company is still in the process of evaluating the effect of adopting ASU 2016
‑02, the adoption is expected to result in (i) an increase in the assets and liabilities recorded on its consolidated balance sheet, (ii) an increase in depreciation, depletion and amortization expense and interest expense recorded on its consolidated statement of operations, and (iii) additional disclosures. As of
March
31, 201
8
, the Company had approximately $
80
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
this standard
.
In March 2018, the FASB issued Accounting Standards Update No. 2018-05,
Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118
(“ASU 2018-05”). The objective of this ASU is to codify the guidance provided by Staff Accounting Bulletin No. 118 regarding the accounting for the income tax effects of the Tax Cuts and Jobs Act (the “TCJA”) passed by Congress in
December 2017 if such accounting is not complete by the time a company issues its financial statements that include the reporting period in which the TCJA was enacted. ASU 2018-05 was effective upon addition to the FASB Codification in March 2018.
2.
OIL AND GAS PROPERTIES
Net capitalized costs related to the Company’s oil and gas producing activities at
March 31, 2018
and
December 31, 2017
are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
|
2018
|
|
2017
|
Proved leasehold costs
|
|
$
|
2,623,654
|
|
$
|
2,622,576
|
Unproved leasehold costs
|
|
|
132,759
|
|
|
137,694
|
Costs of completed wells and facilities
|
|
|
8,468,966
|
|
|
8,288,591
|
Wells and facilities in progress
|
|
|
248,113
|
|
|
244,789
|
Total oil and gas properties, successful efforts method
|
|
|
11,473,492
|
|
|
11,293,650
|
Accumulated depletion
|
|
|
(4,368,947)
|
|
|
(4,185,301)
|
Oil and gas properties, net
|
|
$
|
7,104,545
|
|
$
|
7,108,349
|
3.
ACQUISITIONS AND DIVESTITURES
2018 Acquisitions and Divestitures
There were no significant acquisitions or divestitures during the three months ended March 31, 2018.
2017 Acquisitions and Divestitures
On September 1, 2017, the Company completed the sale of its interests in certain producing oil and gas properties located in the Fort Berthold Indian Reservation area in Dunn and McLean counties of North Dakota, as well as other related assets and liabilities, for aggregate sales proceeds of $500 million (before closing adjustments). The sale was effective September 1, 2017 and resulted in a pre-tax loss on sale of $402 million. The Company used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
On January 1, 2017, the Company completed the sale of
its
50% interest in the Robinson Lake gas processing plant located in Mountrail County, North Dakota and its 50% interest in the Belfield gas processing plant located in Stark County, North Dakota, as well as the associated natural gas, crude oil and water gathering systems, effective January 1, 2017, for aggregate sales proceeds of $375 million (before closing adjustments). The Company used the net proceeds from this transaction to repay a portion of the debt outstanding under its credit agreement.
There were no significant acquisitions during the
year
ended
December 31
, 201
7
.
4
. LONG-TERM DEBT
Long-term debt
, including the current portion,
consisted of the following at
March 31, 2018
and
December 31, 2017
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
|
2018
|
|
2017
|
Credit agreement
|
|
$
|
90,000
|
|
$
|
-
|
5.0%
Senior Notes due 2019
|
|
|
-
|
|
|
961,409
|
1.25%
Convertible Senior Notes due 2020
|
|
|
562,075
|
|
|
562,075
|
5.75%
Senior Notes due 2021
|
|
|
873,609
|
|
|
873,609
|
6.25%
Senior Notes due 2023
|
|
|
408,296
|
|
|
408,296
|
6.625%
Senior Notes due 2026
|
|
|
1,000,000
|
|
|
1,000,000
|
Total principal
|
|
|
2,933,980
|
|
|
3,805,389
|
Unamortized debt discounts and premiums
|
|
|
(45,572)
|
|
|
(50,945)
|
Unamortized debt issuance costs on notes
|
|
|
(26,980)
|
|
|
(31,015)
|
Total debt
|
|
|
2,861,428
|
|
|
3,723,429
|
Less current portion of long-term debt
|
|
|
-
|
|
|
(958,713)
|
Total long-term debt
|
|
$
|
2,861,428
|
|
$
|
2,764,716
|
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, 2018 had a borrowing
base
and aggregate commitments of
$2.3
billion. As of March 31, 2018, the Company had
$2.2
billion of available borrowing capacity, which was net of
$90
million in borrowings and
$2
million in letters of credit outstanding.
On April 12, 2018, the Company entered into a Seventh Amended and Restated Credit Agreement, which replace
d
its existing credit agreement on that date. This amended credit agreement, among other things, (i) increased the borrowing base under the facility from $2.3 billion to
$2.4
billion, (ii) reduced the aggregate commitments from $2.3 billion to
$1.75
billion, (iii) extended the principal repayment date from December 2019 to April 2023, (iv) decreased the applicable margin based on the borrowing base utilization percentage by
50
basis points per annum, (v) decreased the commitment fee to
37.5
basis points per annum for certain ratios of outstanding borrowings to the borrowing base as shown in the table below, (vi) modified certain financial covenants as discussed below
, and (vii) removed the ability of the Company and certain of its subsidiaries to issue second lien indebtedness of up to
$1.0
billion
.
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 redeter
minations on May 1 and November
1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. Upon a redetermination of the borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, the Company could be forced to immediately repay a portion of its debt outstanding under the credit agreement.
A portion of the revolving credit facility in an aggregate amount not to exceed
$50
million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company. As of
March 31, 2018
,
$48
million was available for additional letters of credit under the agreement.
The
credit agreement provides for interest only payments until
maturity
, when the credit agreement expires and all outstanding borrowings are due. Interest under the
amended credit agreement
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
amended credit agreement
, which are included as a component of interest expense.
At March 31, 2018,
the weighted average interest rate on the outstanding principal balance under the credit agreement
was
3.9%
.
|
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|
|
|
|
|
|
|
Applicable
|
|
Applicable
|
|
|
|
|
Margin for Base
|
|
Margin for
|
|
Commitment
|
Ratio of Outstanding Borrowings to Borrowing Base
|
|
Rate Loans
|
|
Eurodollar Loans
|
|
Fee
|
Less than
0.25
to 1.0
|
|
0.50%
|
|
1.50%
|
|
0.375%
|
Greater than or equal to
0.25
to 1.0 but less than
0.50
to 1.0
|
|
0.75%
|
|
1.75%
|
|
0.375%
|
Greater than or equal to
0.50
to 1.0 but less than
0.75
to 1.0
|
|
1.00%
|
|
2.00%
|
|
0.50%
|
Greater than or equal to
0.75
to 1.0 but less than
0.90
to 1.0
|
|
1.25%
|
|
2.25%
|
|
0.50%
|
Greater than or equal to
0.90
to 1.0
|
|
1.50%
|
|
2.50%
|
|
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. 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, 2018
, there were
no
retained earnings free from restrictions.
As of March 31, 2018, the existing
credit agreement require
d
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 and (iii) a ratio of the last four quarters’ EBITDAX to consolidated
cash
interest charges of not less than
2.25
to 1.0.
The amended credit agreement requires the Company, as of the last day of any quarter, to maintain the following ratios (as defined in the amended 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 and (ii) a total debt to last four quarters’ EBITDAX ratio of less than
4.0
to 1.0.
The Company was in compliance with its covenants under the credit agreement as of
March 31, 2018
.
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, 2018
:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
Convertible
|
|
2021
|
|
2023
|
|
2026
|
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
|
Senior Notes
|
Outstanding principal (in thousands)
|
|
$ 562,075
|
|
$ 873,609
|
|
$ 408,296
|
|
$ 1,000,000
|
Interest rate
|
|
1.25%
|
|
5.75%
|
|
6.25%
|
|
6.625%
|
Maturity date
|
|
Apr 1, 2020
|
|
Mar 15, 2021
|
|
Apr 1, 2023
|
|
Jan 15, 2026
|
Interest payment dates
|
|
Apr 1, Oct 1
|
|
Mar 15, Sep 15
|
|
Apr 1, Oct 1
|
|
Jan 15, Jul 15
|
Make-whole redemption date
(1)
|
|
N/A
(2)
|
|
Dec 15, 2020
|
|
Jan 1, 2023
|
|
Oct 15, 2025
|
|
(1)
|
|
On or after these dates, the Company may redeem the applicable series of notes, in whole or in part, at a redemption price equal to
100%
of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, the Company may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.
|
|
(2)
|
|
The indenture governing our 1.25% Convertible Senior Notes due 2020 do
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”).
In December 2017, the Company issued at par
$1.0
billion of
6.625%
Senior Notes due January 2026 (the “2026 Senior Notes” and together with the 2021 Senior Notes and the 2023 Senior Notes, the “Senior Notes”).
The Company used the net proceeds from this offering to redeem on January 26, 2018 all of the outstanding 2019 Senior Notes.
Refer to “Redemption of 2019 Senior Notes” below for more information on the redemption of the 2019 Senior Notes.
Exchange of Senior Notes and Senior Subordinated Notes for Convertible Notes.
During 2016, the Company exchanged (i)
$75
million aggregate principal amount of its 2018 Senior Subordinated Notes, (ii)
$139
million aggregate principal amount of its 2019 Senior Notes, (iii)
$326
million aggregate principal amount of its 2021 Senior Notes, and (iv)
$342
million aggregate principal amount of its 2023 Senior Notes, for the same aggregate principal amount of convertible notes. Subsequently during 2016, all
$882
million aggregate principal amount of these convertible notes was converted into approximately
21.6
million shares of the Company’s common stock
pursuant to the terms of the
notes
.
Redemption of 2018 Senior Subordinated Notes.
O
n F
ebruary 2, 2017,
the Company paid
$281
million
to redeem
all of the
then outstanding
$275
million aggregate principal amount of
2018
Senior Subordinated Notes
, which payment consisted
of the
100%
redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption with borrowings under its credit agreement.
As a result of the redemption, Whiting recognized a
$2
million loss on extinguishment of debt, which consisted of a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2017,
no
2018 Senior Subordinated Notes remained outstanding.
Redemption of 2019 Senior Notes.
O
n January 26, 2018,
the Company
paid
$1.0
billion to redeem all of the remaining $961 million aggregate principal amount of the 2019 Senior Notes
, which payment consisted
of the
102.976%
redemption price plus all accrued and unpaid interest on the notes. The Company financed the redemption with proceeds from the issuance of the 2026 Senior Notes and borrowings under its credit agreement.
As a result of the redemption, the Company recognized a
$31
million loss on extinguishment of debt, which included
the redemption premium and
a non-cash charge for the acceleration of unamortized debt issuance costs on the notes. As of March 31, 2018, no 2019 Senior Notes remained outstanding.
2020 Convertible Senior
Notes
—In March 2015, the Company issued at par
$1,250
million of
1.25%
Convertible Senior Notes due April 2020 (the “
2020
Convertible Senior Notes”
) f
or net proceeds of
$1.2
billion, net of initial purchasers’ fees of
$25
million.
During 2016, the Company exchanged
$688
million aggregate principal amount of its 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 notes was converted into approximately
17.8
million shares of the Company’s common stock pursuant to the terms of the notes.
For the remaining $
562
million aggregate principal amount of 2020 Convertible Senior Notes outstanding as of March 31, 2018, t
he Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the
2020
Convertible Senior Notes in cash upon conversion. Prior to January 1, 2020, the
2020
Convertible Senior Notes will be convertible
at the holder’s option
only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on June 30, 2015 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least
20
trading days (whether or not consecutive) during the period of
30
consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to
130%
of the conversion price on each applicable trading day; (ii) during the
five
business day period after any
five
consecutive trading day period (the “measurement period”) in which the trading price per
$1,000
principal amount of the
2020
Convertible Senior Notes for each trading day of the measurement period is less than
98%
of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after January 1, 2020, the
2020
Convertible Senior Notes will be convertible at any time until the second scheduled trading day immediately preceding the April 1, 2020 maturity date of the notes. The notes will be convertible at a
current
conversion rate of
6.4102
shares of Whiting’s common stock per
$1,000
principal amount of the notes, which is equivalent to a
current
conversion price of approximately
$156.00
. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, the Company will increase, in certain circumstances, the conversion rate for a holder who elects to convert its
2020
Convertible Senior Notes in connection with such corporate event. As of
March 31, 2018
, none of the contingent conditions allowing holders of the
2020
Convertible Senior Notes to convert these notes had been met.
Upon issuance, the Company separately accounted for the liability and equity components of the
2020
Convertible Senior Notes. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the
2020
Convertible Senior Notes and the estimated fair value of the liability component was recorded as a debt discount and
is being
amortized to interest expense over the term of the notes using the effective interest method, with an effective interest rate of
5.6%
per annum. The fair value of the
liability component of the
2020
Convertible Senior Notes as of the issuance date was estimated at
$1.0
billion, resulting in a debt discount at inception of
$238
million. The equity component, representing
the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the
2020
Convertible Senior Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within shareholders’ equity, and will not be remeasured as long as it continues to meet the conditions for equity classification.
Transaction costs related to the
2020
Convertible Senior Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were recorded
as a reduction to the carrying value of long-term
debt on the consolidated balance sheet and are being amortized to
interest
expense over the term of the notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within shareholders’ equity.
The
2020
Convertible Senior Notes consist
ed
of the following at
March 31, 2018
and December 31, 2017
(in thousands):
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|
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|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
|
|
2018
|
|
2017
|
Liability component
|
|
|
|
|
|
|
Principal
|
|
$
|
562,075
|
|
$
|
562,075
|
Less: unamortized note discount
|
|
|
(46,241)
|
|
|
(51,666)
|
Less: unamortized debt issuance costs
|
|
|
(3,721)
|
|
|
(4,178)
|
Net carrying value
|
|
$
|
512,113
|
|
$
|
506,231
|
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
.
|
Interest expense recognized on the 2020 Convertible Senior Notes related to the stated interest rate and amortization of the debt discount totaled
$7
million for each of the three months ended March 31, 2018 and 2017.
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, 2018
and
December 31, 2017
were
$
6
million and
$
5
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, 2018
(in thousands):
|
|
|
|
|
|
|
|
Asset retirement obligation at January 1, 2018
|
|
$
|
134,237
|
Additional liability incurred
|
|
|
1,449
|
Revisions to estimated cash flows
|
|
|
68
|
Accretion expense
|
|
|
2,708
|
Liabilities settled
|
|
|
(1,142)
|
Asset retirement obligation at March 31, 2018
|
|
$
|
137,320
|
6
.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, and
it
uses derivative instruments to manage its commodity price risk.
In addition, the Company periodically enters into contracts that contain embedded features which are required to be bifurcated and accounted for separately as derivatives.
Commodity Derivative Contracts
—
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. Whiting
primarily
enters into derivative contracts such as crude oil costless collars
and swaps, as well as
sales and delivery contracts
,
to achieve a more predictable cash flow by reducing its exposure to commodity price volatility
,
thereby
ensuring
adequate
funding for
the Company’s capital programs and
facilitating the management of
returns on drilling programs
and
acquisitions. The Company does not enter into derivative contracts for speculative or trading purposes.
Crude Oil Costless Collars
and Swaps
.
Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production
, while swaps establish a fixed price for 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
and swap
derivatives entered into to hedge forecasted crude oil production revenues as of
March 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
|
|
|
|
Contracted Crude
|
|
Weighted Average NYMEX Price
|
Instrument
|
|
Period
|
|
Oil Volumes (Bbl)
|
|
for Crude Oil (per Bbl)
|
Three-way collars
(1)
|
|
Apr - Dec 2018
|
|
13,050,000
|
|
$37.07
-
$47.07
-
$57.30
|
Swaps
|
|
Apr - Dec 2018
|
|
3,600,000
|
|
$61.74
|
Collars
(2)
|
|
Jan - Jun 2019
|
|
1,500,000
|
|
$50.00
-
$65.90
|
|
|
Total
|
|
18,150,000
|
|
|
|
(1)
|
|
A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
|
|
(2)
|
|
Subsequent to March 31, 2018, the Company entered into additional costless collar contracts for
9
00,000
Bbl of crude oil volumes for the six months ended June 30, 2019.
|
Crude Oil Sales and Delivery Contract.
As of December 31, 2017, t
he Company ha
d
a long-term crude oil sales and delivery contract for oil volumes produced from its Redtail field in Colorado. Under the terms of the agreement, Whiting ha
d
committed to deliver certain fixed volumes of crude oil through
April
2020. The Company determined it was not probable that future oil production from its Redtail field would be sufficient to meet the minimum volume requirement
s
specified in this contract
; a
ccordingly, the Company would not settle this contract through physical delivery of crude oil volumes. As a result, Whiting determined that this contract would not qualify for the “normal purchase normal sale” exclusion and has therefore reflected the contract at fair value in the consolidated financial statements. As of
December 31, 2017
, the estimated fair value of this derivative contract was a liability of
$
63 million
.
On February 1, 2018, Whiting paid
$61
million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this crude oil sales and delivery contract was fully terminated
,
and the fair value of this corresponding derivative was therefore zero as of that date.
Embedded
Derivative
s
—
In July 2016, the Company
entered into a purchase and sale agreement with the buyer of its North Ward Estes Properties, whereby the buyer agreed to pay Whiting additional proceeds of
$100,000
for every $0.01 that, as of June 28, 2018, the average NYMEX crude oil futures contract price for each month from August 2018 through July 2021 is above
$50.00/Bbl
up to a maximum amount of
$100
million. The Company determined that this NYMEX-linked contingent payment was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature and reflected it
at
its estimated
fair value in the consolidated financial statements.
On July 19, 2017, the buyer paid
$35
million to Whiting to settle this NYMEX-linked contingent payment, and accordingly, the embedded derivative’s fair value was
zero
as of December 31, 2017 and March 31, 2018.
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, 2018 and 2017
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Recognized in Income
|
Not Designated as
|
|
Statement of Operations
|
|
Three Months Ended March 31,
|
ASC 815 Hedges
|
|
Classification
|
|
2018
|
|
2017
|
Commodity contracts
|
|
Derivative loss, net
|
|
$
|
52,664
|
|
$
|
23,351
|
Embedded derivatives
|
|
Derivative loss, net
|
|
|
-
|
|
|
13,226
|
Total
|
|
|
|
$
|
52,664
|
|
$
|
36,577
|
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, 2018
(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
|
|
$
|
6,038
|
|
$
|
(6,038)
|
|
$
|
-
|
Commodity contracts - non-current
|
|
Other long-term assets
|
|
|
1,925
|
|
|
(1,925)
|
|
|
-
|
Total derivative assets
|
|
|
|
$
|
7,963
|
|
$
|
(7,963)
|
|
$
|
-
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
105,058
|
|
$
|
(6,038)
|
|
$
|
99,020
|
Commodity contracts - non-current
|
|
Other long-term liabilities
|
|
|
2,221
|
|
|
(1,925)
|
|
|
296
|
Total derivative liabilities
|
|
|
|
$
|
107,279
|
|
$
|
(7,963)
|
|
$
|
99,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
(1)
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
Gross
|
|
|
|
|
Recognized
|
|
|
|
|
Recognized
|
|
Gross
|
|
Fair Value
|
Not Designated as
|
|
|
|
Assets/
|
|
Amounts
|
|
Assets/
|
ASC 815 Hedges
|
|
Balance Sheet Classification
|
|
Liabilities
|
|
Offset
|
|
Liabilities
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Prepaid expenses and other
|
|
$
|
9,829
|
|
$
|
(9,829)
|
|
$
|
-
|
Total derivative assets
|
|
|
|
$
|
9,829
|
|
$
|
(9,829)
|
|
$
|
-
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - current
|
|
Derivative liabilities
|
|
$
|
142,354
|
|
$
|
(9,829)
|
|
$
|
132,525
|
Total derivative liabilities
|
|
|
|
$
|
142,354
|
|
$
|
(9,829)
|
|
$
|
132,525
|
|
(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
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, 2018 and December 31, 2017 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
|
Value
(1)
|
|
Value
(2)
|
|
Value
(1)
|
|
Value
(2)
|
5.0%
Senior Notes due 2019
|
|
$
|
-
|
|
$
|
-
|
|
$
|
985,444
|
|
$
|
958,713
|
1.25%
Convertible Senior Notes due 2020
|
|
|
528,351
|
|
|
512,113
|
|
|
517,109
|
|
|
506,231
|
5.75%
Senior Notes due 2021
|
|
|
882,345
|
|
|
869,592
|
|
|
897,633
|
|
|
869,284
|
6.25%
Senior Notes due 2023
|
|
|
412,889
|
|
|
404,115
|
|
|
418,503
|
|
|
403,940
|
6.625% Senior Notes due 2026
|
|
|
1,007,500
|
|
|
985,608
|
|
|
1,025,000
|
|
|
985,261
|
Total
|
|
$
|
2,831,085
|
|
$
|
2,771,428
|
|
$
|
3,843,689
|
|
$
|
3,723,429
|
|
(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 liabilities measured at fair value on a recurring basis as of
March 31, 2018
and
December 31, 2017
, 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, 2018
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
99,020
|
|
$
|
-
|
|
$
|
99,020
|
Commodity derivatives – non-current
|
|
|
-
|
|
|
296
|
|
|
-
|
|
|
296
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
99,316
|
|
$
|
-
|
|
$
|
99,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
December 31, 2017
|
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives – current
|
|
$
|
-
|
|
$
|
69,247
|
|
$
|
63,278
|
|
$
|
132,525
|
Total financial liabilities
|
|
$
|
-
|
|
$
|
69,247
|
|
$
|
63,278
|
|
$
|
132,525
|
The following methods and assumptions were used to estimate the fair values of the Company’s financial assets and liabilities that are measured on a recurring basis:
Commodity Derivatives
.
Commodity derivative instruments consist mainly of costless collars for crude oil. The Company’s costless collars are valued based on an income approach.
T
he option model consider
s
various assumptions, such as quoted forward prices for commodities, time value and volatility factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy. The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.
The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
In addition, the Company ha
d
a
long-term crude oil sales
and delivery contract, whereby it ha
d
committed to deliver certain fixed volumes of crude oil through April 2020.
Whiting determined that the contract d
id
not meet the “normal purchase normal sale” exclusion, and therefore reflected this contract at fair value in its consolidated financial statements
prior to settlement
.
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 Leve
l 3 within the valuation hierarchy. On February 1, 2018, Whiting paid
$61
million to the counterparty to settle all future minimum volume commitments under this agreement. Accordingly, this derivative was settled in its entirety as of that date.
Embedded Derivatives
.
The Company ha
d
an embedded derivative
related to its purchase and sale agreement with the buyer of the North Ward Estes Properties. The agreement included a contingent payment linked to NYMEX crude oil prices which the Company determined was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded feature
and reflected
it
at fair value in the consolidated financial statements
prior to settlement
. The fair value of this embedded derivative
was
determined using a
modified Black-Scholes
swaption pricing model which considers various assumptions,
including
quoted forward prices for commodities, time value and volatility factors. These assumptions
we
re observable in the marketplace throughout the full term of the financial instrument
,
could
be derived from observable data or
we
re supported by observable levels at which transactions are executed in the marketplace, and
we
re therefore designated as Level 2 within the valuation hierarchy.
The discount rate used in the fair value of this instrument include
d
a measure of the counterparty’s nonperformance risk.
On July 19, 2017, the buyer paid
$35
million to Whiting in satisfaction of this contingent payment. Accordingly, the embedded derivative was settled in its entirety as of that date.
Level 3 Fair Value Measurements
—
A third-party valuation specialist is utilized
in
determini
ng
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, 2018 and 2017 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Fair value liability, beginning of period
|
|
$
|
(63,278)
|
|
$
|
(9,214)
|
Unrealized gains (losses) on commodity derivative contracts included in earnings
(1)
|
|
|
2,242
|
|
|
(56,692)
|
Settlement of commodity derivative contracts
|
|
|
61,036
|
|
|
-
|
Transfers into (out of) Level 3
|
|
|
-
|
|
|
-
|
Fair value liability, end of period
|
|
$
|
-
|
|
$
|
(65,906)
|
|
(1)
|
|
Included in derivative loss
,
net in the consolidated statements of operations.
|
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 2018 or 2017 reporting periods presented.
8
.
SHAREHOLDERS’ EQUITY AND
NONCONTROLLING INTEREST
Common Stock
—
On November 8, 2017 and following approval by the Company’s stockholders of an amendment to its certificate of incorporation to effect a reverse stock split, the Company’s Board of Directors approved a reverse stock split of Whiting’s common stock at a ratio of
one
-for-four and a reduction in the number of authorized shares of the Company’s common stock from
600,000,000
shares to
225,000,000
. Whiting’s common stock began trading on a split-adjusted basis on November 9, 2017 upon opening of the markets. All share and per share amounts in these consolidated financial statements and related notes for periods prior to November 2017 have been retroactively adjusted to reflect the reverse stock split.
Noncontrolling Interest
—The Company’s noncontrolling interest represent
ed
an unrelated third party’s
25%
ownership interest in Sustainable Water Resources, LLC
(“SWR”)
.
During the
third
quarter of 2017, the
third party
’s
ownership interest
in SWR was assigned
back to SWR
.
9.
REVENUE
RECOGNITION
The Company adopted
ASC 606
effective January 1, 2018
, which
replaces previous revenue recognition requirements
under FASB
ASC
Topic
605
–
Revenue Recognition
(“ASC 605”)
.
The standard
was
adopted using the modified retrospective approach which requires the Company to
recognize in retained earnings at the date of adoption the cumulative effect of the application of ASC 606 to
all existing revenue contracts which were not substantially complete as of January 1, 2018.
T
he Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying ASC 606
.
Although t
he adoption of
ASC 606
did not have an impact on the Company’s net income or cash flows, it
did
result in the
re
classification of
certain
fees incurred under pipeline gathering and transportation agreements and gas processing agreements, as well as certain costs attributable to non-operated properties. Such
re
classification led to an overall decrease in total revenues with a corresponding decrease in lease operating expenses as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
|
Under ASC 606
|
|
Under ASC 605
|
|
Difference
|
OPERATING REVENUES
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
453,650
|
|
$
|
450,209
|
|
$
|
3,441
|
NGL and natural gas sales
|
|
|
61,433
|
|
|
74,639
|
|
|
(13,206)
|
Oil, NGL and natural gas sales
|
|
$
|
515,083
|
|
$
|
524,848
|
|
$
|
(9,765)
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
92,572
|
|
$
|
102,337
|
|
$
|
(9,765)
|
Total operating expenses
|
|
$
|
416,892
|
|
$
|
426,657
|
|
$
|
(9,765)
|
INCOME FROM OPERATIONS
|
|
$
|
98,191
|
|
$
|
98,191
|
|
$
|
-
|
The reclassification of fees between
operating
revenues and
expense
s
is
the
result of the Company’s
assessment
of the point in time
at
which
its
performance obligation
s
under its commodity sales contracts are
satisfied and control of the commodity is transferred to the customer.
The Company
has determined that its
contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs
contain
monthly performance obligation
s
to deliver product
at locations specified in the contract
.
Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized.
Fees included in the contract that are incurred prior to control transfer are classified as
lease operating
expense and fees incurred after control transfer
s
are included as a reduction to the transaction price
.
The transaction price at which revenue is recognized consists entirely of variable consideration
based on quoted market prices less various fees and the quantity of volumes delivered
.
Whiting receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets. As of January 1, 2018 and March 31, 2018, such receivable balances were $186 and $196 million, respectively. Variances between the Company’s estimated revenue and actual payments are recorded in the month
the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.
The Company
has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each monthly delivery of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required
.
The Company p
reviously utilize
d
the entitlements method to account for product imbalances
,
which is no longer applicable
under ASC 606
.
The
impact to the financial statements
resulting from this
change in accounting for our production imbalances
was not significant
.
10
.
STOCK-BASED COMPENSATION
Equity Incentive Plan
—
The Company maintains
the Whiting Petroleum Corporation 2013 Equity Incentive Plan
, as amended and restated (the “2013 Equity Plan”),
which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”)
and includ
es
the authority to issue
1,375,000
shares of the Company’s common stock.
Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated. The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms.
Any shares netted or forfeited under the 2003 Equity Plan
and any shares forfeited under the 2013 Equity Plan
will be available for future issuance under the 2013 Equity Plan.
However, shares netted for tax withholding under the 2013 Equity Plan will be cancelled and will not be available for future issuance.
Under the 2013 Equity Plan
,
no employee or officer participant may be granted options for more than
225,000
shares of common stock, stock appreciation rights relating to more than
225,000
shares of common stock, more than
150,000
shares of restricted stock
, more than
150,000
restricted stock units, more than
150,000
performance shares, or more than
150,000
performance units
during any calendar year.
In addition, no non-employee director participant may be granted options for more than
25,000
shares of common stock,
stock appreciation rights relating to more than
25,000
shares of common stock, more than
25,000
shares of restricted stock
, or more than
25,000
restricted stock units
during any calendar year.
As of
March 31, 2018
,
803,022
shares of common stock remained available for grant under the 2013 Equity Plan.
Restricted
Stock
Awards
, Restricted Stock Units and Performance
Shares
—The Company grants service-based restricted stock awards
and restricted stock units
to executive officers and employees, which generally vest ratably over a
three
-year service period
. The Company also grants
service-based restricted stock awards
to directors, which generally vest over a
one
-year service period. In addition, the Company grants
performance share
awards to executive officers that are subject to market-based vesting criteria as well as a
three
-year service period.
Upon adoption of ASU 2016-09 on January 1, 2017, the Company elected to account for forfeitures of awards granted under these plans as they occur in determining compensation expense
. The Company recognizes compensation expense for all awards subject to market-based vesting conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
During the three months ended March 31, 2018 and 2017,
215,898
and
369,061
shares, respectively, of service-based restricted stock
awards
were granted to employees, executive officers and directors under the 2013 Equity Plan.
The Company determines compensation expense for these share-settled awards
using
their fair value at the grant date
,
which is
based on the closing bid price of the Company’s common stock on
such
date. The weighted average grant date fair value of restricted stock
awards
was
$30.03
per share
and
$47.44
per share
for the three months ended March 31, 2018 and 2017
, respectively.
During the three months ended March 31, 2018,
308,432
shares of service-based restricted stock units were granted to employees under the 2013 Equity Plan. These awards will be settled
in cash
and are recorded as a liability in the consolidated balance sheets. The Company determines compensation expense for cash-settled restricted stock units
using
the fair value at the end of each reporting period
, which is based on the closing bid price of the Company’s common stock on such date.
In January 2018,
215,898
performance shares 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 on each anniversary of the grant date over the three-year performance period.
The number of
award
s earned could range from
zero
up to
two
times the number of shares initially granted. However, awards earned up to the target shares granted (or
100%
) will be settled
in shares
, while awards earned in excess of the target shares granted will be settled
in cash
.
The cash-settled component of such awards is recorded as a liability in the consolidated balance sheets
and will be remeasured at fair value using a Monte Carlo valuation model at the end of each reporting period
.
In January 2017,
158,363
performance
shares 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
and will be settled entirely in shares
.
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
and implied 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
8
|
|
201
7
|
Number of simulations
|
|
2,500,000
|
|
2,500,000
|
Expected volatility
|
|
72
.
80
%
|
|
82.44%
|
Risk-free interest rate
|
|
2.12%
|
|
1.52%
|
Dividend yield
|
|
-
|
|
-
|
The grant date fair value of the market-based
awards
that will be settled in shares,
as determined by the Monte Carlo valuation model
,
was
$
27
.
2
8
per share
and
$65.44
per share in January 201
8
and 201
7
, respectively.
The following table shows a summary of the Company’s restricted stock
award (“RSA”) and performance share
activity
for the three months ended
March 31
, 201
8
:
|
|
|
|
|
|
|
|
|
|
Number of Awards
|
|
Weighted Average
|
|
|
Service-Based
|
|
Market-Based
|
|
Grant Date
|
|
|
RSAs
|
|
Performance Awards
|
|
Fair Value
|
Nonvested awards, January 1
|
|
898,421
|
|
497,527
|
|
$
|
45.55
|
Granted
|
|
215,898
|
|
215,898
|
|
|
28.66
|
Vested
|
|
(333,203)
|
|
-
|
|
|
46.96
|
Forfeited
|
|
(4,878)
|
|
(90,668)
|
|
|
128.16
|
Nonvested awards,
March
31
|
|
776,238
|
|
622,757
|
|
$
|
34.36
|
Stock Options—
There was no significant stock option activity during the
three
months ended
March 31
, 201
8 and 2017.
For the three months ended March 31, 2018 and 2017,
the Company recognized
total stock compensation expense
of
$7
million and
$6
million, respectively.
11
. 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, 2018 and 2017 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% and 35%, respectively, to pre-tax income primarily because (i) for the three months ended March 31, 2017, state income taxes and estimated permanent differences increased and decreased, respectively, the expected tax benefit for the period and (ii) for the three months ended March 31, 2018, a full valuation allowance was in effect, which reduced the Company’s net tax expense to zero.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion, or all, of the Company’s deferred tax assets will not be realized. In making such determination, the Company considers all available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and projected future taxable income and results of operations. If the Company concludes that it is more likely than not that some portion, or all, of its deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. At December 31, 2017, the Company recorded a full valuation allowance on its net deferred tax assets. The Company assesses the appropriateness of its valuation allowance on a quarterly basis. As of March 31, 2018, there was no change in the Company’s assessment of the realizability of its deferred tax assets, and the full valuation allowance remains in effect.
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.
On December 22, 2017, Congress passed the TCJA. The new legislation significantly changed the U.S. corporate tax law by, among other things, lowering the U.S. corporate income tax rate from 35% to 21% beginning in January 2018, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries.
The SEC issued Staff Accounting Bulletin No. 118 (“SAB 118”), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used to account for business combinations, however, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 outlines a three-step process to be applied at each reporting period to account for and qualitatively disclose (i) the effects of the change in tax law for which accounting is complete, (ii) provisional amounts (or adjustments to provisional amounts) for the effects of the change in tax law where accounting is not complete, but where a reasonable estimate has been made, and (iii) areas affected by the change in tax law where a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the TCJA.
As of March 31, 2018, the Company’
s
accounting was complete for the change in the U.S. corporate income tax rate from 35% to 21% effective for tax years after December 31, 2017. At December 31, 2017, the Company was able to reasonably estimate the impact of the corporate tax rate reduction and recorded provisional (i) income tax expense of $51 million from the revaluation of the Company’s deferred tax assets and liabilities as of the date of enactment and (ii) income tax benefit totaling $93 million related to a reduction in the Company’s existing valuation allowances. No changes to the impact of the corporate tax rate reduction were recognized during the three months ended March 31, 2018.
Other elements of the TCJA for which the accounting is complete include (i) IRC Section 168(k) first-year optional bonus depreciation, (ii) repeal of the corporate alternative minimum tax, (iii) limitation on the usage of net operating losses generated after 2017 to 80% of taxable income, (iv) additional limitations on certain meals and entertainment expenses, (v) repeal of the deduction for income attributable to domestic production activities, and (vi) like-kind exchange limitations for property other than real property. These items did not have an impact on the Company’s financial statements upon enactment of the TCJA, but may impact the Company’s income taxes in future periods.
The TCJA modified executive compensation deduction limitations under IRC Section 162(m).
The Company was able to reasonably estimate the impacts of the Section 162(m) changes and recorded an initial provisional reduction to deferred tax assets of $1 million for the year ended December 31, 2017. The accounting for this item is not yet complete as further guidance is needed from tax authorities. The Company expects to complete its accounting within the prescribed measurement period.
The TCJA implemented mandatory repatriation of previously untaxed foreign earnings of specified foreign corporations. The Company has estimated that it has no untaxed foreign-sourced earnings and profits from a specified foreign corporation, and accordingly, no provisional amount was recorded as of March 31, 2018 or December 31, 2017. The Company expects to complete its accounting
for this element of the TCJA
within the prescribed measurement period.
The Company’s accounting for the following elements of the TCJA is incomplete
, however the Company expects to complete its accounting within the prescribed measurement period
:
(i)
ability to capitalize and amortize intangible drilling costs under IRC Section
59(e)
and (ii) i
nterest deduction limitations under
IRC Section
163(j)
. Reasonable estimates of the impact to the Company’s financial statements could not be made, and accordingly, no adjustments were recorded to the
financial statements
as of March 31, 2018 or
December 31, 2017. The Company will assess
the
impact of the
se sections of the TCJA
on its financial statements
as
further
clarification and
guidance
is issued by regulatory
authorities.
12
. EARNINGS PER SHARE
The reconciliations between basic and diluted
earnings (
loss
)
per share are as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Basic Earnings (Loss) Per Share
(1)
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders
|
|
$
|
15,012
|
|
$
|
(86,957)
|
Weighted average shares outstanding, basic
|
|
|
90,892
|
|
|
90,652
|
Earnings (loss) per common share, basic
|
|
$
|
0.17
|
|
$
|
(0.96)
|
|
|
|
|
|
|
|
Diluted Earnings (Loss) Per Share
(1)
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders
|
|
$
|
15,012
|
|
$
|
(86,957)
|
Weighted average shares outstanding, basic
|
|
|
90,892
|
|
|
90,652
|
Restricted stock awards, performance share awards and stock options
|
|
|
418
|
|
|
-
|
Weighted average shares outstanding, diluted
|
|
|
91,310
|
|
|
90,652
|
Earnings (loss) per common share, diluted
|
|
$
|
0.16
|
|
$
|
(0.96)
|
|
(1)
|
|
All share
and per share
amounts have been retroactively adjusted for the 2017 period to reflect the Company’s one-for-four reverse stock split in November 2017, as described in Not
e 8
to these
condensed
consolidated financial statements.
|
During the
three months ended March 31, 2018
, the
diluted earnings per share calculation excludes the
effect of
116
,
552
common shares for stock options that were out-of-the-money
and
246
,
613
performance
share
awards
that did not meet
the
market-based vesting criteria as of
March 31, 2018.
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
446,890
shares of service-based restricted stock awards
and
1,220
stock options. In addition, the diluted earnings per share calculation for the three months ended March 31, 2017 excludes the
effect of
127
,
020
common shares for stock options that were out-of-the-money
and
353
,
748
performance
sh
are awards that did not meet the market-based vesting criteria as of March 31, 2017.
Refer to the “Stock-Based Compensation” footnote for further information on the Company’s restricted stock awards, performance share awards 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, 2018
would be convertible into approximately
3.6
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, 2018 and 2017,
the conversion value did not exceed the principal amount of the notes
.
A
ccordingly, 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, 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
.
During 2017, we focused our drilling activity on projects that provide the highest rate of return, while closely aligning our capital spending with cash flows generated from operations. During 2018, we continue to focus on high-return projects in our asset portfolio that will add production and reserves while generating free cash flows from operations. 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 our plan to explore monetization of our Redtail field assets and the asset sales discussed 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, 2017
. 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
6
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2017
|
|
2018
|
|
|
Q1
|
|
Q2
|
|
Q3
|
|
Q4
|
|
Q1
|
|
Q2
|
|
Q3
|
|
Q4
|
|
Q1
|
Crude oil
|
|
$
|
33.51
|
|
$
|
45.60
|
|
$
|
44.94
|
|
$
|
49.33
|
|
$
|
51.86
|
|
$
|
48.29
|
|
$
|
48.19
|
|
$
|
55.39
|
|
$
|
62.89
|
Natural gas
|
|
$
|
2.06
|
|
$
|
1.98
|
|
$
|
2.93
|
|
$
|
2.98
|
|
$
|
3.07
|
|
$
|
3.09
|
|
$
|
2.89
|
|
$
|
2.87
|
|
$
|
3.13
|
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
have resulted, and
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
8
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 103.1 MBOE/d for the first quarter of 2018, representing a 3% decrease from 106.8 MBOE/d in the fourth quarter of 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.
As of March 31, 2018, we had four rigs active in the Williston Basin and added a fifth rig in April 2018. Under our current development plan, we expect to put 123 wells on production in this area during 2018.
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
23.3
MBOE/d
i
n the
first
quarter of 201
8
, representing a
13
%
in
crease
from
20.6
MBOE/d in the
fourth
quarter of 201
7
.
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. During 2017, we completed and brought on production a significant portion of our drilled uncompleted well inventory (“DUCs”) from yearend 2016.
During the fourth quarter of 2017, based on the recent and comparative well performance results of the DJ Basin to the Williston Basin, our management decided to concentrate development activities during 2018 in the Williston Basin. We plan to complete 22 DUCs in our Redtail field during the first half of 2018, and then cease additional development activity in this area until commodity prices further recover.
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, 2018, the plant was processing over 36 MMcf/d.
Financing
Highlights
On January 26, 2018, we paid $1.0 billion to redeem all of the then outstanding $961 million aggregate principal amount of our 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with proceeds from the issuance of our 2026 Senior Notes and 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.
Results of Operations
Three Months Ended March 31, 2018
Compared to
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Net production
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
|
7.7
|
|
|
7.3
|
NGLs (MMBbl)
|
|
|
1.8
|
|
|
1.6
|
Natural gas (Bcf)
|
|
|
11.3
|
|
|
9.9
|
Total production (MMBOE)
|
|
|
11.4
|
|
|
10.6
|
Net sales (in millions)
|
|
|
|
|
|
|
Oil
(1)
|
|
$
|
453.7
|
|
$
|
320.5
|
NGLs
|
|
|
42.8
|
|
|
28.6
|
Natural gas
|
|
|
18.6
|
|
|
22.2
|
Total oil, NGL and natural gas sales
|
|
$
|
515.1
|
|
$
|
371.3
|
Average sales prices
|
|
|
|
|
|
|
Oil (per Bbl)
(1)
|
|
$
|
58.61
|
|
$
|
43.92
|
Effect of oil hedges on average price (per Bbl)
|
|
|
(3.21)
|
|
|
0.20
|
Oil net of hedging (per Bbl)
|
|
$
|
55.40
|
|
$
|
44.12
|
Weighted average NYMEX price (per Bbl)
(2)
|
|
$
|
62.92
|
|
$
|
51.87
|
NGLs (per Bbl)
|
|
$
|
23.57
|
|
$
|
17.69
|
Natural gas (per Mcf)
|
|
$
|
1.65
|
|
$
|
2.25
|
Weighted average NYMEX price (per MMBtu)
(2)
|
|
$
|
3.13
|
|
$
|
3.06
|
Costs and expenses (per BOE)
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
8.10
|
|
$
|
8.56
|
Production taxes
|
|
$
|
3.31
|
|
$
|
3.03
|
Depreciation, depletion and amortization
|
|
$
|
16.43
|
|
$
|
22.76
|
General and administrative
|
|
$
|
2.75
|
|
$
|
2.90
|
|
(1)
|
|
Before consideration of hedging transactions.
|
|
(2)
|
|
Average NYMEX pricing weighted for monthly production volumes.
|
Oil, NGL and Natural Gas Sales
. O
ur oil, NGL and natural gas sales revenue
increased
$144
million to
$515
m
illion when comparing
the first quarter of 2018
to
the same period in
201
7
. 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
in
creased
6%, 12%
and
14%
respectively,
between period
s. The oil volume
in
crease between periods
was
primarily
attributable to
new wells drilled and completed in the Williston
B
asin
and DJ Basin
which added
2,060
MBbl
and 1,315 MBbl, respectively,
of oil production during the first
quarter
of 201
8 as compared to the first quarter of 2017
.
These
in
creases were partially offset by
n
ormal field production decline across several of our areas
, as well as 2017
property divestitures
which negatively impacted oil production in the first quarter of 2018 by 685 MBbl
.
The NGL volume increase between periods generally relates to new wells drilled and completed in the Williston Basin and DJ Basin over the last twelve months, as well as additional volumes processed as more wells were connected to gas processing plants in the Williston Basin in an effort to increase our overall gas capture rate in this area and reduce flared volumes. Many of the new Williston Basin wells are in areas with higher gas-to-oil production ratios than previously drilled areas. These NGL volume increases were partially offset by normal field production decline across
several of
our areas.
T
he gas volume
in
crease between periods
was
primarily
due to
new wells drilled and completed at our Williston Basin and DJ Basin properties which resulted in 2,795 MMcf and 1,245 MMcf, respectively, of additional gas volumes during the first quarter of 2018 as compared to the first quarter of 2017
.
Th
ese
in
crease
s
w
ere
partially
offset by
normal field production decline across several of our areas
, as well as 2017 property divestitures which negatively impacted gas production in the first quarter of 2018 by 115 MMcf.
In addition to the above
production-related
in
creases in net revenue
, there were also increases
in the average sales price realized
for oil and NGLs
in
the first quarter of
201
8
compared to 201
7.
Our average price for oil
(
before the effects of hedging
) and NGLs each
increased
33%
b
etween periods
, while our average price for natural gas decreased 27% between periods
.
Our average sales price realized for oil is impacted by deficiency payments we are making under two physical delivery contracts at our Redtail field due to our inability
to meet the minimum volume commitments under these contracts. During the three months ended March 31, 2018 and 2017, our total average sales price realized for oil was $1.09 per Bbl and $2.21 per Bbl lower, respectively, as a result of these deficiency payments.
On February 1, 2018, we paid $61 million to the counterparty to one of these Redtail delivery contracts to settle all future minimum volume commitments under the agreement.
The remaining agreement will continue to negatively impact the price we receive for oil from our Redtail field through April 2020, when the contract terminates.
Our average sales price for oil was further impacted by the adoption of FASB ASC Topic 606 –
Revenue from Contracts with Customers
(“ASC 606”), which resulted in an increase of $0.44 per Bbl for the three months ended March 31, 2018. In addition, the adoption of ASC 606 negatively impacted our average sales price for NGLs and natural gas by $3.67 per Bbl and $0.58 per Mcf, respectively, for the three months ended March 31, 2018. Refer to the “Revenue Recognition” footnote in the condensed consolidated financial statements for more information on the impact of this new standard.
Lease Operating Expenses
. Our lease operating expenses (“LOE”) during the first
quarter
of 201
8
were
$93
million, a
$2
million
in
crease over the same period in 201
7
. This
in
crease was primarily due to
new wells put on production in the Williston Basin and the DJ Basin during 2018, largely offset by the impact of adopting ASC 606 effective January 1, 2018, which reduced LOE by $10 million during the three months ended March 31, 2018, as well as the elimination of
$
9
million of LOE attributable to properties that we divested during 2017
. Refer to the “Revenue Recognition” footnote in the condensed consolidated financial statements for more information on the impact of ASC 606
.
Our lease operating expenses on a BOE basis
, however,
de
creased when comparing the first
quarter
of 201
8
to the same 201
7
period. LOE per BOE amounted to
$8.10
during the first
quarter
of 201
8
, which represents a
de
crease of
$0.46
per BOE (or
5%
) from the first
quarter
of
201
7
. This
de
crease was mainly due to
high
er overall production volumes between periods, partially offset by the overall
in
crease in LOE expense discussed above.
Production Taxes
. O
ur production taxes during the first
quarter
of 201
8
were
$38
million, a
$6
million
in
crease over the same period in 201
7
, 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
7.3%
and
8.6%
for the first
quarter
of 201
8
and 201
7
, respectively.
Our production tax rate of 7.3% for the first quarter of 2018 was less than the rate for the same period in 2017 due to successful wells completed during the past twelve months in Colorado, which has a 5% tax rate, as well as severance tax refunds received during the first quarter of 2018.
Depreciation, Depletion and Amortization
. Our depreciation, depletion and amortization (“DD&A”) expense
decreased
$52
million in 201
8
as compared to the first
quarter
of 201
7
. The components of our DD&A expense were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Depletion
|
|
$
|
183,645
|
|
$
|
235,032
|
Depreciation
|
|
|
1,566
|
|
|
1,870
|
Accretion of asset retirement obligations
|
|
|
2,708
|
|
|
3,505
|
Total
|
|
$
|
187,919
|
|
$
|
240,407
|
DD&A
decreased between periods
due to $
51
million in
lower
depletion expense
, consisting of a
$
65 million decrease
related to
a lower depletion rate between periods, partially offset by a $14 million
in
crease
due to higher
overall production volumes during the first
quarter
of 201
8
. On a BOE basis, our overall DD&A r
ate of
$16.43
for the first
quarter
of 201
8
was
28%
lower
than the rate of
$22.76
for the same period in 201
7
. The primary factor
s
contributing to
this
lower
DD&A rate
were (i) impairment write-downs on proved oil and gas properties recognized in the fourth quarter of 2017, (ii) an increase to proved developed reserves over the last twelve months (excluding the effect of divestitures) and (iii) the impact of property divestitures over the past twelve months.
Exploration and Impairmen
t Cos
t
s
. Our exploration and impairment costs
de
creased
$6
m
illion for the first
quarter
of 201
8
as compared to the same period in 201
7
. The components of our exploration and impairment
expense
w
ere as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Exploration
|
|
$
|
4,697
|
|
$
|
6,138
|
Impairment
|
|
|
10,050
|
|
|
14,703
|
Total
|
|
$
|
14,747
|
|
$
|
20,841
|
Impairment expense for the first quarter of 2018 and 2017 primarily 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,
|
|
|
2018
|
|
2017
|
General and administrative expenses
|
|
$
|
56,470
|
|
$
|
56,990
|
Reimbursements and allocations
|
|
|
(24,990)
|
|
|
(26,373)
|
General and administrative expenses, net
|
|
$
|
31,480
|
|
$
|
30,617
|
G&A
expense
, net
increased slightly when comparing the first quarter of 2018 to the same 2017 period, however, our general and administrative expenses on a BOE basis decreased between periods. G&A expense per BOE amounted to
$2.75
during the first quarter of 2018, which represents a decrease of
$0.15
per BOE (or
5%
) from the first quarter of 2017. This decrease was mainly due to higher 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
$53
million for the
three
months ended
March 31
, 201
8, which consisted of
a $55 million loss on our costless collar and swap commodity derivative contracts resulting from
the
upward
shift in the futures curve of forecasted commodity prices (“forward price curve”) for crude oil from January 1, 201
8
(or the 2018 date on which new contracts were entered into)
to
March 31
, 201
8, partially offset by a
$2 million fair value gain on our
long-term crude oil sales
and delivery contract. 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
sh
ift in the same forward price curve from January 1, 201
7
(or the 201
7
date on which prior year contracts
were entered into) to
March 31
, 201
7
.
Refer to
Item 3, “Quantitative and Qualitativ
e Disclosures about Market Risk
”
,
for a list of our outstanding
commodity
derivative
contracts
as
of April
24
, 2018.
Interest Expense
. The components of our interest expense were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
March 31,
|
|
|
2018
|
|
2017
|
Notes
|
|
$
|
40,595
|
|
$
|
34,252
|
Amortization of debt issue costs, discounts and premiums
|
|
|
7,805
|
|
|
7,605
|
Credit agreement
|
|
|
4,089
|
|
|
5,813
|
Other
|
|
|
410
|
|
|
341
|
Total
|
|
$
|
52,899
|
|
$
|
48,011
|
The
in
crease in interest expen
se of
$5
million between periods was mainly attributable to
higher
interest costs incurred on our notes
during the first
quarter
of 201
8
as compared to the first
quarter
of 201
7
. The
$6 million in
crease in note interest
was
primarily
due to
$17 million of interest incurred on the 2026 Senior Notes issued in December 2017, partially offset by a $9 million reduction in interest related to the redemption of the 2019 Notes in January 2018. Refer to the “Long-Term Debt” footnote in the notes to condensed consolidated financial statements for more information on these debt transactions.
Our weighted average debt outstanding during the first
quarter
of 201
8
was $
3.2
billion versus $
3.3
billion for the first
quarter
of 201
7
. Our weighted average effective cash interest rate was
5.5
% during the first
quarter
of 201
8
compared to 4.
9
% for the first
quarter
of 201
7
.
Loss on Extinguishment of Debt.
During the first quarter of 2018, we redeemed all of the remaining $961 million aggregate principal amount of 2019 Senior Notes and recognized a $31 million 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. 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
.
As of December 31, 2017, we recorded a full valuation allowance on our deferred tax assets. Accordingly, we did not recognize any income tax expense or benefit during the first quarter of 2018, as compared to an income tax benefit of
$39
million for the first quarter of 2017.
Our overall effective tax rate
of
31.2% for the first quarter of 2017
was lower than the U.S. statutory income tax rate in effect during 2017 primarily due to the impact of performance share awards that were canceled during the period after not meeting their market-based vesting criteria.
Liquidity and Capital Resources
Overvie
w
. At
March 31, 2018
, we had $
31
million of cash on hand and $
3.9
billion of equity, while at
December 31, 2017
, we had $
879
million of cash on hand and $
3.9
billion of equity.
Cash on hand at December 31, 2017 consisted of the remaining proceeds from the issuance of our 2026 Senior Notes in December 2017.
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
68% and 69
% of our total production in the first
quarter
of 201
8
and 201
7, 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
April 24
, 201
8
, we had derivative contracts covering the sale of approximately
73%
of our forecasted oil production volumes for the remainder of 201
8
.
For a list of all of our outstanding derivatives as of April 24
, 201
8, refer to Item 3, “Quantitative and Qualitative Disclosures about Market Risk”.
During the first quarter of 2018, we generated $233 million of cash provided by operating activities, an increase of $153 million from the same period in 2017. Cash provided by operating activities increased primarily due to higher crude oil, NGL and natural gas production
volumes
and
higher realized sales prices for oil
and
NGLs. These
posi
tive factors were partially offset by
a decrease in cash settlements received on our derivative contracts, as well as
higher production taxes
,
cash interest expense
and
lease operating expenses during the first
quarter
of 201
8
as compared to the same period in 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 2018, cash flows from operating activities and cash on hand
plus $90 million in net borrowings under our credit agreement
were used to finance the redemption of the remaining $961 million of 2019 Senior Notes
and
$
173
million of drilling and development expenditures.
Exploration and Development Expenditures
. The
following
table
details our exploration
and
development expenditures incurred by
core area
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2018
|
|
2017
|
Northern Rocky Mountains
|
|
$
|
136,871
|
|
$
|
132,536
|
Central Rocky Mountains
|
|
|
46,181
|
|
|
53,045
|
Other
(1)
|
|
|
4,092
|
|
|
210
|
Total incurred
|
|
$
|
187,144
|
|
$
|
185,791
|
|
(1)
|
|
Other primarily includes non-core oil and gas properties located in Colorado, Texas, Utah and Wyoming.
|
We continually evaluate our capital needs and compare them to our capital resources.
Our 201
8 exploration and development
(“E&D”)
budget
is $750 million
, which we expect to fund substantially with net cash provided by operating activities
and cash on hand
.
The 2018 E&D budget
represents a
de
crease
from
the $
912
m
illion
i
ncurred on
E&D
expenditures during 201
7
. We believe that should additional attractive acquisition opportunities arise or
E&D
expenditures exceed $
750 m
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, 2018
had a borrowing base
and
aggregate commitments of
$2.3
billion.
As of
March 31, 2018
, we had
$2.2
billion of available borrowing capacity, which was net of
$90 million in borrowings and $2
million in letters of credit outstanding.
On April
12
, 2018,
we
entered into a Seventh Amended and Restated Credit Agreement, which replace
d
our
existing credit agreement
on that date
. This amended credit agreement, among other things, (i) increased the borrowing base under the facility from $2.3 billion to $2.4 billion, (ii) reduced the aggregate commitments from $2.3 billion to $
1.75
billion,
(iii)
extended the principal repayment date from December 2019 to April 2023, (iv)
decreased the applicable margin based on the borrowing base utilization percentage by 50 basis points per annum, (v) decreased the commitment fee to 37.5 basis points per annum for certain ratios of outstanding borrowings to the borrowing base
as shown in the table below
, (v
i
)
modified certain financial covenants as discussed below, and (vii) removed our ability to issue second lien indebtedness of up to $1.0 billion.
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.
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.
A portion of the revolving credit facility
in an aggregate 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, 2018
,
$48
million was available for additional letters of credit under the agreement.
The credit agreement provides for interest only payments until
maturity, when the credit agreement expires and
all outstanding borrowings are due.
Interest under the
amended credit agreement
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
amended credit agreement
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Applicable
|
|
Applicable
|
|
|
|
|
Margin for Base
|
|
Margin for
|
|
Commitment
|
Ratio of Outstanding Borrowings to Borrowing Base
|
|
Rate Loans
|
|
Eurodollar Loans
|
|
Fee
|
Less than 0.25 to 1.0
|
|
0.50
%
|
|
1.5
0%
|
|
0.
37
5%
|
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0
|
|
0.75
%
|
|
1.7
5%
|
|
0.
37
5%
|
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0
|
|
1.00
%
|
|
2.
0
0%
|
|
0.50%
|
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0
|
|
1.
2
5%
|
|
2.
2
5%
|
|
0.50%
|
Greater than or equal to 0.90 to 1.0
|
|
1.50
%
|
|
2
.
5
0%
|
|
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. 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)
.
As of March 31, 2018, the existing credit agreement required 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 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 and (iii) a ratio of the last four quarters’ EBITDAX to consolidated
cash
interest charges of not less than
2.25
to 1.0.
The
amended
credit agreement requires us, as of the last day of any quarter,
to maintain the following ratios (as defined in the amended credit agreement):
(i) a consolidated current assets to consolidated current liabilities ratio
(which includes an add back of the available borrowing capacity under the amended credit agreement)
of not less th
an 1.0 to 1.0
and
(ii)
a total debt to
the last four quarters’
EBITDAX ratio of not greater than 4.0 to 1.0.
We were in compliance with our covenants under the credit agreement as of
March 31, 2018
.
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 December 2017, we issued at par $1.0 billion of 6.625% Senior Notes due January 2026 (the “2026 Senior 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 2026 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 exchanged (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 during 2016, all $882 million aggregate principal amount of these convertible notes was converted into approximately 21.6 million shares of our common stock
pursuant to the terms of the
notes
.
Redemption of 2018 Senior Subordinated Notes.
O
n February 2, 2017,
we paid $281 million
to redeem all of the
then outstanding
$275 million aggregate principal amount of our 2018 Senior Subordinated Notes
, which payment consisted
of the 100% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with borrowings under our credit agreement.
As of March 31, 2017, no 2018 Senior Subordinated Notes remained outstanding.
Redemption of 201
9
Senior Notes.
On January 26, 2018, we paid $1.0 billion to redeem all of the then outstanding $961 million aggregate principal amount of our 2019 Senior Notes, which payment consisted of the 102.976% redemption price plus all accrued and unpaid interest on the notes. We financed the redemption with proceeds from the issuance of our 2026 Senior Notes and borrowings under our credit agreement.
As of March 31, 2018, no 2019 Senior Notes remained outstanding.
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 exchanged $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 17.8 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 outstanding as of March 31, 2018, we have the option to settle conversions of 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 6.4102 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $156.00. The conversion rate will be subject to adjustment in some events. In addition, following certain corporate events that occur prior to the maturity date, 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, 2018, 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, 2018
. 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, 2018
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, 2017
.
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Payments due by period
|
|
|
|
(in thousands)
|
|
|
|
|
|
Less than 1
|
|
|
|
|
|
|
|
More than 5
|
Contractual Obligations
|
|
Total
|
|
year
|
|
1-3 years
|
|
3-5 years
|
|
years
|
Long-term debt
(1)
|
|
$
|
2,933,980
|
|
$
|
-
|
|
$
|
1,435,684
|
|
$
|
-
|
|
$
|
1,498,296
|
Cash interest expense on debt
(2)
|
|
|
856,299
|
|
|
159,120
|
|
|
308,687
|
|
|
203,402
|
|
|
185,090
|
Asset retirement obligations
(3)
|
|
|
137,320
|
|
|
5,642
|
|
|
16,758
|
|
|
11,815
|
|
|
103,105
|
Water disposal agreement
(4)
|
|
|
117,015
|
|
|
19,013
|
|
|
40,635
|
|
|
35,820
|
|
|
21,547
|
Purchase obligations
(5)
|
|
|
21,054
|
|
|
7,656
|
|
|
13,398
|
|
|
-
|
|
|
-
|
Pipeline transportation agreements
(6)
|
|
|
52,736
|
|
|
9,332
|
|
|
18,964
|
|
|
14,301
|
|
|
10,139
|
Drilling rig contracts
(7)
|
|
|
14,567
|
|
|
14,567
|
|
|
-
|
|
|
-
|
|
|
-
|
Leases
(8)
|
|
|
12,836
|
|
|
7,467
|
|
|
5,369
|
|
|
-
|
|
|
-
|
Total
|
|
$
|
4,145,807
|
|
$
|
222,797
|
|
$
|
1,839,495
|
|
$
|
265,338
|
|
$
|
1,818,177
|
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(1)
|
|
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 amended 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 amended credit agreement is estimated assuming no principal borrowings or repayments through the April
20
23
instrument due date and a fixed interest rate of
4.0
%.
Commitment fees on the
amended
credit agreement are estimated assuming
a reduction in commitments pursuant to the terms of the amended credit facility with
no principal borrowings or repayments through the
April 2023
instrument due date.
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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.
As a result of our reduced development operations at our Redtail field, we have made and expect to continue to make periodic deficiency payments under this contract.
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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.
As a result of our reduced development operations at our Redtail field, we have made and expect to continue to make periodic deficiency payments under this contract.
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(6)
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W
e have
three
pipeline transportation agreements with
two
different
sup
pliers, 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
these
contract
s,
however, our actual expenditures under
these
contract
s
may exceed the minimum commitments presented above.
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(7)
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As of
March 31, 2018
, we had
three
drilling rigs under long-term contract
s, of which two drilling rigs
expir
e
in 201
8 and one expires in 2019
.
As of March 31, 2018, e
arly termination of
these
contracts would require
termination
penalties of $
8
million, which would be in lieu of paying the remaining drilling commitments under these contracts.
The obligations reported above represent our minimum financial commitments pursuant to the terms of
these
contract
s,
however, our actual expenditures under
these
contract
s
may exceed the minimum commitments presented above.
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(8)
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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. We have sublet the majority of our office space in Midland, Texas to a third party for the remaining lease term. The offsetting rental income has not been included in the table above.
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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
and the “Revenue Recognition” 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, 2017. The following is a material update to such critical accounting policies and estimates:
Revenue Recognition
. We predominantly derive our revenue from the sale of produced oil, NGLs and natural gas. Revenue is reco
gnized
when we meet our performance obligation to deliver the product and control is transferred to the customer
. We receive payment
for product sales
from one to three months after delivery. At the end of each month
when the performance obligation is satisfied
, the
amount of production delivered and the
price we will receive
can be reasonably estimated and amounts due from customers are accrued in accounts receivable trade, net in the consolidated balance sheets
. Variances between our estimated revenue and actual payment
s
are recorded in the month the payment is received. However, differences have been and are insignificant.
We adopted FASB ASC Topic
60
6 –
Revenue from Contracts with Customers
effective January 1, 2018 using the modified retrospective approach. Refer to the “
Basis of Presentation
”
and “Revenue Recognition”
footnote
s
in the notes to
condensed
consolidated financial statements for more information on this new accounting standard.
Effects of Inflation and Pricing
As a result of the sustained depressed commodity price environment from 2015 through 2017, w
e
have
experienced
lower
costs due to
a decrease
in
demand for oil field products and services.
Although prices have begun to recover during the first quarter of 2018, the cost of oil field goods and services has remained relatively consistent with 2017 levels.
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
, including the
potential disposition of our Redtail field assets
; 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, 2017
. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this Quarterly Report on Form 10-Q.