Note 1.
Organization and nature of operations
Concho Resources Inc. (the “Company”) is a Delaware
corporation formed on February 22, 2006. The Company’s principal business
is the acquisition, development, exploration and production of oil and natural
gas properties primarily located in the Permian Basin of southeast New Mexico
and west Texas.
Note 2.
Summary
of significant accounting policies
Principles
of consolidation.
The consolidated
financial statements of the Company include the accounts of the Company and its
100 percent owned subsidiaries. The Company consolidates the financial
statements of these entities. All material intercompany balances and
transactions have been eliminated.
Reclassifications.
Certain prior period amounts have been reclassified
to conform to the 2017 presentation. These reclassifications had no impact on
net income (loss), total stockholders’ equity or total cash flows.
Use of
estimates in the preparation of financial statements.
Preparation of financial statements in conformity with
generally accepted accounting principles in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting periods. Actual results could differ
from these estimates. Depletion of oil and natural gas properties is determined
using estimates of proved oil and natural gas reserves. There are numerous
uncertainties inherent in the estimation of quantities of proved reserves and
in the projection of future rates of production and the timing of development
expenditures. Similarly, evaluations for impairment of proved and unproved oil
and natural gas properties are subject to numerous uncertainties including,
among others, estimates of future recoverable reserves, commodity price
outlooks and prevailing market rates of other sources of income and costs.
Other significant estimates include, but are not limited to, asset retirement
obligations, fair value of stock-based compensation, fair value of business
combinations, fair value of nonmonetary exchanges, fair value of derivative
financial instruments and income taxes.
Interim
financial statements.
The
accompanying consolidated financial statements of the Company have not been
audited by the Company’s independent registered public accounting firm, except
that the consolidated balance sheet at December 31, 2016 is derived from
audited consolidated financial statements. In the opinion of management, the
accompanying consolidated financial statements reflect all adjustments
necessary to present fairly the Company’s consolidated financial statements.
All such adjustments are of a normal, recurring nature. In preparing the
accompanying consolidated financial statements, management has made certain
estimates and assumptions that affect reported amounts in the consolidated
financial statements and disclosures of contingencies. Actual results may
differ from those estimates. The results for interim periods are not
necessarily indicative of annual results.
Certain disclosures have been condensed in or omitted from
these consolidated financial statements. Accordingly, these condensed notes to
the consolidated financial statements should be read in conjunction with the
audited consolidated financial statements and notes included in the Company’s
Annual Report on Form 10-K for the year ended December 31, 2016.
Cash
equivalents.
The Company considers
all cash on hand, depository accounts held by banks, money market accounts and
investments with an original maturity of three months or less to be cash
equivalents. The Company’s cash and cash equivalents are held in financial
institutions in amounts that exceed the insurance limits of the Federal Deposit
Insurance Corporation. However, management believes that the Company’s
counterparty risks are minimal based on the reputation and history of the
institutions selected. The majority of the Company’s cash is invested in stable
value government money market funds.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Equity method investments.
At December 31, 2016, the Company owned a 50 percent membership
interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that
operated a crude oil gathering and transportation system in the northern
Delaware Basin. During February 2017, the Company closed on its previously
announced divestiture of its ownership interest in ACC. See Note 4 for
additional information regarding the disposition of ACC.
The Company accounted for its investment in ACC under the
equity method of accounting for investments in unconsolidated affiliates. The
Company’s net investment in ACC was approximately $129 million at December 31,
2016, and was included in other assets in the Company’s consolidated balance
sheet. Gains and losses incurred from the Company’s equity investment in ACC were
recorded in other income (expense) in its consolidated statements of
operations.
The Company owns a 23.75 percent membership interest in an
entity that operates a crude oil gathering and transportation system in the
southern Delaware Basin. The Company accounts for its investment under the
equity method of accounting for investments in unconsolidated affiliates. The
Company’s net investment was approximately $43 million and $42 million at March
31, 2017 and December 31, 2016, respectively, and is included in other assets
in the Company’s consolidated balance sheets. Gains and losses incurred from the
Company’s equity investment are recorded in other income (expense) in its
consolidated statements of operations.
Revenue
recognition.
Oil and natural gas
revenues are recorded at the time of physical transfer of such products to the
purchaser, which for the Company is primarily at the wellhead. The Company
follows the sales method of accounting for oil and natural gas sales,
recognizing revenues based on the Company’s actual proceeds from the oil and
natural gas sold to purchasers.
General
and administrative expense.
The
Company receives fees for the operation of jointly-owned oil and natural gas
properties during the drilling and production phases and records such
reimbursements as reductions of general and administrative expense. The Company
earned reimbursements of approximately $4 million for each of the three months
ended March 31, 2017 and 2016.
Adoption
of new accounting standard
s.
The Company
adopted Accounting Standards Update (“ASU”) No. 2016-09, “Compensation–Stock
Compensations (Topic 718): Improvements to Employee Share-based Payment
Accounting,” on January 1, 2017. The adoption did not have an impact on prior
period consolidated financial statements. The Company elected to account for
forfeitures of share-based payments as they occur. At December 31, 2016, the
Company had not recorded compensation expense of approximately $8 million based
on forecasted forfeitures nor the associated deferred tax benefit of
approximately $3 million. The Company recognized all excess tax benefits not
previously recorded, which totaled approximately $5 million at December 31, 2016.
Upon adoption, the Company recorded a cumulative-effect adjustment, which
decreased retained earnings by less than $1 million, increased additional
paid-in capital by approximately $8 million, and decreased net deferred income
taxes by approximately $8 million. The Company elected to prospectively
classify excess tax benefits and deficiencies as operating activities on the
consolidated statements of cash flows and will prospectively record those
excess tax benefits and deficiencies as discrete items in the income tax
provision in the consolidated statements of operations. Under the new standard,
for the three months ended March 31, 2017, the Company recorded excess tax
benefits of approximately $7 million as an offset to the Company’s income tax
provision and approximately $5 million in forfeitures.
Recent
accounting pronouncements.
In May
2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No.
2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a
new, single comprehensive model for entities to use in accounting for revenue
arising from contracts with customers and supersedes most current revenue
recognition guidance, including industry-specific guidance. This new revenue
recognition model provides a five-step analysis in determining when and how
revenue is recognized. The new model will require revenue recognition to depict
the transfer of promised goods or services to customers in an amount that
reflects the consideration a company expects to receive in exchange for those
goods or services.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
In August
2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers
(Topic 606): Deferral of the Effective Date,” which deferred the effective date
of ASU No. 2014-09 by one year. That new standard is now effective for annual
reporting periods beginning after December 15, 2017. The Company expects to use
the modified retrospective method to adopt the standard, meaning the cumulative
effect of initially applying the standard will be recognized in the most
current period presented in the financial statements. The Company has
substantially completed its internal evaluation of the adoption of this
standard and does not expect this new guidance will have a material impact on
its consolidated financial statements.
In February 2016, the FASB issued
ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance.
The new lease standard requires all leases with a term greater than one year to
be recognized on the balance sheet while maintaining substantially similar
classifications for financing and operating leases. Lease expense recognition
on the consolidated statements of operations will be effectively unchanged.
This guidance is effective for reporting periods beginning after December 15,
2018, and early adoption is permitted. The Company does not plan to early adopt
the standard. The Company enters into lease agreements to support its
operations. These agreements are for leases on assets such as office space,
vehicles, field services, well equipment and drilling rigs. The Company is
currently in the process of reviewing all contracts that could be applicable to
this new guidance. The Company believes this new guidance will have a moderate
impact to its consolidated balance sheets due to the recognition of right-of-use
assets and lease liabilities that are not currently recognized under currently
applicable guidance.
In June 2016, the FASB issued ASU
No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of
Credit Losses on Financial Instruments,” which replaces the current “incurred
loss” methodology for recognizing credit losses with an “expected loss”
methodology. This new methodology requires that a financial asset measured at
amortized cost be presented at the net amount expected to be collected. This
standard is intended to provide more timely decision-useful information about
the expected credit losses on financial instruments. This guidance is effective
for fiscal years beginning after December 15, 2019, and early adoption is
allowed as early as fiscal years beginning after December 15, 2018. The Company
does not believe this new guidance will have a material impact on its
consolidated financial statements.
In January 2017, the FASB issued
ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition
of a Business,” with the objective of adding guidance to assist in evaluating
whether transactions should be accounted for as asset acquisitions or as
business combinations. The guidance provides a screen to determine when an
integrated set of assets and activities is not a business. The screen requires
that when substantially all of the fair value of the acquired assets is
concentrated in a single asset or a group of similar assets, the set is not a
business. If the screen is not met, to be considered a business, the set must
include an input and a substantive process that together significantly
contribute to the ability to create output. This new guidance is effective for
annual periods beginning after December 15, 2017, and early adoption is
allowed. The Company is evaluating the impact this new guidance will have on
its consolidated financial statements. The new guidance could result in more
acquisitions of oil and natural gas properties being accounted for as asset
acquisitions instead of business combinations.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 3.
Exploratory
well costs
The Company capitalizes exploratory well costs until a
determination is made that the well has either found proved reserves or that it
is impaired. After an exploratory well has been completed and found oil and
natural gas reserves, a determination may be pending as to whether the oil and
natural gas reserves can be classified as proved. In those circumstances, the
Company continues to capitalize the well or project costs pending the
determination of proved status if (i) the well has found a sufficient quantity
of reserves to justify its completion as a producing well and (ii) the Company
is making sufficient progress assessing the reserves and the economic and
operating viability of the project.
The capitalized exploratory
well costs are carried in unproved oil and natural gas properties. See Note 15
for the proved and unproved components of oil and natural gas properties. If
the exploratory well is determined to be impaired, the well costs are charged
to exploration and abandonments expense in the consolidated statements of
operations.
The
following table reflects the Company’s net capitalized exploratory well
activity during the three months ended March 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
(in millions)
|
|
|
March 31, 2017
|
|
|
|
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
|
|
|
$
|
151
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
|
|
|
145
|
|
Reclassifications due to determination of proved reserves
|
|
|
|
|
|
(99)
|
Ending capitalized exploratory well costs
|
|
|
|
|
$
|
197
|
|
|
|
|
|
|
|
|
The
following table provides an aging at March 31, 2017 and December 31, 2016 of
capitalized exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(dollars in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Capitalized exploratory well costs that have been
capitalized for a period of one year or less
|
|
$
|
185
|
|
$
|
141
|
Capitalized exploratory well costs that have been
capitalized for a period greater than one year
|
|
|
12
|
|
|
10
|
|
Total capitalized exploratory well costs
|
|
$
|
197
|
|
$
|
151
|
Number of projects with exploratory well costs that have
been capitalized for a period greater
|
|
|
|
|
|
|
|
than one year
|
|
|
7
|
|
|
8
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 4.
Acquisitions and divestitures
ACC divestiture.
In February 2017, the Company closed on
its previously announced divestiture of its ownership interest in ACC in which
the Company and its joint venture partner entered into separate agreements to
sell 100 percent of their respective ownership interests in ACC. After
adjustments for debt and working capital, the Company received cash proceeds
from the sale of approximately $803 million. After direct transaction costs,
the Company recorded a pre-tax gain on disposition of assets of approximately
$656 million.
The Company’s net investment in ACC at the time of closing
was approximately $129 million.
Northern Delaware Basin acquisition.
In January 2017, the Company completed a
portion of the previously announced acquisition of approximately 16,400 net
acres in the Northern Delaware Basin. As consideration for this portion of the
acquisition, the Company paid approximately $132 million in cash, of which $43
million was held in escrow at December 31, 2016, and issued to the
seller approximately 1.9 million shares of its common stock with an approximate
value of $258 million. In April 2017, the Company closed on the remainder of
the acquisition. The acquisition, in its entirety, is subject to customary
closing and post-closing adjustments. The purchase price allocation of this
acquisition is preliminary and subject to change as the Company takes over
operatorship of the acquired properties and subsequent due diligence is
performed.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 5.
Stock incentive plan
The Company’s 2015 Stock Incentive Plan provides for
granting stock options, restricted stock awards and performance awards to
directors, officers and employees of the Company.
The
restricted stock-based compensation awards generally vest over a period ranging
from one to eight years.
A summary of
the Company’s activity for the three months ended March 31, 2017 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
Stock
|
|
Performance
|
|
|
|
|
Stock Shares
|
|
Options
|
|
Units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
1,157,270
|
|
|
20,000
|
|
|
331,526
|
|
|
Awards granted (a)
|
|
|
113,460
|
|
|
-
|
|
|
108,398
|
|
|
Options exercised
|
|
|
-
|
|
|
(20,000)
|
|
|
-
|
|
|
Awards cancelled / forfeited
|
|
|
(44,232)
|
|
|
-
|
|
|
(37,542)
|
|
|
Lapse of restrictions
|
|
|
(160,353)
|
|
|
-
|
|
|
-
|
|
Outstanding at March 31, 2017
|
|
1,066,145
|
|
-
|
|
402,382
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Weighted average grant date fair value per share/unit
|
|
$
|
119.99
|
|
$
|
-
|
|
$
|
149.10
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Company used the following assumptions to estimate the fair value of
performance unit awards granted during the three months ended March 31, 2017:
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31, 2017
|
|
|
|
|
|
|
Risk-free interest rate
|
|
1.47%
|
Range of volatilities
|
|
24.8% - 60.2%
|
|
|
|
|
|
|
The
following table reflects the future stock-based compensation expense to be
recorded for all the stock-based compensation awards that were outstanding at March
31, 2017:
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Remaining 2017
|
|
$
|
44
|
2018
|
|
|
34
|
2019
|
|
|
15
|
Thereafter
|
|
|
2
|
|
Total
|
|
$
|
95
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 6.
Disclosures about fair value measurements
The Company uses a valuation framework based upon inputs
that market participants use in pricing an asset or liability, which are
classified into two categories: observable inputs and unobservable inputs. Observable
inputs represent market data obtained from independent sources, whereas
unobservable inputs reflect a company’s own market assumptions, which are used
if observable inputs are not reasonably available without undue cost and
effort. These two types of inputs are further prioritized into the following
fair value input hierarchy:
Level 1
:
Unadjusted quoted prices in active markets that are
accessible at the measurement date for identical, unrestricted assets or
liabilities. The Company considers active markets to be those in which
transactions for the assets or liabilities occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 2
:
Quoted prices in markets that are not active, or
inputs which are observable, either directly or indirectly, for substantially
the full term of the asset or liability. This category includes those
derivative instruments that the Company values using observable market data.
Substantially all of these inputs are observable in the marketplace throughout
the full term of the derivative instrument, can be derived from observable data,
or supported by observable levels at which transactions are executed in the
marketplace. Level 2 instruments primarily include non-exchange traded
derivatives such as over-the-counter commodity price swaps, basis swaps,
collars and floors, investments and interest rate swaps. The Company’s
valuation models are primarily industry-standard models that consider various
inputs including: (i) quoted forward prices for commodities,
(ii) time value, (iii) current market and contractual prices for the
underlying instruments and (iv) volatility factors, as well as other relevant
economic measures.
Level 3
:
Prices or valuation models that require inputs that
are both significant to the fair value measurement and less observable from
objective sources (
i.e.
, supported by little or no market activity). The
Company’s valuation models are primarily industry-standard models that consider
various inputs including: (i) quoted forward prices for commodities,
(ii) time value, (iii) volatility factors and (iv) current market
and contractual prices for the underlying instruments, as well as other
relevant economic measures.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Financial Assets and Liabilities Measured at Fair Value
The
following table presents the carrying amounts and fair values of the Company’s
financial instruments at
March 31, 2017
and December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
December 31, 2016
|
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
(in millions)
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
97
|
|
$
|
97
|
|
$
|
4
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
13
|
|
$
|
13
|
|
$
|
178
|
|
$
|
178
|
|
|
$600 million 5.5% senior notes due 2022 (a)
|
|
$
|
594
|
|
$
|
621
|
|
$
|
594
|
|
$
|
620
|
|
|
$1,550 million 5.5% senior notes due 2023 (a)
|
|
$
|
1,554
|
|
$
|
1,604
|
|
$
|
1,555
|
|
$
|
1,621
|
|
|
$600 million 4.375% senior notes due 2025 (a)
|
|
$
|
593
|
|
$
|
604
|
|
$
|
592
|
|
$
|
599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The carrying value includes associated deferred loan costs and any
premium.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents, accounts receivable, other current assets, accounts
payable, interest payable and other current
liabilities.
The carrying amounts approximate fair value due to
the short maturity of these instruments.
Senior notes.
The
fair values of the Company’s senior notes are based on quoted market prices. The
debt securities are not actively traded and, therefore, are classified as
Level 2 in the fair value hierarchy.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Derivative instruments.
The fair value of the Company’s derivative
instruments is estimated by management considering various factors, including
closing exchange and over-the-counter quotations and the time value of the
underlying commitments. Financial assets and liabilities are classified based
on 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 requires judgment and may affect the valuation of the fair
value of assets and liabilities and their placement within the fair value hierarchy
levels.
The following tables
summarize (i) the valuation of each of the Company’s financial instruments by
required fair value hierarchy levels and (ii) the gross fair value by the
appropriate balance sheet classification,
even when the derivative
instruments are subject to netting arrangements and qualify for net
presentation in the Company’s consolidated balance sheets at
March 31, 2017
and
December 31, 2016. The Company nets the fair value of derivative instruments by
counterparty in the Company’s consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2017
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Net
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Amounts
|
|
|
Presented
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
Offset in the
|
|
|
in the
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Total
|
|
|
Balance
|
|
|
Balance
|
(in millions)
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Sheet
|
|
|
Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
$
|
98
|
|
$
|
-
|
|
$
|
98
|
|
$
|
(43)
|
|
$
|
55
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
60
|
|
|
-
|
|
|
60
|
|
|
(18)
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(53)
|
|
|
-
|
|
|
(53)
|
|
|
43
|
|
|
(10)
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(21)
|
|
|
-
|
|
|
(21)
|
|
|
18
|
|
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative instruments
|
|
$
|
-
|
|
$
|
84
|
|
$
|
-
|
|
$
|
84
|
|
$
|
-
|
|
$
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Net
|
|
|
|
|
|
Quoted Prices
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Fair Value
|
|
|
|
|
|
in Active
|
|
|
Significant
|
|
|
|
|
|
|
|
|
Amounts
|
|
|
Presented
|
|
|
|
|
|
Markets for
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
Offset in the
|
|
|
in the
|
|
|
|
|
|
Identical
|
|
|
Observable
|
|
|
Unobservable
|
|
|
|
|
|
Consolidated
|
|
|
Consolidated
|
|
|
|
|
|
Assets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Total
|
|
|
Balance
|
|
|
Balance
|
(in millions)
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Sheet
|
|
|
Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
$
|
59
|
|
$
|
-
|
|
$
|
59
|
|
$
|
(55)
|
|
$
|
4
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(137)
|
|
|
-
|
|
|
(137)
|
|
|
55
|
|
|
(82)
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(96)
|
|
|
-
|
|
|
(96)
|
|
|
-
|
|
|
(96)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative instruments
|
|
$
|
-
|
|
$
|
(174)
|
|
$
|
-
|
|
$
|
(174)
|
|
$
|
-
|
|
$
|
(174)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concentrations
of credit risk.
At
March 31, 2017
,
the Company’s primary concentrations of credit risk are the risk of collecting
accounts receivable and the risk of counterparties’ failure to perform under
derivative obligations.
The Company has entered into International Swap Dealers
Association Master Agreements (“ISDA Agreements”) with each of its derivative
counterparties. The terms of the ISDA Agreements provide the Company and the counterparties
with rights of set-off upon the occurrence of defined acts of default by either
the Company or a counterparty to a derivative, whereby the party not in default
may set off all derivative liabilities owed to the defaulting party against all
derivative asset receivables from the defaulting party. See Note 7 for
additional information regarding the Company’s derivative activities and
counterparties.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Assets and Liabilities Measured at Fair Value on a
Nonrecurring Basis
Certain assets and liabilities are reported at fair value
on a nonrecurring basis in the Company’s consolidated balance sheets. The
following methods and assumptions were used to estimate the fair values:
Impairments of long-lived assets
– The Company periodically reviews its long-lived assets
to be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. The Company reviews its oil and
natural gas properties by depletion base. An impairment loss is indicated if
the sum of the expected undiscounted future net cash flows is less than the
carrying amount of the assets. If the estimated undiscounted future net cash
flows are less than the carrying amount of the Company’s assets, it recognizes
an impairment loss for the amount by which the carrying amount of the asset
exceeds the estimated fair value of the asset.
The Company calculates the expected undiscounted future net
cash flows of its long-lived assets and their integrated assets using
management’s assumptions and expectations of (i) commodity prices, which are
based on the New York Mercantile Exchange (“NYMEX”) strip, (ii) pricing
adjustments for differentials, (iii) production costs, (iv) capital expenditures,
(v) production volumes, (vi) estimated proved reserves and risk-adjusted
probable and possible reserves, and (vii) prevailing market rates of income and
expenses from integrated assets. At
March 31,
2017,
the Company’s estimates of commodity prices for
purposes of determining undiscounted future cash flows, which are based on the NYMEX
strip, ranged from a 2017 price of $51.58 per barrel of oil to a 2024 price of
$54.62 per barrel of oil. Similarly, natural gas prices ranged from a 2017
price of $3.32 per Mcf of natural gas decreasing to a 2020 price of $2.82 per Mcf
partially recovering to a 2024 price of $3.04 per Mcf of natural gas. Commodity
prices for this purpose were held flat after 2024.
The Company calculates the estimated fair values of its
long-lived assets and their integrated assets using a discounted future cash
flow model. Fair value assumptions associated with the calculation of
discounted future net cash flows include (i) market estimates of commodity
prices, (ii) pricing adjustments for differentials, (iii) production costs,
(iv) capital expenditures, (v) production volumes, (vi) estimated proved
reserves and risk-adjusted probable and possible reserves, (vii) prevailing
market rates of income and expenses from integrated assets and (viii) discount
rate. The expected future net cash flows were discounted using an annual rate
of 10 percent to determine fair value. These are classified as Level 3 fair
value assumptions.
During the three months ended March 31, 2016, NYMEX strip
prices declined as compared to December 31, 2015, and as a result the carrying
amount of the Company’s Yeso field of approximately $3.4 billion exceeded the
expected undiscounted future net cash flows resulting in a non-cash charge
against earnings of approximately $1.5 billion. The non-cash charge represented
the amount by which the carrying amount exceeded the estimated fair value of
the assets.
The
following table reports the carrying amount, estimated fair value and
impairment expense of long-lived assets for the indicated period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
|
|
|
Carrying
|
|
|
Fair Value
|
|
|
Impairment
|
(in millions)
|
|
|
Amount
|
|
|
(Level 3)
|
|
|
Expense
|
|
|
|
|
|
|
|
|
|
|
March 2016
|
|
$
|
3,438
|
|
$
|
1,913
|
|
$
|
1,525
|
|
|
|
|
|
|
|
|
|
|
It
is reasonably possible that the estimate of undiscounted future net cash flows of
the Company’s long-lived assets may change in the future resulting in the need
to impair carrying values. The primary factors that may affect estimates of
future cash flows are (i) commodity prices including differentials,
(ii) increases or decreases in production and capital costs, (iii)
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
future reserve volume
adjustments, both positive and negative, to proved reserves and appropriate
risk-adjusted probable and possible reserves, (iv) results of future
drilling activities and (v) changes in income and expenses from integrated
assets.
Note 7.
Derivative
financial instruments
The Company uses derivative financial instruments to manage
its exposure to commodity price fluctuations. Commodity derivative instruments
are used to (i) reduce the effect of the volatility of price changes on
the oil and natural gas the Company produces and sells, (ii) support the
Company’s capital budget and expenditure plans and (iii) support the economics
associated with acquisitions. The Company does not enter into derivative
financial instruments for speculative or trading purposes. The Company may also
enter into physical delivery contracts to effectively provide commodity price
hedges. Because these physical delivery contracts are not expected to be net
cash settled, they are considered to be normal sales contracts and not
derivatives. Therefore, these contracts are not recorded in the Company’s
consolidated financial statements.
The Company does not designate its derivative instruments
to qualify for hedge accounting. Accordingly, the Company reflects changes in
the fair value of its derivative instruments in its consolidated statements of
operations as they occur.
The following
table summarizes the amounts reported in earnings related to the commodity
derivative instruments for the three months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Gain on derivatives:
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
266
|
|
$
|
72
|
|
|
Natural gas derivatives
|
|
|
20
|
|
|
9
|
|
|
|
Total
|
|
$
|
286
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents the Company’s net cash receipts from (payments on) derivatives for
the three months ended March 31, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
|
Oil derivatives
|
|
$
|
31
|
|
$
|
252
|
|
|
Natural gas derivatives
|
|
|
(3)
|
|
|
7
|
|
|
|
Total
|
|
$
|
28
|
|
$
|
259
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Commodity derivative
contracts at March 31, 2017.
The following table sets forth the
Company’s outstanding derivative contracts at
March 31, 2017
. When
aggregating multiple contracts, the weighted average contract price is disclosed.
All of the Company’s derivative contracts at
March
31, 2017 are expected to settle by December 31, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
7,708,480
|
|
6,898,370
|
|
6,333,080
|
|
20,939,930
|
|
|
Price per Bbl
|
|
|
$
|
57.22
|
$
|
51.87
|
$
|
52.04
|
$
|
53.89
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
5,875,629
|
|
5,516,170
|
|
5,204,318
|
|
4,941,007
|
|
21,537,124
|
|
|
Price per Bbl
|
$
|
52.11
|
$
|
51.93
|
$
|
51.75
|
$
|
51.59
|
$
|
51.86
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
2,355,000
|
|
2,253,000
|
|
2,163,000
|
|
2,083,000
|
|
8,854,000
|
|
|
Price per Bbl
|
$
|
55.15
|
$
|
55.11
|
$
|
55.14
|
$
|
55.16
|
$
|
55.14
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
6,141,500
|
|
5,290,000
|
|
5,290,000
|
|
16,721,500
|
|
|
Price per Bbl
|
|
|
$
|
(1.03)
|
$
|
(0.49)
|
$
|
(0.49)
|
$
|
(0.69)
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
3,870,000
|
|
3,913,000
|
|
3,956,000
|
|
3,956,000
|
|
15,695,000
|
|
|
Price per Bbl
|
$
|
(1.00)
|
$
|
(1.00)
|
$
|
(1.00)
|
$
|
(1.00)
|
$
|
(1.00)
|
Natural Gas Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
14,814,642
|
|
14,665,441
|
|
14,043,000
|
|
43,523,083
|
|
|
Price per MMBtu
|
|
|
$
|
3.08
|
$
|
3.10
|
$
|
3.09
|
$
|
3.09
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
8,656,000
|
|
8,401,000
|
|
8,249,000
|
|
8,064,000
|
|
33,370,000
|
|
|
Price per MMBtu
|
$
|
3.04
|
$
|
3.04
|
$
|
3.04
|
$
|
3.03
|
$
|
3.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) The index prices for the oil price swaps are based on
the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
|
(b) The basis differential price is between Midland – WTI and
Cushing – WTI.
|
(c) The index prices for the natural gas price swaps are
based on the NYMEX – Henry Hub last trading day futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative counterparties.
The Company uses credit and other
financial criteria to evaluate the creditworthiness of counterparties to its
derivative instruments. The Company believes that all of its derivative
counterparties are currently acceptable credit risks. Other than provided by
the Company’s credit facility, the Company is not required to provide credit
support or collateral to any counterparties under its derivative contracts, nor
are they required to provide credit support to the Company. Under the terms of
the Company’s credit facility, certain events could occur that would cause any
obligations under the Company’s credit facility to no longer be secured by the
Company’s oil and natural gas properties.
At March 31,
2017, the Company had a net asset position of $84 million as a result of
outstanding derivative contracts
which are reflected in the accompanying consolidated balance sheets. The
Company assessed this balance for concentration risk and noted balances of
approximately $14 million, $13 million, $13 million and $13 million with
Citibank, N.A., J.P. Morgan Chase Bank, Societe Generale and ING Bank,
respectively.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 8.
Debt
The Company’s
debt consisted of the following at March 31, 2017 and December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Credit facility
|
|
$
|
-
|
|
$
|
-
|
5.5% unsecured senior notes due 2022
|
|
|
600
|
|
|
600
|
5.5% unsecured senior notes due 2023
|
|
|
1,550
|
|
|
1,550
|
4.375% unsecured senior notes due 2025
|
|
|
600
|
|
|
600
|
Unamortized original issue premium
|
|
|
21
|
|
|
22
|
Senior notes issuance costs, net
|
|
|
(30)
|
|
|
(31)
|
|
Less: current portion
|
|
|
-
|
|
|
-
|
|
|
Total long-term debt
|
|
$
|
2,741
|
|
$
|
2,741
|
|
|
|
|
|
|
|
|
|
Credit
facility.
At March 31,
2017, the Company’s credit facility, as amended and restated, had a maturity
date of May 9, 2019. At March 31, 2017, the Company’s commitments from its bank
group were $2.5 billion and its borrowing base was $2.8 billion. See Note 14
for a discussion of the credit facility amendment that occurred in April 2017.
Senior notes.
Interest on the Company’s senior notes is paid in arrears semi-annually. The
senior notes are fully and unconditionally guaranteed on a senior unsecured
basis by all subsidiaries of the Company, subject to customary release
provisions as described in Note 13.
At
March 31, 2017
, the Company was in compliance with the covenants under
all of its debt instruments.
Principal
maturities of long-term debt.
Principal
maturities of long-term debt outstanding at March 31, 2017 were as follows:
|
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
|
Remaining 2017
|
|
$
|
|
-
|
2018
|
|
|
|
-
|
2019
|
|
|
|
-
|
2020
|
|
|
|
-
|
2021
|
|
|
|
-
|
2022
|
|
|
|
600
|
Thereafter
|
|
|
|
2,150
|
|
Total
|
$
|
|
2,750
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Interest expense.
The following
amounts have been incurred and charged to interest expense for the
three
months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments for interest
|
|
$
|
61
|
|
$
|
42
|
Non-cash interest
|
|
|
3
|
|
|
3
|
Net changes in accruals
|
|
|
(24)
|
|
|
9
|
|
Total interest expense
|
|
$
|
40
|
|
$
|
54
|
|
|
|
|
|
|
|
|
|
|
|
Note 9.
Commitments
and contingencies
Legal actions
.
The Company is a party to proceedings and
claims incidental to its business. While many of these matters involve inherent
uncertainty, the Company believes that the amount of the liability, if any,
ultimately incurred with respect to any such proceedings or claims will not have
a material adverse effect on the Company’s consolidated financial position as a
whole or on its liquidity, capital resources or future results of operations.
The Company will continue to evaluate proceedings and claims involving the
Company on a regular basis and will establish and adjust any reserves as
appropriate to reflect its assessment of the then current status of the
matters.
Severance tax, royalty and joint interest
audits
.
The Company is subject to routine severance, royalty and joint
interest audits from regulatory bodies and non-operators and makes accruals as
necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject
to various possible contingencies that arise primarily from interpretations
affecting the oil and natural gas industry. Such contingencies include
differing interpretations as to the prices at which oil and natural gas sales
may be made, the prices at which royalty owners may be paid for production from
their leases, allowable costs under joint interest arrangements and other
matters. At
March 31, 2017
and December 31, 2016
, the Company had $4 million and $7 million, respectively, accrued
for estimated exposure. Although
the Company believes that it has estimated its exposure with respect to the
various laws and regulations, administrative rulings and interpretations
thereof, adjustments could be required as new interpretations and regulations
are issued.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Commitments.
The Company periodically enters into contractual
arrangements under which the Company is committed to expend funds. These
contractual arrangements relate to purchase agreements the Company has entered
into including drilling commitments, water commitment agreements, throughput
volume delivery commitments, power commitments, fixed asset commitments and
maintenance commitments.
The
following table summarizes the Company’s commitments at
March 31, 2017
:
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Remaining 2017
|
|
$
|
46
|
2018
|
|
|
65
|
2019
|
|
|
52
|
2020
|
|
|
25
|
2021
|
|
|
21
|
2022
|
|
|
22
|
Thereafter
|
|
|
78
|
|
Total
|
$
|
309
|
|
|
|
|
|
Operating
leases.
The Company leases
vehicles, equipment and office facilities under non-cancellable operating
leases. Lease payments associated with these operating leases for the three
months ended
March 31, 2017
and 2016 were approximately $3 million and $2 million,
respectively.
Future
minimum lease commitments under non-cancellable operating leases at
March 31, 2017
were as
follows:
|
|
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
Remaining 2017
|
|
$
|
7
|
2018
|
|
|
8
|
2019
|
|
|
7
|
2020
|
|
|
5
|
2021
|
|
|
5
|
2022
|
|
|
-
|
Thereafter
|
|
|
1
|
|
Total
|
$
|
33
|
|
|
|
|
|
Note 10.
Income taxes
The effective income tax rates were 36.3 percent
and 36.8 percent for the three months ended
March 31, 2017
and 2016,
respectively. Total income tax expense for the three months ended
March 31, 2017
differed from amounts computed by applying the United States federal statutory
tax rates to pre-tax income primarily due to state income taxes and the impact
of permanent differences between book and taxable income, partially offset by a
discrete income tax benefit of approximately $7 million related to excess tax
benefits on stock-based awards, which are now recorded in the income tax
provision due to the adoption of ASU No. 2016-09.
Total
income tax benefit for the three months ended
March
31, 2016
differed from amounts
computed by applying the United States federal statutory tax rates to pre-tax
loss primarily due to state income taxes, partially offset by the impact of
permanent differences between book and taxable loss.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 11.
Related
party transactions
The Company paid royalties on certain properties to a
partnership in which a director of the Company is the general partner and owns
a 3.5 percent partnership interest. These payments were reported in the Company’s
consolidated statements of operations and totaled approximately $2 million and
$1 million for the three months ended March 31, 2017 and 2016, respectively.
Note 12.
Earnings per share
The Company uses the two-class method of calculating
earnings per share because certain of the Company’s unvested share-based awards
qualify as participating securities.
The Company’s basic earnings per share attributable to
common stockholders is computed as (i) net income (loss) as reported, (ii) less
participating basic earnings (iii) divided by weighted average basic common
shares outstanding. The Company’s diluted earnings per share attributable to
common stockholders is computed as (i) basic earnings attributable to common
stockholders, (ii) plus reallocation of participating earnings (iii) divided by
weighted average diluted common shares outstanding.
The
following table reconciles the Company’s earnings from operations and earnings
attributable to common stockholders to the basic and diluted earnings used to
determine the Company’s earnings per share amounts for the three months ended
March 31, 2017 and 2016, respectively, under the two-class method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in millions)
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Net income (loss) as reported
|
$
|
650
|
|
$
|
(1,020)
|
Participating basic earnings (a)
|
|
(5)
|
|
|
-
|
|
Basic earnings attributable to common stockholders
|
|
645
|
|
|
(1,020)
|
Reallocation of participating earnings
|
|
-
|
|
|
-
|
|
Diluted earnings attributable to common stockholders
|
$
|
645
|
|
$
|
(1,020)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Unvested restricted stock awards
represent participating securities because they participate in nonforfeitable
dividends or distributions with the common equity holders of the Company.
Participating earnings represent the distributed earnings of the Company
attributable to the participating securities. Unvested restricted stock
awards do not participate in undistributed net losses as they are not
contractually obligated to do so.
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
The
following table is a reconciliation of the basic weighted average common shares
outstanding to diluted weighted average common shares outstanding for the
three
months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
Basic
|
|
146,838
|
|
128,396
|
|
|
Dilutive common stock options
|
|
12
|
|
-
|
|
|
Dilutive performance units
|
|
701
|
|
-
|
|
Diluted
|
|
147,551
|
|
128,396
|
|
|
|
|
|
|
|
The
following table is a summary of the performance units that were not included in
the computation of diluted earnings per share, as inclusion of these items
would be antidilutive:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in thousands)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Number of antidilutive units:
|
|
|
|
|
|
Antidilutive performance units
|
|
108
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance
unit awards.
The number of shares
of common stock that will ultimately be issued for performance units will be
determined by a combination of (i) comparing the Company’s total shareholder
return relative to the total shareholder return of a predetermined group of
peer companies at the end of the performance period and (ii) the Company’s
absolute total shareholder return at the end of the performance period. The
performance period is 36 months. The actual payout of shares will be between
zero and 300 percent.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 13.
Subsidiary guarantors
All of the Company’s 100
percent owned subsidiaries have fully and unconditionally guaranteed the
Company’s senior notes. The indentures governing the Company’s senior notes
provide that the guarantees of its subsidiary guarantors will be released in
certain customary circumstances including (i) in connection with any sale,
exchange or other disposition, whether by merger, consolidation or otherwise,
of the capital stock of that guarantor to a person that is not the Company or a
restricted subsidiary of the Company, such that, after giving effect to such
transaction, such guarantor would no longer constitute a subsidiary of the
Company, (ii) in connection with any sale, exchange or other disposition (other
than a lease) of all or substantially all of the assets of that guarantor to a
person that is not the Company or a restricted subsidiary of the Company, (iii)
upon the merger of a guarantor into the Company or any other guarantor or the liquidation
or dissolution of a guarantor, (iv) if the Company designates any restricted
subsidiary that is a guarantor to be an unrestricted subsidiary in accordance
with the indenture, (v) upon legal defeasance or satisfaction and discharge of
the indenture and (vi) upon written notice of such release or discharge by the
Company to the trustee following the release or discharge of all guarantees by
such guarantor of any indebtedness that resulted in the creation of such
guarantee, except a discharge or release by or as a result of payment under
such guarantee.
See Note 8 for a summary of
the Company’s senior notes. In accordance with practices accepted by the United
States Securities and Exchange Commission, the Company has prepared condensed
consolidating financial statements in order to quantify the assets, results of
operations and cash flows of such subsidiaries as subsidiary guarantors.
The following condensed consolidating balance sheets
at
March 31, 2017 and December
31, 2016
,
condensed consolidating statements of operations for the
three
months ended
March 31, 2017 and
2016
and
condensed consolidating statements of cash flows for the
three
months ended
March 31, 2017 and
2016,
present
financial information for Concho Resources Inc. as the parent on a stand-alone basis
(carrying any investments in subsidiaries under the equity method), financial
information for the subsidiary guarantors on a stand-alone basis and the
consolidation and elimination entries necessary to arrive at the information
for the Company on a consolidated basis. All current and deferred income taxes
are recorded on Concho Resources Inc., as the subsidiaries are flow-through
entities for income tax purposes. The subsidiary guarantors are not restricted
from making distributions to the Company.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Condensed
Consolidating Balance Sheet
|
March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
8,947
|
|
$
|
(593)
|
|
$
|
(8,354)
|
|
$
|
-
|
Other current assets
|
|
|
74
|
|
|
1,279
|
|
|
-
|
|
|
1,353
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
11,620
|
|
|
-
|
|
|
11,620
|
Property and equipment, net
|
|
|
-
|
|
|
209
|
|
|
-
|
|
|
209
|
Investment in subsidiaries
|
|
|
2,757
|
|
|
-
|
|
|
(2,757)
|
|
|
-
|
Other long-term assets
|
|
|
52
|
|
|
85
|
|
|
-
|
|
|
137
|
|
Total assets
|
|
$
|
11,830
|
|
$
|
12,600
|
|
$
|
(11,111)
|
|
$
|
13,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
(593)
|
|
$
|
8,947
|
|
$
|
(8,354)
|
|
$
|
-
|
Other current liabilities
|
|
|
25
|
|
|
755
|
|
|
-
|
|
|
780
|
Long-term debt
|
|
|
2,741
|
|
|
-
|
|
|
-
|
|
|
2,741
|
Other long-term liabilities
|
|
|
1,125
|
|
|
141
|
|
|
-
|
|
|
1,266
|
Equity
|
|
|
8,532
|
|
|
2,757
|
|
|
(2,757)
|
|
|
8,532
|
|
Total liabilities and equity
|
|
$
|
11,830
|
|
$
|
12,600
|
|
$
|
(11,111)
|
|
$
|
13,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
8,991
|
|
$
|
(336)
|
|
$
|
(8,655)
|
|
$
|
-
|
Other current assets
|
|
|
12
|
|
|
534
|
|
|
-
|
|
|
546
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
11,086
|
|
|
-
|
|
|
11,086
|
Property and equipment, net
|
|
|
-
|
|
|
216
|
|
|
-
|
|
|
216
|
Investment in subsidiaries
|
|
|
1,989
|
|
|
-
|
|
|
(1,989)
|
|
|
-
|
Other long-term assets
|
|
|
11
|
|
|
260
|
|
|
-
|
|
|
271
|
|
Total assets
|
|
$
|
11,003
|
|
$
|
11,760
|
|
$
|
(10,644)
|
|
$
|
12,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
(336)
|
|
$
|
8,991
|
|
$
|
(8,655)
|
|
$
|
-
|
Other current liabilities
|
|
|
114
|
|
|
639
|
|
|
-
|
|
|
753
|
Long-term debt
|
|
|
2,741
|
|
|
-
|
|
|
-
|
|
|
2,741
|
Other long-term liabilities
|
|
|
861
|
|
|
141
|
|
|
-
|
|
|
1,002
|
Equity
|
|
|
7,623
|
|
|
1,989
|
|
|
(1,989)
|
|
|
7,623
|
|
Total liabilities and equity
|
|
$
|
11,003
|
|
$
|
11,760
|
|
$
|
(10,644)
|
|
$
|
12,119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Condensed
Consolidating Statement of Operations
|
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
612
|
|
$
|
-
|
|
$
|
612
|
Total operating costs and expenses
|
|
|
285
|
|
|
164
|
|
|
-
|
|
|
449
|
|
Income from operations
|
|
|
285
|
|
|
776
|
|
|
-
|
|
|
1,061
|
Interest expense
|
|
|
(40)
|
|
|
-
|
|
|
-
|
|
|
(40)
|
Other, net
|
|
|
776
|
|
|
-
|
|
|
(776)
|
|
|
-
|
|
Income before income taxes
|
|
|
1,021
|
|
|
776
|
|
|
(776)
|
|
|
1,021
|
Income tax expense
|
|
|
(371)
|
|
|
-
|
|
|
-
|
|
|
(371)
|
|
Net income
|
|
$
|
650
|
|
$
|
776
|
|
$
|
(776)
|
|
$
|
650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
|
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
284
|
|
$
|
-
|
|
$
|
284
|
Total operating costs and expenses
|
|
|
79
|
|
|
(1,916)
|
|
|
-
|
|
|
(1,837)
|
|
Income (loss) from operations
|
|
|
79
|
|
|
(1,632)
|
|
|
-
|
|
|
(1,553)
|
Interest expense
|
|
|
(53)
|
|
|
(1)
|
|
|
-
|
|
|
(54)
|
Other, net
|
|
|
(1,640)
|
|
|
(7)
|
|
|
1,640
|
|
|
(7)
|
|
Loss before income taxes
|
|
|
(1,614)
|
|
|
(1,640)
|
|
|
1,640
|
|
|
(1,614)
|
Income tax benefit
|
|
|
594
|
|
|
-
|
|
|
-
|
|
|
594
|
|
Net loss
|
|
$
|
(1,020)
|
|
$
|
(1,640)
|
|
$
|
1,640
|
|
$
|
(1,020)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Condensed
Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
Consolidating
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by operating activities
|
|
$
|
19
|
|
$
|
388
|
|
$
|
-
|
|
$
|
407
|
Net cash flows provided by investing activities
|
|
|
-
|
|
|
330
|
|
|
-
|
|
|
330
|
Net cash flows used in financing activities
|
|
|
(19)
|
|
|
-
|
|
|
-
|
|
|
(19)
|
|
Net increase in cash and cash equivalents
|
|
|
-
|
|
|
718
|
|
|
-
|
|
|
718
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
53
|
|
|
-
|
|
|
53
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
771
|
|
$
|
-
|
|
$
|
771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in millions)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by operating activities
|
|
$
|
10
|
|
$
|
360
|
|
$
|
-
|
|
$
|
370
|
Net cash flows used in investing activities
|
|
|
-
|
|
|
(122)
|
|
|
-
|
|
|
(122)
|
Net cash flows used in financing activities
|
|
|
(10)
|
|
|
-
|
|
|
-
|
|
|
(10)
|
|
Net increase in cash and cash equivalents
|
|
|
-
|
|
|
238
|
|
|
-
|
|
|
238
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
229
|
|
|
-
|
|
|
229
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
467
|
|
$
|
-
|
|
$
|
467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 14.
Subsequent
events
Credit Facility amendment.
In April 2017, the Company amended its credit facility to
extend the maturity date to May 9, 2022. Additionally, the Company increased
its borrowing base to $3.0 billion and decreased the commitments from its bank
group to $2.0 billion.
New
commodity derivative contracts.
After
March 31, 2017, the Company entered into the following oil price swaps and oil
basis swaps to hedge additional amounts of the Company’s estimated future
production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
971,000
|
|
1,068,000
|
|
855,000
|
|
2,894,000
|
|
|
Price per Bbl
|
|
|
$
|
50.41
|
$
|
50.50
|
$
|
50.59
|
$
|
50.49
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
630,000
|
|
637,000
|
|
644,000
|
|
644,000
|
|
2,555,000
|
|
|
Price per Bbl
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil price swaps are based on the NYMEX – WTI
monthly average futures price.
|
(b)
|
The basis differential price is between Midland – WTI and Cushing –
WTI.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Note 15.
Supplementary
information
Capitalized
costs
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
17,081
|
|
$
|
16,620
|
|
Unproved
|
|
|
2,206
|
|
|
1,856
|
|
Less: accumulated depletion
|
|
|
(7,667)
|
|
|
(7,390)
|
|
|
Net capitalized costs for oil and natural gas properties
|
|
$
|
11,620
|
|
$
|
11,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
incurred for oil and natural gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
127
|
|
$
|
252
|
|
Unproved
|
|
|
306
|
|
|
139
|
Exploration
|
|
|
235
|
|
|
170
|
Development
|
|
|
158
|
|
|
83
|
|
Total costs incurred for oil and natural gas properties
|
|
$
|
826
|
|
$
|
644
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2017
Unaudited
Item 2. Management’s Discussion and
Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist
you in understanding our business and results of operations together with our
present financial condition. This section should be read in conjunction with
our historical consolidated financial statements and notes.
Certain statements in our discussion below are
forward-looking statements. These forward-looking statements involve risks and
uncertainties. We caution that a number of factors could cause actual results
to differ materially from those implied or expressed by the forward-looking
statements. Please see “Cautionary Statement Regarding Forward-Looking
Statements.”
Overview
We are an
independent oil and natural gas company engaged in the acquisition, development,
exploration and production of oil and natural gas properties. Our core
operations are primarily focused in the Permian Basin of southeast New Mexico
and west Texas. Concho’s legacy in the Permian Basin provides us a deep
understanding of operating and geological trends. We are actively applying new
technologies, such as extended length lateral drilling, multi-well pad
development and enhanced completion techniques, throughout our four core
operating areas: the Northern Delaware Basin, the Southern Delaware Basin, the
Midland Basin and the New Mexico Shelf. Oil comprised
59 percent of our 720 MMBoe of estimated proved
reserves at December 31, 2016 and 63 percent of our 181,372 Boe of average
daily production for the three months ended
March
31, 2017
.
We seek to operate the wells in which we own an
interest, and we operated wells that accounted for 92 percent of our proved
developed producing reserves and 79 percent of our 7,858 gross wells at
December 31, 2016
. By controlling operations, we are able to more effectively
manage the cost and timing of exploration and development of our properties,
including the drilling and stimulation methods used.
Financial
and Operating Performance
Our financial
and operating performance for the three months ended March 31, 2017 and 2016
included the following highlights:
·
Net income was $
650 m
illion
($4.37
per diluted share) as compared to net loss
of $1.0
billion ($(7.95)
per diluted share) for the first three months of
2017 and 2016, respectively. The increase was primarily due to:
•
no
recorded impairments of long-lived assets during the three months ended March
31, 2017, as compared to $1.5 billion in non-cash impairment charges in 2016
,
primarily attributable to properties in our New
Mexico Shelf area;
•
gain
on disposition of assets, net increased $543 million primarily due to our
disposition of Alpha Crude Connector, LLC (“ACC”) which resulted in a gain of
approximately $656 million during the three months ended March 31, 2017, as
compared to a gain of approximately $111 million during 2016 primarily
attributable to our Northern Delaware Basin divestiture in February 2016;
•
$328
million increase in oil and natural gas revenues as a result of a
68 percent increase in commodity price realizations per Boe
(excluding the effects of derivative activities) and
a
30
percent increase in production
;
•
$205 million increase in gain on derivatives
during
the three months ended March 31, 2017, as compared to 2016; and
•
$27
million decrease in depreciation, depletion and amortization expense, primarily
due to a decrease in the depletion rate per Boe period over period, partially
offset by an increase in production;
partially
offset by:
•
$965
million change in our income tax provision due to income before income taxes during
the three months ended March 31, 2017, as compared to a loss before income
taxes during 2016; and
•
$25
million increase in production and ad valorem tax expense, primarily due to
increased production taxes as a result of increased oil and natural gas sales.
·
Average daily sales volumes of
181,372
Boe
per day during the first three months of 2017 increased 30 percent as compared
to 139,482 Boe per day during 2016.
·
Net cash provided by operating activities increased by approximately
$37 million to $407
million
for the first
three months of 2017, as compared to $370
m
illion
in the first three months of 2016, primarily due to an increase in oil and
natural gas revenues and decreased cash interest expense, partially offset by, (i)
a decrease in cash settlements on derivatives, (ii) negative variances in
working capital, (iii) increased production tax expense and (iv) changes
related to cash income taxes.
·
Cash increased by approximately $718 million during the first
three months of 2017 primarily as a result of proceeds from our February 2017
divestiture of ACC.
Commodity Prices
Our
results of operations are heavily influenced by commodity prices. Commodity
prices may fluctuate widely in response to (i) relatively minor changes in the
supply of and demand for oil, natural gas and natural gas liquids, (ii) market
uncertainty and (iii) a variety of additional factors that are beyond our
control. Factors that may impact future commodity prices, including the price
of oil, natural gas and natural gas liquids, include, but are not limited to:
·
continuing economic uncertainty
worldwide;
·
political and economic developments in
oil and natural gas producing regions, including Africa, South America and the
Middle East;
·
the extent to which members of the
Organization of Petroleum Exporting Countries and other oil exporting nations
are able to influence global oil supply levels;
·
technological advances affecting energy
consumption and energy supply;
·
domestic and foreign governmental
regulations, including limits on the United States’ ability to export crude
oil, and taxation;
·
the level of global inventories;
·
the proximity, capacity, cost and
availability of pipelines and other transportation facilities, as well as the
availability of commodity processing and gathering and refining capacity;
·
risks related to the concentration of
our operations in the Permian Basin of southeast New Mexico and west Texas and
the level of commodity inventory in the Permian Basin;
·
the quality of the oil we produce;
·
the overall global demand for oil,
natural gas and natural gas liquids;
·
the domestic and foreign supply of oil,
natural gas and natural gas liquids;
·
political and economic events that
directly or indirectly impact the relative strength or weakness of the United
States dollar, on which oil prices are benchmarked globally, against foreign
currencies;
·
the effect of energy conservation
efforts;
·
the price and availability of
alternative fuels; and
·
overall North American oil, natural gas
and natural gas liquids supply and demand fundamentals, including:
•
the United States economy,
•
weather conditions, and
•
liquefied natural gas deliveries to and exports from the
United States.
Although
we cannot predict the occurrence of events that may affect future commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that we produce will generally approximate current market prices in
the geographic region of the production. From time to time, we expect that we
may economically hedge a portion of our commodity price risk to mitigate the
impact of price volatility on our business. See Notes 7 and 14 of the Condensed
Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information
regarding our commodity derivative positions at March 31, 2017 and additional
derivative contracts entered into subsequent to March 31, 2017, respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. The average oil and
natural gas prices were higher during the comparable quarterly period of 2017
measured against 2016. The following table sets forth the average New York
Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months
ended
March 31, 2017
and 2016, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
51.95
|
|
$
|
33.73
|
|
Natural gas (MMBtu)
|
|
$
|
3.08
|
|
$
|
1.99
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
54.45
|
|
$
|
41.45
|
|
|
Low
|
|
$
|
47.34
|
|
$
|
26.21
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
3.72
|
|
$
|
2.47
|
|
|
Low
|
|
$
|
2.56
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $53.40 and $48.84 per Bbl and $3.33 and
$3.04 per MMBtu, respectively, during the period from
April 1, 2017
to May 1, 2017. At May 1, 2017, the NYMEX oil price and NYMEX natural gas price
were $48.84 per Bbl and $3.22 per MMBtu, respectively.
Historically, and during the three months ended
March 31, 2017, we derived a significant portion of our total natural gas
revenues from the value of the natural gas liquids contained in our natural
gas, with the remaining portion coming from the value of the dry natural gas
residue. The average Mont Belvieu price for a blended barrel of natural gas
liquids was $24.19 per Bbl and $14.48 per Bbl during the three months ended
March 31, 2017 and 2016, respectively.
Recent Events
Credit Facility amendment.
In April 2017, we amended our credit facility to extend the
maturity date to May 9, 2022. Additionally, we increased our borrowing base to
$3.0 billion and decreased the commitments from our bank group to $2.0 billion.
2017 capital budget
.
In
February 2017, we announced our updated 2017 capital budget, excluding
acquisitions, of approximately $1.8 billion with expected capital spending to
range between $1.6 billion and $1.8 billion. Approximately 90 percent of
capital will be directed to drilling and completion activity. Our 2017 capital
program is expected to continue focusing on
extended
length lateral drilling and
multi-well pad development. Our 2017 capital
budget, based on our current expectations of commodity prices and costs, is
expected to be within our cash flows. Our budget could change depending on
numerous factors, including commodity prices, leverage metrics and industry
conditions.
ACC divestiture.
In February 2017, we closed on our
previously announced divestiture of our ownership interest in ACC in which we
and our joint venture partner entered into separate agreements to sell 100
percent of our respective ownership interests in ACC. After adjustments for
debt and working capital, we received cash proceeds from the sale of
approximately $803 million. Potential uses of our net cash proceeds from the
sale of ACC could include (i) financing possible future acquisitions, (ii)
funding future capital expenditures associated with our acquisition, exploration
and development activities, (iii) retiring or purchasing outstanding debt and
(iv) general corporate purposes. After direct transaction costs, we recorded a
pre-tax gain on disposition of assets of approximately $656 million. Our net
investment in ACC at the time of closing was approximately $129 million.
Northern Delaware Basin
acquisition.
In January 2017, we completed a portion of the previously
announced acquisition of approximately 16,400 net acres in the Northern
Delaware Basin. As consideration for this portion of the acquisition, we paid
approximately $132 million in cash and issued to the seller approximately 1.9
million shares of our common stock with an approximate value of $258 million. In
April 2017, we closed on the remainder of the acquisition. The acquisition, in
its entirety, is subject to customary closing and post-closing adjustments.
Derivative
Financial Instruments
Derivative financial instrument exposure.
At
March 31, 2017
, the fair value of our financial derivatives was a net
asset
of $
84
million. At
March 31, 2017
, all of our counterparties to these financial derivatives
were parties to our credit facility and have their outstanding debt commitments
and derivative exposures collateralized pursuant to our credit facility. At
March 31, 2017
, under the
terms of our financial derivative instruments and their collateralization under
our credit facility, we do not have exposure to potential “margin calls” on our
financial derivative instruments. We currently have no reason to believe that
our counterparties to these commodity derivative contracts are not financially
viable. Under the terms of our credit facility, certain events could occur that
would cause the obligations under our credit facility to no longer be secured
by our oil and natural gas properties. Our credit facility does not allow us to
offset amounts we may owe a lender against amounts we may be owed related to
our financial instruments with such party.
New commodity derivative contracts.
After March 31, 2017, we entered into the following
oil price swaps and oil basis swaps to hedge additional amounts of our
estimated future production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
971,000
|
|
1,068,000
|
|
855,000
|
|
2,894,000
|
|
|
Price per Bbl
|
|
|
$
|
50.41
|
$
|
50.50
|
$
|
50.59
|
$
|
50.49
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
630,000
|
|
637,000
|
|
644,000
|
|
644,000
|
|
2,555,000
|
|
|
Price per Bbl
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
$
|
(1.25)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil
price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly
average futures price.
|
|
(b)
|
The basis differential price is
between Midland – WTI and Cushing – WTI.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations
The following table sets forth summary
information concerning our production and operating data for the three months
ended
March 31, 2017
and 2016.
The
actual historical data in this table excludes results from our asset acquisition
from Reliance Energy, Inc. (the “Reliance Acquisition”) for periods prior to October
2016.
Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of our acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
113,600
|
|
|
89,011
|
|
|
Natural gas (Mcf)
|
|
|
406,633
|
|
|
302,824
|
|
|
Total (Boe)
|
|
|
181,372
|
|
|
139,482
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices per unit:
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
49.08
|
|
$
|
29.90
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
52.12
|
|
$
|
60.90
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
3.00
|
|
$
|
1.50
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
2.90
|
|
$
|
1.75
|
|
|
Total, without derivatives (Boe)
|
|
$
|
37.47
|
|
$
|
22.34
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
39.15
|
|
$
|
42.66
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
$
|
5.35
|
|
$
|
7.28
|
|
|
Production and ad valorem taxes
|
|
$
|
2.93
|
|
$
|
1.78
|
|
|
Depreciation, depletion and amortization
|
|
$
|
17.36
|
|
$
|
24.43
|
|
|
General and administrative
|
|
$
|
3.36
|
|
$
|
4.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the effect
of net cash receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
31
|
|
$
|
252
|
|
|
|
Natural gas derivatives
|
|
|
(3)
|
|
|
7
|
|
|
|
|
Total
|
|
$
|
28
|
|
$
|
259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation
of average prices with derivatives is a result of including the net cash
receipts from (payments on) commodity derivatives that are presented in our
statements of cash flows. This presentation of average prices with
derivatives is a means by which to reflect the actual cash performance of our
commodity derivatives for the respective periods and presents oil and natural
gas prices with derivatives in a manner consistent with the presentation
generally used by the investment community.
|
|
|
|
|
|
|
Three
Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$612 million for the three months ended
March 31, 2017
, an
increase of
$328 million (115
percent
) from $284 million for
2016
.
This increase was primarily due to the increase in realized oil and natural gas
prices as well as the increase in oil production and natural gas production.
Specific factors affecting oil and natural gas revenues include the following:
·
average daily oil production was 113,600
Bbl
for the three months ended
March 31, 2017
, an
increase
of 24,589
Bbl
(28
percent
) from 89,011
Bbl
for
2016
;
·
average realized oil price (excluding the effects of derivative
activities) was
$49.08
per Bbl during the three months ended
March 31, 2017
, an
increase of 64
percent
from
$29.90
per Bbl
during
2016
.
For the three
months ended March 31, 2017, our crude oil price differential relative to NYMEX
was $(2.87) per Bbl, or a realization of approximately 94 percent, as compared
to a crude oil price differential relative to NYMEX of $(3.83) per Bbl, or a
realization of approximately 89 percent, for 2016. The basis differential
between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing
location) for our oil directly impacts our realized oil price. For the three
months ended March 31, 2017 and 2016, the average market basis differential
between WTI-Midland and WTI-Cushing was a price benefit of $
0.75
per
Bbl and $
0.14
per
Bbl, respectively. Additionally, we incur fixed deductions from the posted
Midland oil price based on the location of our oil within the Permian Basin.
These fixed deductions were less per Boe during the
three
months ended
March
31, 2017 as compared to 2016
primarily due to (i) more production
transported through pipelines and (ii) successful renegotiation of fixed
deductions for existing production transported through pipelines.
·
average daily natural gas production was 406,633
Mcf
for the three months ended
March 31, 2017
, an
increase
of 103,809
Mcf
(34
percent
) from 302,824
Mcf
for
2016
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$3.00
per Mcf during the
three months ended
March 31, 2017
, an increase of 100
percent
from
$1.50
per Mcf during
2016.
For the three months ended March 31, 2017 and 2016, we realized approximately
97 percent and 75 percent, respectively, of the average NYMEX natural gas
prices for the respective periods. The increase in our realized gas price
(excluding the effects of derivatives) as a percentage of NYMEX during the
three months ended March 31, 2017 as compared to 2016 was primarily due to an
increase in the average Mont Belvieu price for a blended barrel of natural gas
liquids. Historically, and during the
three months ended
March 31, 2017,
we derived a significant portion of our total natural gas revenues from the
value of the natural gas liquids contained in our natural gas, with the
remaining portion coming from the value of the dry natural gas residue. The
average Mont Belvieu price for a blended barrel of natural gas liquids was $24.19
per Bbl and $14.48 per Bbl during the three months ended March 31, 2017 and
2016, respectively.
During December 2015, a third-party
natural gas processing plant located in the northern Delaware Basin became
inoperable following an explosion. We estimate that this event negatively
impacted production for the quarter ended March 31, 2016 by approximately
4.5 MBoepd. The plant became fully operational during April 2016.
Oil and natural gas production expenses.
The following table provides the
components of our oil and natural gas production expenses for the three months
ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
82
|
|
$
|
5.05
|
|
$
|
86
|
|
$
|
6.86
|
Workover costs
|
|
|
5
|
|
|
0.30
|
|
|
6
|
|
|
0.42
|
|
|
Total oil and natural gas production expenses
|
|
$
|
87
|
|
$
|
5.35
|
|
$
|
92
|
|
$
|
7.28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses were $82 million ($5.05
per Boe) for the three months ended
March 31,
2017
, which was a decrease of $4
million from $86 million ($6.86 per Boe) for the three months ended
March 31, 2016
.
The decrease in lease operating expenses during the first quarter of 2017 as
compared to 2016 was primarily due to (i)
implementation
of operational cost efficiencies, including improved infrastructure around
saltwater disposals
and (ii) an
overall decrease in the cost of goods and services.
The decrease
in lease operating expenses per Boe was primarily due to an increase in
production period over period
coupled
with the reduction in lease operating expenses noted above
.
Production and ad valorem
taxes.
The
following table provides the components of our production and ad valorem tax
expenses for the three months ended
March 31,
2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
$
|
44
|
|
$
|
2.66
|
|
$
|
17
|
|
$
|
1.34
|
Ad valorem taxes
|
|
|
4
|
|
|
0.27
|
|
|
6
|
|
|
0.44
|
|
|
Total production and ad valorem taxes
|
|
$
|
48
|
|
$
|
2.93
|
|
$
|
23
|
|
$
|
1.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes per unit of production were $2.66
per Boe during the three months ended
March
31, 2017
, an increase of 99
percent from $1.34 per Boe during
2016
. Over the same period, our revenue per Boe
prices (excluding the effects of derivatives) increased 68 percent. The
increase in production taxes per unit of production was directly related to the
increase in oil and natural gas sales. Additionally, tax credits of
approximately $4 million were received during the first quarter of 2016 related
to certain wells in Texas qualifying for reduced severance tax rates.
Generally, production and ad valorem taxes are related to
oil and natural gas sales.
Exploration
and abandonments expense.
The following table provides the components of our exploration and abandonments
expense for the three months ended
March 31,
2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
6
|
|
$
|
1
|
Leasehold abandonments
|
|
|
6
|
|
|
21
|
Other
|
|
|
3
|
|
|
1
|
|
Total exploration and abandonments
|
|
$
|
15
|
|
$
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our geological and geophysical expense for the
periods presented above primarily consists of the costs of acquiring and
processing geophysical data and core analysis.
For the three months ended
March 31, 2017 and 2016
, we recorded approximately $6 million and $21 million,
respectively, of leasehold abandonments. For the three months ended
March 31, 2017
,
our abandonments were primarily related to (i) acreage in our Northern Delaware
Basin and Midland Basin core areas in locations where we had no future plans to
drill and (ii) expiring acreage primarily located in our Southern Delaware
Basin core area. For the three months ended
March
31, 2016
, our abandonments were
primarily related to acreage in our New Mexico Shelf core area in locations
where we had no future plans to drill.
Depreciation, depletion and amortization
expense.
The following table provides components of our
depreciation, depletion and amortization expense for the three months ended
March 31, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
277
|
|
$
|
16.97
|
|
$
|
304
|
|
$
|
24.01
|
Depreciation of other property and equipment
|
|
|
6
|
|
|
0.37
|
|
|
6
|
|
|
0.39
|
Amortization of intangible assets - operating rights
|
|
|
-
|
|
|
0.02
|
|
|
-
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
283
|
|
$
|
17.36
|
|
$
|
310
|
|
$
|
24.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period
end
|
|
$
|
44.10
|
|
|
|
|
$
|
42.77
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end
|
|
$
|
2.73
|
|
|
|
|
$
|
2.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $277 million ($16.97 per Boe) for the three months ended March
31, 2017, a decrease of $27 million (9 percent) from $304 million ($24.01
per Boe) for 2016. The decrease in depletion expense was primarily due to a
lower depletion rate per Boe period over period partially offset by an increase
in production. The decrease in depletion expense per Boe period over period was
primarily due to (i) a non-cash impairment charge of approximately $1.5 billion
recorded in the first quarter of 2016 and (ii) an overall increase in proved
reserves period over period primarily caused by our successful exploratory
drilling program, the Reliance Acquisition and reductions in future estimated
lease operating expenses, partially offset by decreased proved reserves caused
by reclassification of proved undeveloped reserves to unproved reserves because
they are no longer expected to be developed within five years of their initial
recording.
Impairments of long-lived assets.
We periodically review our long-lived assets to
be held and used, including proved oil and natural gas properties and their
integrated assets, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable, for instance when there are
declines in commodity prices or well performance. We review our oil and natural
gas properties by depletion base. An impairment loss is indicated if the sum of
the expected undiscounted future net cash flows is less than the carrying
amount of the assets. If the estimated undiscounted future net
cash flows are less than the carrying amount of our
assets, we recognize an impairment loss for the amount by which the carrying
amount of the asset exceeds the estimated fair value of the asset.
We calculate the expected undiscounted future
net cash flows of our long-lived assets and their integrated assets using
management’s assumptions and expectations of (i) commodity prices, which are
based on the NYMEX strip, (ii) pricing adjustments for differentials, (iii)
production costs, (iv) capital expenditures, (v) production volumes, (vi) estimated
proved reserves and risk-adjusted probable and possible reserves, and (vii)
prevailing market rates of income and expenses from integrated assets. At March
31, 2017, our estimates of commodity prices for purposes of determining
undiscounted future cash flows, which are based on the NYMEX strip, ranged from
a 2017 price of $51.58 per barrel of oil to a 2024 price of $54.62 per barrel
of oil. Similarly, natural gas prices ranged from a 2017 price of $3.32 per Mcf
of natural gas decreasing to a 2020 price of $2.82 per Mcf of natural gas
partially recovering to a 2024 price of $3.04 per Mcf of natural gas. Commodity
prices for this purpose were held flat after 2024.
We calculate the estimated fair values of our
long-lived assets and their integrated assets using a discounted future cash
flow model. Fair value assumptions associated with the calculation of
discounted future net cash flows include (i) market estimates of commodity
prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv)
capital expenditures, (v) production volumes, (vi) estimated proved reserves
and risk-adjusted probable and possible reserves, (vii) prevailing market rates
of income and expenses from integrated assets and (viii) discount rate. The
expected future net cash flows were discounted using an annual rate of 10
percent to determine fair value.
During the three months ended March 31, 2016,
NYMEX strip prices declined as compared to December 31, 2015, and as a result
the carrying amount of our Yeso field in our New Mexico Shelf core area
exceeded the expected undiscounted future net cash flows resulting in a
non-cash charge against earnings of approximately $1.5 billion. The Yeso field,
as compared to our other fields not previously impaired, had significant proved
reserves upon acquisition, which required a higher valuation than a field more
exploratory in nature that has a higher risk factor adjustment in the fair
value estimate. Our estimates of commodity prices for purposes of determining
the estimated fair value at March 31, 2016 ranged from a 2016 price of $41.26
per barrel of oil and $2.26 per Mcf of natural gas to a 2023 price of $66.33
per barrel of oil and $3.56 per Mcf of natural gas. Commodity prices for this
purpose were held flat after 2023. We did not recognize an impairment charge
during the three months ended March 31, 2017.
It is reasonably possible that the estimate of
undiscounted future net cash flows of our long-lived assets may change in the
future resulting in the need to impair carrying values. The primary factors
that may affect estimates of future net cash flows are (i) commodity futures
prices, (ii) increases or decreases in production and capital costs, (iii)
future reserve volume adjustments, both positive and negative, to proved
reserves and appropriate risk-adjusted probable and possible reserves, (iv)
results of future drilling activities and (v) prevailing market rates of income
and expenses from integrated assets.
Based on economic factors at March 31, 2017, we
determined that undiscounted future cash flows attributable to our North Basin
Bone Spring (“NBBS”) field located in the northern Delaware Basin with a net book
value of approximately $1.2 billion indicated that its carrying amount was
expected to be recovered; however, it may be at risk for impairment if
management’s estimates of future cash flows decline, including as a result of
further declines in projected commodity prices (and the resulting impact of
future cash flows) subsequent to March 31, 2017. We estimate that if the oil
and natural gas prices used in this analysis, and noted above, would have been
approximately 10 percent lower at March 31, 2017 with no other changes in
capital costs, operating costs, price differentials, or reserve performance
curves, we could have recognized a non-cash impairment in that period of
approximately $300 million related to our NBBS field. Other assumptions
such as operating costs, well and reservoir performance, severance and ad
valorem taxes, and operating and development plans would likely change given a
change in oil and natural gas prices. However, we did not estimate the
correlation between these assumptions and any estimated commodity price change,
and these and other assumptions may worsen or partially mitigate some of the
effects of a reduction in commodity prices, including the ultimate impact and
amount of any potential impairment charge. As a result, we are unable to
predict with certainty whether or not a decline in commodity prices alone will
cause us to recognize an impairment charge in a particular field or the
magnitude of any such impairment charge. We additionally note that there may be
changes to both drilling and completion designs that affect the volume curves,
capital costs estimates, and the amount of proved undeveloped locations that
can be recorded, each of which will affect management’s estimates of future
cash flows.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the three months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2017
|
|
2016
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in millions, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
48
|
|
$
|
2.91
|
|
$
|
42
|
|
$
|
3.32
|
Less: Operating fee reimbursements
|
|
|
(4)
|
|
|
(0.24)
|
|
|
(4)
|
|
|
(0.34)
|
Non-cash stock-based compensation
|
|
|
12
|
|
|
0.69
|
|
|
16
|
|
|
1.26
|
|
Total general and administrative expenses
|
|
$
|
56
|
|
$
|
3.36
|
|
$
|
54
|
|
$
|
4.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $56 million ($3.36 per Boe) for the three months ended
March 31, 2017
,
an increase of $2 million (4 percent) from $54 million ($4.24 per Boe) for
2016
. The
increase in cash general and administrative expenses was primarily a result of
increased cash compensation, while the decrease in non-cash stock-based compensation
was primarily a result of recording forfeitures as they occur rather than
recording forfeiture estimates per the adoption of Accounting Standards Update
(“ASU”) No. 2016-09 on January 1, 2017.
The decrease in total general and administrative expenses per Boe
was primarily due to increased production period over period, partially offset
by the increase in general and administrative costs noted above.
We receive fees for the operation of
jointly-owned oil and natural gas properties during the drilling and production
phases and record such reimbursements as reductions of general and
administrative expenses in the consolidated statements of operations. We earned
reimbursements of approximately
$4
million for each of the
three months ended
March 31, 2017 and 2016
.
Gain on derivatives.
The following table sets forth the gain on derivatives for the
three months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Gain on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
266
|
|
$
|
72
|
|
Natural gas derivatives
|
|
|
20
|
|
|
9
|
|
|
Total
|
|
$
|
286
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from (payments on) derivatives for the three
months ended March 31, 2017 and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in millions)
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash receipts from (payments on) derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
31
|
|
$
|
252
|
|
Natural gas derivatives
|
|
|
(3)
|
|
|
7
|
|
|
Total
|
|
$
|
28
|
|
$
|
259
|
|
|
|
|
|
|
|
|
|
Our earnings are affected by the changes in
value of our derivatives portfolio between periods and the related cash
settlements of those derivatives, which could be significant. To the extent the
future commodity price outlook declines between measurement periods, we will
have mark-to-market gains, while to the extent future commodity price outlook
increases between measurement periods, we will have mark-to-market losses. See
Note 7 of the Condensed Notes to Consolidated Financial Statements included in
“Item 1. Consolidated Financial Statements (Unaudited)” for additional
information regarding significant judgments made in classifying financial
instruments in the fair value hierarchy.
Gain on disposition of assets, net.
In February 2017, we closed on our previously announced
divestiture of our ownership interest in ACC. After adjustments for debt and
working capital, we received cash proceeds from the sale of approximately $803
million. After direct transaction costs, we recorded a pre-tax gain on
disposition of assets of approximately $656 million. Our net investment in ACC
at the time of closing was approximately $129 million.
In February 2016, we sold certain assets in the northern
Delaware Basin for estimated proceeds of approximately $294 million, prior to
customary post-closing adjustments of approximately $1 million recorded in the
second quarter of 2016, and recognized a pre-tax gain of approximately $111
million.
Interest expense.
Interest expense was $40 million for the three
months ended
March 31, 2017 as compared to $54
million during 2016. T
he decrease was
due to (i) the early redemption of the $600 million outstanding principal
amount of our 7.0% unsecured senior notes due 2021 during August 2016 and (ii)
the satisfaction and discharge of our obligations under the indenture of the
$600 million outstanding principal amount of our 6.5% unsecured senior notes
due 2022 during December 2016, partially offset by (iii) the issuance of $600
million in aggregate principal amount of 4.375% senior notes due 2025 in
December 2016.
Income tax provisions.
We recorded income tax expense of
$371 million, which includes a discrete income tax benefit of approximately $7
million related to excess tax benefits on stock-based awards, which are now
recorded in the income tax provision due to the adoption of ASU No. 2016-09, and
an income tax benefit of $594 million for the three months ended
March 31, 2017
and 2016, respectively. The change in our income tax provision was primarily due
to income before income taxes during the three months ended
March 31, 2017, as compared to a loss before income taxes
during 2016
. The effective income
tax rates for the three months ended
March 31,
2017
and 2016 were 36.3 percent
and 36.8 percent, respectively.
Capital Commitments, Capital Resources and Liquidity
Capital commitments.
Our primary needs for cash are development, exploration and acquisition
of oil and natural gas assets, midstream joint ventures and other capital
commitments, payment of contractual obligations and working capital
obligations. Funding for these cash needs may be provided by any combination of
internally-generated cash flow, financing under our credit facility, proceeds
from the disposition of assets or alternative financing sources, as discussed
in
“—
Capital resources” below.
Oil and natural gas properties.
Our costs incurred on oil and natural gas
properties, excluding acquisitions, during the
three
months ended
March
31, 2017
and 2016 totaled $393 million
and $253 million, respectively. The increase was primarily due to our increased
drilling and completion activity level during the first three months of 2017 as
compared to 2016. Our intent is to manage our capital spending to be within our
cash flow, excluding unbudgeted acquisitions. The primary reason for the
differences in costs incurred and cash flow expenditures was our issuance of
approximately 1.9 million shares of common stock related to our January 2017
acquisition and timing of payments. Total 2017 expenditures were primarily
funded in part from (i) cash flows from operations, (ii) our issuance of
approximately 1.9 million shares of common stock related to our January 2017
acquisition and to a lesser extent (iii) proceeds from our February 2017
divestiture of ACC.
2017 capital budget.
In February 2017, we announced our updated 2017
capital budget, excluding acquisitions, of approximately $1.8 billion with
expected capital spending to range between $1.6 billion and $1.8 billion.
Approximately 90 percent of capital will be directed to drilling and completion
activity. Our 2017 capital program is expected to continue focusing on extended
length lateral drilling and multi-well pad development. Our 2017 capital
budget, based on our current expectations of commodity prices and costs, is
expected to be within our cash flows. However, if we were to outspend our cash
flows, we believe we could use our (i) cash on hand, (ii) credit facility and
(iii) other financing sources to fund any cash flow deficits. The actual amount
and timing of our expenditures may differ materially from our estimates as a
result of, among other things, actual drilling results, the timing of
expenditures by third parties on projects that we do not operate, the costs of
drilling rigs and other services and equipment, regulatory, technological and
competitive developments, commodity prices, leverage metrics and industry
conditions. In addition, under certain circumstances, we may consider
increasing, decreasing or reallocating our capital spending plans.
Acquisitions.
The
following table reflects o
ur expenditures for
acquisitions of proved and unproved properties for the three months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
127
|
|
$
|
252
|
|
Unproved
|
|
|
306
|
|
|
139
|
|
|
Total property acquisition costs (a)
|
|
$
|
433
|
|
$
|
391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the property
acquisition costs above are budgeted unproved leasehold acreage acquisitions
of $5 million and $16 million for the three months ended March 31, 2017 and
2016, respectively. For the three months ended March 31, 2017, our unbudgeted
acquisitions are primarily comprised of approximately $393 million of
property acquisition costs related to our January 2017 acquisition. For the
three months ended March 31, 2016, our unbudgeted acquisitions are primarily
comprised of approximately $374 million of property acquisition costs related
to our March 2016 acquisition.
|
|
|
|
|
|
|
|
|
|
|
|
|
Contractual obligations.
Our contractual obligations include long-term
debt, cash interest expense on debt, derivative liabilities, asset retirement
obligations, employment agreements with officers, purchase obligations,
operating lease obligations and other obligations. Since December 31, 2016, the
changes in our contractual obligations are not material, other than our
derivative liability position, which decreased by $165 million. See Note 8 of
the Condensed Notes to Consolidated
Financial
Statements included in “Item 1. Consolidated Financial Statements (Unaudited)”
for additional information regarding our long-term debt and “Item 3.
Quantitative and Qualitative Disclosures About Market Risk” for information
regarding the interest on our long-term debt and information on changes in the
fair value of our open derivative obligations during the three months ended
March 31, 2017
.
Off-balance sheet arrangements.
Currently, we do not have any material
off-balance sheet arrangements.
Capital resources.
Our primary sources of liquidity have been
cash flows generated from (i) operating activities, (ii) borrowings under our
credit facility, (iii) proceeds from bond and equity offerings and (iv) asset
dispositions. In February 2017, we announced our updated 2017 capital budget,
excluding acquisitions, of approximately $1.8 billion with expected capital
spending to range between $1.6 billion and $1.8 billion. Approximately 90
percent of capital will be directed to drilling and completion activity. Our
2017 capital program is expected to continue focusing on extended length
lateral drilling and multi-well pad development. Our 2017 capital budget, based
on our current expectations of commodity prices and costs, is expected to be
within our cash flows. However, if we were to outspend our cash flows, we
believe we could use our (i) cash on hand, (ii) credit facility and (iii) other
financing sources to fund any cash flow deficits. The actual amount and timing
of our expenditures may differ materially from our estimates as a result of,
among other things, actual drilling results, the timing of expenditures by
third parties on projects that we do not operate, the costs of drilling rigs
and other services and equipment, regulatory, technological and competitive
developments, commodity prices, leverage metrics and industry conditions. In
addition, under certain circumstances, we may consider increasing, decreasing
or reallocating our capital spending plans.
The following table summarizes our changes in
cash and cash equivalents for the three months ended
March 31, 2017
and 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in millions)
|
|
2017
|
|
2016
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
407
|
|
$
|
370
|
Net cash provided by (used in) investing activities
|
|
|
330
|
|
|
(122)
|
Net cash used in financing activities
|
|
|
(19)
|
|
|
(10)
|
|
Net increase in cash and cash equivalents
|
|
$
|
718
|
|
$
|
238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities.
The increase in operating cash flows during the
three
months ended
March
31, 2017
as compared to the same period in
2016 was
primarily due to (i) an increase in
oil and natural gas revenues of approximately $328 million and (ii) a decrease
in cash interest expense of approximately $14 million, partially offset by (i)
approximately $
28
million from settlements on derivatives during
the three months ended March 31, 2017, as compared to $
259
million
from settlements on derivatives during the comparable period in 2016,
(ii) approximately $27 million of negative variances in
operating assets and liabilities (iii) approximately $25 million increase in
production and ad valorem tax expense and (iv) a decrease in operating cash
flow of approximately $18 million due to cash tax expense of approximately $8
million for the
three
months ended March 31, 2017, as compared to a cash tax
benefit of approximately $10 million during the comparable period in
2016
.
Our net cash provided by operating activities included a
benefit of approximately $2
million and $29
million for the
three
months ended
March 31, 2017
and 2016, respectively, associated with changes in working
capital items. Changes in working capital items adjust for the timing of
receipts and payments of actual cash.
Cash flow from investing activities.
During the three months ended
March 31, 2017
and 2016, we invested approximately $457 million and $380 million,
respectively, for capital expenditures on oil and natural gas properties. Additionally,
we received approximately $
806
million related to proceeds from the
disposition of assets during the three months ended
March 31, 2017,
as compared to $292 million during the comparable period of 2016.
Cash flow from financing
activities.
Net cash used in financing activities was approximately $19
million and $10 million for the
three
months ended March 31, 2017 and 2016, respectively.
At
March 31,
2017,
we had unused commitments on
our credit facility of
$2.5
billion. Our unused lender commitments were
subsequently reduced to $2.0 billion through an amendment to our credit
facility in April 2017 while our borrowing base was increased to $3.0 billion.
Advances on our amended and restated credit
facility bear interest, at our option, based on (i) the prime rate of JPMorgan
Chase Bank (“JPM Prime Rate”) (4.0 percent at
March
31, 2017)
or (ii) the London
Interbank Offered Rate (“LIBOR”). The credit facility’s interest rates vary,
with interest margins ranging from 125 to 225 basis points (LIBOR Rate Loans)
and 25 to 125 basis points (Alternate Base Rate Loans) per annum depending on
the utilization of the borrowing base. We pay commitment fees on the unused
portion of the available commitment ranging from 30.0 to 37.5 basis points per
annum, depending on utilization of the borrowing base. Subject to certain
restrictions, with respect to our public debt ratings, the collateral securing
the facility may be released.
In conducting our business, we may utilize various
financing sources, including the issuance of (i) fixed and floating rate debt,
(ii) convertible securities, (iii) preferred stock, (iv) common stock and (v)
other securities.
Historically, we have demonstrated
our use of the capital markets by issuing common stock and senior unsecured
debt. There are no assurances that we can access the capital markets to obtain
additional funding, if needed, and at cost and terms that are favorable to us.
We
may also sell assets and issue securities in exchange for oil and natural gas
assets or interests in energy companies. Additional securities may be of a
class senior to common stock with respect to such matters as dividends and
liquidation rights and may also have other rights and preferences as determined
from time to time. Utilization of some of these financing sources may require
approval from the lenders under our credit facility.
Liquidity.
Our
principal sources of liquidity are cash on hand and available borrowing
capacity under our credit facility. At
March
31, 2017
, we had approximately $771
million
of cash on hand. Potential uses of our
net cash proceeds from the sale of ACC could include (i) financing possible
future acquisitions, (ii) funding future capital expenditures associated with
our acquisition, exploration and development activities, (iii) retiring or
purchasing outstanding debt and (iv) general corporate purposes.
At March 31, 2017, our commitments from our
bank group were $2.5 billion. During April 2017, we amended our credit facility
to extend the maturity date to May 9, 2022. Additionally, we increased our
borrowing base to $3.0 billion and decreased our commitments from bank groups
to $2.0 billion.
Upon a subsequent
redetermination, there
is no
assurance that our borrowing base will not be reduced, which could affect our
liquidity
.
We may from time to time seek to retire or
purchase our outstanding debt through cash purchases and/or exchanges for other
debt or equity securities, in open market purchases, privately negotiated
transactions or otherwise. Such repurchases or exchanges, if any, will depend
on prevailing market conditions, our liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.
Debt ratings
.
We receive debt credit ratings from S&P Global Ratings
(“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), which are subject
to regular reviews. S&P and Moody’s consider many factors in determining
our ratings including: the industry in which we operate, production growth
opportunities, liquidity, debt levels and asset and reserve mix. A reduction in
our debt ratings could negatively affect our ability to obtain additional
financing or the interest rate, fees and other terms associated with such
additional financing.
A downgrade in our credit ratings could negatively impact
our costs of capital and our ability to effectively execute aspects of our
strategy. Further, a downgrade in our credit ratings could affect our ability
to raise debt in the public debt markets, and the cost of any new debt could be
much higher than our outstanding debt. These and other impacts of a downgrade
in our credit ratings could have a material adverse effect on our business,
financial condition and results of operations.
As of the filing of this Quarterly Report, no changes in
our credit ratings have occurred since March 31, 2017; however, we cannot be
assured that our credit ratings will not be downgraded in the future.
Book capitalization and current ratio
.
Our net book capitalization at
March 31, 2017
was $10.4
billion, consisting of $0.8 billion of cash and
cash equivalents, debt of $
2.7 b
illion and
stockholders’ equity of $
8.5
billion. Our net
book capitalization at December 31, 2016 was $10.2 billion, consisting of $0.1
billion of cash and cash equivalents, debt of $2.7 billion and
stockholders’ equity of $7.6 billion. Our ratio of net debt
to net book capitalization was 19
percent and
26
percent
at
March
31, 2017
and December 31, 2016, respectively.
Our ratio of current assets to current liabilities was 1.73
to 1.0 at
March
31, 2017
as compared to 0.73 to 1.0 at
December 31, 2016.
Inflation and changes in prices.
Our revenues, the value of our assets, and our ability to
obtain bank financing or additional capital on attractive terms have been and
will continue to be affected by changes in commodity prices and the costs to
produce our reserves. Commodity prices are subject to significant fluctuations
that are beyond our ability to control or predict. During the three months
ended
March 31, 2017
, we received an average of $49.08
per Bbl of oil and $3.00
per Mcf of
natural gas before consideration of commodity derivative contracts compared to
$29.90
per Bbl of oil and $1.50
per Mcf of natural gas in the three months ended
March 31, 2016
. Although
certain of our costs are affected by general inflation, inflation does not
normally have a significant effect on our business.
Critical
Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related
condensed notes to consolidated financial statements contain information that
is pertinent to our management’s discussion and analysis of financial condition
and results of operations. Preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
that our management make estimates, judgments and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and the
disclosure of contingent assets and liabilities. However, the accounting
principles used by us generally do not change our reported cash flows or
liquidity. Interpretation of the existing rules must be done and judgments made
on how the specifics of a given rule apply to us.
In management’s opinion, the more significant reporting
areas impacted by management’s judgments and estimates are the choice of
accounting method for oil and natural gas activities, oil and natural gas
reserve estimation, asset retirement obligations, impairment of long-lived
assets, valuation of business combinations, valuation of nonmonetary exchanges,
valuation of financial derivative instruments, valuation of stock-based compensation
and income taxes. Management’s judgments and estimates in these areas are based
on information available from both internal and external sources, including
engineers, geologists and historical experience in similar matters. Actual
results could differ from the estimates as additional information becomes
known.
There have been no material changes in our critical accounting
policies and procedures during the
three
months ended March 31, 2017. See our disclosure of
critical accounting policies in “Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations” and “Item 8. Financial
Statements and Supplementary Data” of our Annual Report on Form 10-K for the
year ended December 31, 2016, filed with the United States Securities and
Exchange Commission (the “SEC”) on February 22, 2017.
Recent
accounting pronouncements.
In
February 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU
No. 2016-02, “Leases (Topic 842),” which supersedes current lease
guidance. The new lease standard requires all leases with a term greater than
one year to be recognized on the balance sheet while maintaining substantially
similar classifications for finance and operating leases. Lease expense
recognition on the income statement will be effectively unchanged. This
guidance is effective for reporting periods beginning after December 15, 2018
and early adoption is permitted. We are evaluating the impact that this new
guidance will have on our consolidated financial statements.
In January 2017, the FASB issued
ASU No. 2017-01, “Business Combinations (Topic 805): Clarifying the Definition
of a Business,” with the objective of adding guidance to assist in evaluating
whether transactions should be accounted for as asset acquisitions or as
business combinations. The guidance provides a screen to determine when an
integrated set of assets and activities is not a business. The screen requires
that when substantially all of the fair value of the acquired assets is
concentrated in a single asset or a group of similar assets, the set is not a
business. If the screen is not met, to be considered a business, the set must
include an input and a substantive process that together significantly
contribute to the ability to create output. This new guidance is effective for
annual periods beginning after December 15, 2017, and early adoption is
allowed. We are evaluating the impact this new guidance will have on our
consolidated financial statements. The new guidance could result in more
acquisitions of oil and natural gas properties being accounted for as asset
acquisitions instead of business combinations.
Item 3. Quantitative and Qualitative Disclosures About
Market Risk
The following market risk disclosures should be read in
conjunction with the quantitative and qualitative disclosures about market risk
contained in our Annual Report on Form 10-K for the year ended December 31,
2016.
We are exposed to
a variety of market risks, including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management
which includes the use of derivative instruments. The following quantitative
and qualitative information is provided about financial instruments to which we
are a party at
March 31, 2017
, and from which we may incur
future gains or losses from changes in market interest rates or commodity
prices and losses from extension of credit. We do not enter into derivative or
other financial instruments for speculative or trading purposes.
Hypothetical changes in interest rates and
commodity prices chosen for the following estimated sensitivity analysis are
considered to be reasonably possible near-term changes generally based on
consideration of past fluctuations for each risk category. However, since it is
not possible to accurately predict future changes in interest rates and
commodity prices, these hypothetical changes may not necessarily be an
indicator of probable future fluctuations.
Credit risk.
We
monitor our risk of loss due to non-performance by counterparties of their
contractual obligations. Our principal exposure to credit risk is through the
sale of our oil and natural gas production, which we market to energy marketing
companies and refineries, and to a lesser extent, our derivative
counterparties. We monitor our exposure to these counterparties primarily by
reviewing credit ratings, financial statements and payment history. We extend
credit terms based on our evaluation of each counterparty’s creditworthiness.
Although we have not generally required our counterparties to provide collateral
to support their obligations to us, we may, if circumstances dictate, require
collateral in the future. In this manner, we could reduce credit risk. Under
the terms of our credit facility, certain events could occur that would cause
the obligations under our credit facility to no longer be secured by our oil
and natural gas properties. In this circumstance, we have certain agreements in
place with our derivative counterparties that would regulate collateral related
to derivative transactions.
We have entered into International Swap Dealers Association
Master Agreements (“ISDA Agreements”) with each of our derivative
counterparties. The terms of the ISDA Agreements provide us and the counterparties
with rights of set-off upon the occurrence of defined acts of default by either
us or a counterparty to a derivative, whereby the party not in default may set
off all derivative liabilities owed to the defaulting party against all
derivative asset receivables from the defaulting party.
See Note 7 of the Condensed Notes to Consolidated Financial
Statements included in “Item 1. Consolidated Financial Statements
(Unaudited)” for additional information regarding our derivative activities.
Commodity price risk
.
We are exposed to market risk as the prices of our
commodities are subject to fluctuations resulting from changes in supply and
demand. To reduce our exposure to changes in the prices of our commodities, we
have entered into, and may in the future enter into, additional commodity price
risk management arrangements for a portion of our oil and natural gas
production. The agreements that we have entered into generally have the effect
of providing us with a fixed price for a portion of our expected future oil and
natural gas production over a fixed period of time. Our commodity price risk
management arrangements are recorded at fair value and thus changes to the
future commodity prices will have an impact on net income. The following table
sets forth the hypothetical impact on the fair value of the commodity price
risk management arrangements from an average increase and decrease in the
commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from
the commodity prices at March 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase of
|
|
|
Decrease of
|
|
|
|
|
|
|
|
|
$5.00 per Bbl and
|
|
|
$5.00 per Bbl and
|
(in millions)
|
|
$0.50 per MMBtu
|
|
|
$0.50 per MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss):
|
|
|
|
|
|
|
Oil derivatives
|
$
|
(253)
|
|
$
|
253
|
|
Natural gas derivatives
|
|
(36)
|
|
|
36
|
|
|
Total
|
$
|
(289)
|
|
$
|
289
|
|
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At
March 31, 2017
, we had (i)
oil price swaps that settle on a monthly basis covering future oil production
from April 1, 2017 through December 31, 2019 and (ii) oil basis swaps covering
our Midland to Cushing basis differential from April 1,
2017
to December 31, 2018.
The average NYMEX oil price for the
three
months ended
March 31, 2017
was $51.95
per Bbl. At
May 1, 2017
,
the NYMEX oil price was
$48.84 per Bbl.
At
March 31, 2017
, we had natural gas price swaps that settle on a monthly
basis covering future natural gas production from
April 1
,
2017
to
December 31,
2018
. The average NYMEX natural gas price for the
three
months ended
March 31, 2017
was
$3.08
per
MMBtu. At
May 1, 2017
, the NYMEX natural gas price was
$3.22
per
MMBtu.
A decrease in the average forward NYMEX oil and natural gas
prices below those at
March 31, 2017
would increase the fair value asset of our commodity
derivative contracts from their recorded balance at
March 31, 2017
. Changes in
the recorded fair value of our commodity derivative contracts are marked to
market through earnings as gains or losses. The potential increase in our fair
value asset would be recorded in earnings as a gain. However, an increase in
the average forward NYMEX oil and natural gas prices above those at
March 31, 2017
would
decrease the fair value asset of our commodity derivative contracts from their
recorded balance at
March 31, 2017
. The potential decrease in our fair value asset would be
recorded in earnings as a loss. We are currently unable to estimate the effects
on the earnings of future periods resulting from changes in the market value of
our commodity derivative contracts.
The fair value of our derivative instruments is determined
based on our valuation models. We did not change our valuation method for our
derivative instruments during the three months ended
March 31, 2017
. The
following table reconciles the changes that occurred in the fair values of our
derivative instruments during the three months ended
March 31, 2017
:
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Commodity Derivative
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Instruments
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(in millions)
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Net Assets (Liabilities) (a)
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Fair value of contracts outstanding at December 31, 2016
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$
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(174)
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Changes in fair values (b)
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286
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Contract maturities
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(28)
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Fair value of contracts outstanding at March 31, 2017
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$
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84
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(a)
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Represents the fair values of open derivative contracts subject to
market risk.
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(b)
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At inception, new derivative contracts entered into by us have no
intrinsic value.
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See Note
7 of
the Condensed Notes to Consolidated Financial Statements included in “Item 1.
Consolidated Financial Statements (Unaudited)” for additional information
regarding our derivative instruments.
Interest rate risk
.
Our exposure to changes in interest rates
relates primarily to debt obligations. We manage our interest rate exposure by
limiting our variable-rate debt to a certain percentage of total capitalization
and by monitoring the effects of market changes in interest rates. To reduce
our exposure to changes in interest rates we may, in the future, enter into interest
rate risk management arrangements for a portion of our outstanding debt. The
agreements that we have entered into generally have the effect of providing us
with a fixed interest rate for a portion of our variable rate debt. We may
utilize interest rate derivatives to alter interest rate exposure in an attempt
to reduce interest rate expense related to existing debt issues. Interest rate
derivatives are used solely to modify interest rate exposure and not to modify
the overall leverage of the debt portfolio. We are exposed to changes in
interest rates as a result of our credit facility, and the terms of our credit
facility require us to pay higher interest rate margins as we utilize a larger
percentage of our borrowing base.
We had no indebtedness outstanding under our credit
facility at
March 31, 2017
.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
.
As required by
Rule 13a-15(b) of the Exchange Act, we have evaluated, under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, the effectiveness
of the design and operation of our disclosure controls and procedures (as
defined in Rule 13a-15(e) under the Exchange Act) as of the end of the
period covered by this Quarterly Report. Our disclosure controls and procedures
are designed to provide reasonable assurance that the information required to
be disclosed by us in reports that we file or submit under the Exchange Act is
accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate, to allow
timely decisions regarding required disclosure and is recorded, processed,
summarized and reported within the time periods specified in the rules and
forms of the SEC. Based upon the evaluation, our principal executive officer
and principal financial officer have concluded that our disclosure controls and
procedures were effective at
March 31, 2017
at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
.
There have been
no changes in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter
that have materially affected or are reasonably likely to materially affect our
internal control over financial reporting.