Concho
Resources Inc.
|
Consolidated Balance Sheets
|
Unaudited
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(in thousands, except share and per share amounts)
|
|
|
2016
|
|
|
2015
|
Assets
|
Current assets:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
466,821
|
|
$
|
228,550
|
|
Accounts receivable, net of allowance for doubtful
accounts:
|
|
|
|
|
|
|
|
|
Oil and natural gas
|
|
|
191,698
|
|
|
203,972
|
|
|
Joint operations and other
|
|
|
168,545
|
|
|
190,608
|
|
Derivative instruments
|
|
|
527,769
|
|
|
652,498
|
|
Prepaid costs and other
|
|
|
33,734
|
|
|
38,922
|
|
|
|
Total current assets
|
|
|
1,388,567
|
|
|
1,314,550
|
Property and equipment:
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
16,217,487
|
|
|
15,846,307
|
|
Accumulated depletion and depreciation
|
|
|
(6,830,070)
|
|
|
(5,047,810)
|
|
|
Total oil and natural gas properties, net
|
|
|
9,387,417
|
|
|
10,798,497
|
|
Other property and equipment, net
|
|
|
182,473
|
|
|
178,450
|
|
|
Total property and equipment, net
|
|
|
9,569,890
|
|
|
10,976,947
|
Deferred loan costs, net
|
|
|
14,416
|
|
|
15,585
|
Intangible asset - operating rights, net
|
|
|
25,328
|
|
|
25,693
|
Inventory
|
|
|
19,311
|
|
|
19,118
|
Noncurrent derivative instruments
|
|
|
114,072
|
|
|
167,038
|
Other assets
|
|
|
154,937
|
|
|
122,945
|
|
Total assets
|
|
$
|
11,286,521
|
|
$
|
12,641,876
|
Liabilities and Stockholders’ Equity
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable - trade
|
|
$
|
20,751
|
|
$
|
13,200
|
|
Revenue payable
|
|
|
123,338
|
|
|
169,787
|
|
Accrued and prepaid drilling costs
|
|
|
267,235
|
|
|
228,523
|
|
Other current liabilities
|
|
|
193,624
|
|
|
184,910
|
|
|
|
Total current liabilities
|
|
|
604,948
|
|
|
596,420
|
Long-term debt
|
|
|
3,332,854
|
|
|
3,332,188
|
Deferred income taxes
|
|
|
1,046,796
|
|
|
1,630,373
|
Noncurrent derivative instruments
|
|
|
393
|
|
|
-
|
Asset retirement obligations and other long-term
liabilities
|
|
|
142,758
|
|
|
140,344
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000
authorized; 131,973,782 and
|
|
|
|
|
|
|
|
|
129,444,042 shares issued at March 31, 2016 and December
31, 2015, respectively
|
|
|
132
|
|
|
129
|
|
Additional paid-in capital
|
|
|
4,874,546
|
|
|
4,628,390
|
|
Retained earnings
|
|
|
1,325,161
|
|
|
2,345,641
|
|
Treasury stock, at cost; 409,076 and 306,061 shares at
March 31, 2016 and
|
|
|
|
|
|
|
|
|
December 31, 2015, respectively
|
|
|
(41,067)
|
|
|
(31,609)
|
|
|
|
Total stockholders’ equity
|
|
|
6,158,772
|
|
|
6,942,551
|
|
Total liabilities and stockholders’ equity
|
|
$
|
11,286,521
|
|
$
|
12,641,876
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
|
Consolidated Statements of Operations
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands, except per share amounts)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Operating revenues:
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
242,154
|
|
$
|
349,584
|
|
Natural gas sales
|
|
|
41,410
|
|
|
63,938
|
|
|
Total operating revenues
|
|
|
283,564
|
|
|
413,522
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
Oil and natural gas production
|
|
|
114,957
|
|
|
125,535
|
|
Exploration and abandonments
|
|
|
22,860
|
|
|
5,755
|
|
Depreciation, depletion and amortization
|
|
|
310,082
|
|
|
267,205
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,712
|
|
|
1,994
|
|
Impairments of long-lived assets
|
|
|
1,524,645
|
|
|
-
|
|
General and administrative (including non-cash stock-based
compensation of $16,022 and
|
|
|
|
|
|
|
|
|
$15,495 for the three months ended March 31, 2016 and
2015, respectively)
|
|
|
53,795
|
|
|
58,801
|
|
Gain on derivatives
|
|
|
(79,842)
|
|
|
(115,340)
|
|
(Gain) loss on disposition of assets, net
|
|
|
(111,066)
|
|
|
39
|
|
|
Total operating costs and expenses
|
|
|
1,837,143
|
|
|
343,989
|
Income (loss) from operations
|
|
|
(1,553,579)
|
|
|
69,533
|
Other income (expense):
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(54,138)
|
|
|
(53,569)
|
|
Other, net
|
|
|
(6,535)
|
|
|
(4,302)
|
|
|
Total other expense
|
|
|
(60,673)
|
|
|
(57,871)
|
Income (loss) before income taxes
|
|
|
(1,614,252)
|
|
|
11,662
|
|
Income tax (expense) benefit
|
|
|
593,772
|
|
|
(4,150)
|
Net income (loss)
|
|
$
|
(1,020,480)
|
|
$
|
7,512
|
Earnings per share:
|
|
|
|
|
|
|
|
Basic net income (loss)
|
|
$
|
(7.95)
|
|
$
|
0.07
|
|
Diluted net income (loss)
|
|
$
|
(7.95)
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these consolidated financial statements.
|
Concho
Resources Inc.
|
Consolidated Statement of Stockholders’
Equity
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
Issued
|
|
|
Paid-in
|
|
|
Retained
|
|
Treasury Stock
|
|
Stockholders’
|
(in thousands)
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
Shares
|
|
|
Amount
|
|
|
Equity
|
BALANCE AT DECEMBER 31, 2015
|
|
129,444
|
|
$
|
129
|
|
$
|
4,628,390
|
|
$
|
2,345,641
|
|
306
|
|
$
|
(31,609)
|
|
$
|
6,942,551
|
|
Net loss
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(1,020,480)
|
|
-
|
|
|
-
|
|
|
(1,020,480)
|
|
Common stock issued in business combination
|
|
2,214
|
|
|
2
|
|
|
230,826
|
|
|
-
|
|
-
|
|
|
-
|
|
|
230,828
|
|
Stock options exercised
|
|
1
|
|
|
1
|
|
|
10
|
|
|
-
|
|
-
|
|
|
-
|
|
|
11
|
|
Incentive plan activity
|
|
336
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
Cancellation of restricted stock
|
|
(21)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
-
|
|
|
-
|
|
|
-
|
|
Stock-based compensation
|
|
-
|
|
|
-
|
|
|
16,022
|
|
|
-
|
|
-
|
|
|
-
|
|
|
16,022
|
|
Tax deficiency related to stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation
|
|
-
|
|
|
-
|
|
|
(702)
|
|
|
-
|
|
-
|
|
|
-
|
|
|
(702)
|
|
Purchase of treasury stock
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
103
|
|
|
(9,458)
|
|
|
(9,458)
|
BALANCE AT MARCH 31, 2016
|
|
131,974
|
|
$
|
132
|
|
$
|
4,874,546
|
|
$
|
1,325,161
|
|
409
|
|
$
|
(41,067)
|
|
$
|
6,158,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
Concho
Resources Inc.
|
Consolidated Statements of Cash Flows
|
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(1,020,480)
|
|
$
|
7,512
|
|
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
310,082
|
|
|
267,205
|
|
|
Accretion of discount on asset retirement obligations
|
|
|
1,712
|
|
|
1,994
|
|
|
Impairments of long-lived assets
|
|
|
1,524,645
|
|
|
-
|
|
|
Exploration and abandonments, including dry holes
|
|
|
20,652
|
|
|
2,700
|
|
|
Non-cash stock-based compensation expense
|
|
|
16,022
|
|
|
15,495
|
|
|
Deferred income taxes
|
|
|
(583,577)
|
|
|
(11,031)
|
|
|
(Gain) loss on disposition of assets, net
|
|
|
(111,066)
|
|
|
39
|
|
|
Gain on derivatives
|
|
|
(79,842)
|
|
|
(115,340)
|
|
|
Other non-cash items
|
|
|
5,282
|
|
|
2,612
|
|
Changes in operating assets and liabilities, net of
acquisitions and dispositions:
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
68,701
|
|
|
35,731
|
|
|
|
Prepaid costs and other
|
|
|
(4,764)
|
|
|
649
|
|
|
|
Inventory
|
|
|
(219)
|
|
|
3
|
|
|
|
Accounts payable
|
|
|
7,536
|
|
|
3,119
|
|
|
|
Revenue payable
|
|
|
(44,335)
|
|
|
(77,105)
|
|
|
|
Other current liabilities
|
|
|
1,926
|
|
|
(7,334)
|
|
|
|
|
Net cash provided by operating activities
|
|
|
112,275
|
|
|
126,249
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties
|
|
|
(379,799)
|
|
|
(790,773)
|
|
Additions to property, equipment and other assets
|
|
|
(8,999)
|
|
|
(8,147)
|
|
Proceeds from the disposition of assets
|
|
|
292,013
|
|
|
-
|
|
Contributions to equity method investments
|
|
|
(25,000)
|
|
|
(20,000)
|
|
Net settlements received from derivatives
|
|
|
257,930
|
|
|
167,156
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
|
136,145
|
|
|
(651,764)
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
Proceeds from issuance of debt
|
|
|
-
|
|
|
739,000
|
|
Payments of debt
|
|
|
-
|
|
|
(878,500)
|
|
Exercise of stock options
|
|
|
11
|
|
|
57
|
|
Excess tax benefit (deficiency) from stock-based
compensation
|
|
|
(702)
|
|
|
464
|
|
Net proceeds from issuance of common stock
|
|
|
-
|
|
|
741,184
|
|
Purchase of treasury stock
|
|
|
(9,458)
|
|
|
(3,151)
|
|
Decrease in bank overdrafts
|
|
|
-
|
|
|
(73,539)
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(10,149)
|
|
|
525,515
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
238,271
|
|
|
-
|
Cash and cash equivalents at beginning of period
|
|
|
228,550
|
|
|
21
|
Cash and cash equivalents at end of period
|
|
$
|
466,821
|
|
$
|
21
|
NON-CASH INVESTING AND FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
Issuance of common stock for a business combination
|
|
$
|
230,828
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these consolidated financial statements.
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
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 2016 presentation. These reclassifications had no impact on
net income (loss), total stockholders’ equity or 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 derivative financial instruments, fair value of
business combinations, fair value of nonmonetary exchanges, fair value of
stock-based compensation 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, 2015 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 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, 2015.
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. At
March 31, 2016, the Company had approximately $145.8 million of restricted cash
in an account held by a trustee in connection with a tax-free exchange transaction.
During April 2016, the cash amount was transferred to the Company. 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.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Equity method investments.
The Company owns a 50 percent membership interest in a midstream
joint venture, Alpha Crude Connector, LLC (“ACC”), to construct a crude oil gathering
and transportation system in the northern Delaware Basin. The Company has the
option to purchase the membership interest of the other investor in ACC. This
purchase option becomes exercisable three months after the completion date of
the pipeline and remains exercisable for a period of twelve months. The Company
expects the option to become exercisable during the third quarter of 2016. The
Company accounts 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 $122.9 million and $98.9 million at March
31, 2016 and December 31, 2015, respectively, and is included in other assets
in the Company’s consolidated balance sheet. The equity loss for the three
months ended March 31, 2016 and 2015 was approximately $1.0 million and $0.8
million, respectively, and is included in other expense in the Company’s
consolidated statement of operations. During the three months ended March 31, 2015,
the Company recorded $0.6 million of capitalized interest on its investment in
ACC. ACC commenced partial operations in late 2015. The Company expects the
system to be fully operational during 2016.
During 2015, the Company purchased a 25 percent membership
interest in an entity, which is constructing a crude oil gathering and
transportation system in the southern Delaware Basin. The system is expected to
be completed and operational during 2016. The Company accounts for its
investment under the equity method of accounting for investments in
unconsolidated affiliates. The Company’s net investment was approximately $18.9
million and $20.8 million at March 31, 2016 and December 31, 2015,
respectively, and is included in other assets in the Company’s consolidated
balance sheet. The equity loss for the three months ended March 31, 2016 was
approximately $1.9 million.
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 and records such reimbursements as
reductions of general and administrative expense. Such fees totaled
approximately $6.5 million and $6.4 million for the three months ended
March 31, 2016 and 2015, respectively.
Recent
accounting pronouncements.
In May
2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting
Standards Update (“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.
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 2014-09 by one
year. That new standard is now effective for annual reporting periods beginning
after December 15, 2017. An entity can apply ASU 2014-09 using either a full
retrospective method, meaning the standard is applied to all of the periods
presented, or a modified retrospective method, meaning the cumulative effect of
initially applying the standard is recognized in the most current period
presented in the financial statements. The Company is evaluating the impact
that this new guidance will have 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 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
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
and early adoption is permitted. The Company is
evaluating the impact that this new guidance will have on its consolidated
financial statements.
In March 2016, the FASB issued ASU
No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements
to Employee Share-based Payment Accounting,” which changes the accounting and
presentation for share-based payment arrangements in the following areas: (i) recognition
in the statement of operations of excess tax benefits and deficiencies; (ii)
cash flow presentation of excess tax benefits and deficiencies; (iii) minimum
statutory withholding thresholds and the classification on the cash flow
statement of the withheld amounts; and (iv) an accounting policy election to
recognize forfeitures as they occur. This guidance is effective for reporting
periods beginning after December 15, 2016 and early adoption is permitted. The
Company is evaluating the impact that this new guidance will have on its
consolidated financial statements.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
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 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 16
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, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
(in thousands)
|
|
|
March 31, 2016
|
|
|
|
|
|
|
|
|
Beginning capitalized exploratory well costs
|
|
|
|
|
$
|
116,198
|
|
Additions to exploratory well costs pending the determination of
proved reserves
|
|
|
|
|
|
84,895
|
|
Reclassifications due to determination of proved reserves
|
|
|
|
|
|
(45,436)
|
|
Disposition of wells
|
|
|
|
|
|
(17,339)
|
Ending capitalized exploratory well costs
|
|
|
|
|
$
|
138,318
|
|
|
|
|
|
|
|
|
The
following table provides an aging at March 31, 2016 and December 31, 2015 of
capitalized exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(dollars in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
Capitalized exploratory well costs that have been
capitalized for a period of one year or less
|
|
$
|
125,542
|
|
$
|
98,764
|
Capitalized exploratory well costs that have been
capitalized for a period greater than one year
|
|
|
12,776
|
|
|
17,434
|
|
Total capitalized exploratory well costs
|
|
$
|
138,318
|
|
$
|
116,198
|
Number of projects with exploratory well costs that have
been capitalized for a period greater
|
|
|
|
|
|
|
|
than one year
|
|
|
8
|
|
|
8
|
|
|
|
|
|
|
|
|
Delaware Basin project.
At
March 31,
2016
, the Company had approximately $1.4 million of
suspended well costs greater than one year recorded for a well that was initially
drilled to monitor nearby wells and is also being used to determine the
productivity potential of additional zones. At March 31, 2016, the Company also
had approximately $6.0 million of suspended well costs greater than one year
recorded for a well spud in late 2014 that tested multiple zones. Currently, the
Company is evaluating results in the area to determine the most suitable
lateral zone in which to complete. Both wells completed drilling in 2014.
Projects operated by others.
At
March 31, 2016
, the Company had approximately $5.0 million of suspended
well costs greater than one year recorded for five wells that are operated by
others and waiting on completion. Two of these wells, with
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
suspended
well costs totaling approximately $3.5 million, completed drilling in 2012 and
are expected to be completed in 2016. The remaining three wells completed
drilling in 2014 and are waiting on completion.
Texas Permian project.
At
March 31, 2016
, the Company had approximately $0.3 million of suspended
well costs recorded for a well that was initially drilled to monitor nearby pad
wells. These costs became greater than one year old during the three months
ended March 31, 2016.
Note 4.
Acquisitions and divestitures
Asset acquisition.
In
March 2016, the Company completed an acquisition of 80 percent of a third-party
seller’s interest in certain oil and natural gas properties and related assets
in the southern Delaware Basin. As consideration for the acquisition, the
Company issued to the seller approximately 2.2 million shares of common stock
with an approximate value of $230.8 million, $146.2 million in cash and $40.0
million to carry a portion of the seller’s future development costs in these
properties.
Asset divestiture.
In February 2016, the Company sold certain assets in the northern Delaware
Basin for estimated proceeds of approximately $294.1 million, subject to
customary post-closing adjustments, and recognized a pre-tax gain of
approximately $111.1 million.
Note 5.
Asset
retirement obligations
The Company
’
s asset retirement obligations primarily relate to the
future plugging and abandonment of wells and facilities.
The following table summarizes the
Company
’
s asset retirement obligation
activity
during the three months ended March 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
(in thousands)
|
|
|
March 31, 2016
|
|
|
|
|
|
|
|
|
Asset retirement obligations, beginning of period
|
|
|
|
|
$
|
119,945
|
|
Liabilities incurred from new wells
|
|
|
|
|
|
460
|
|
Liabilities assumed in acquisitions
|
|
|
|
|
|
902
|
|
Accretion expense
|
|
|
|
|
|
1,712
|
|
Disposition of wells
|
|
|
|
|
|
(507)
|
|
Liabilities settled upon plugging and abandoning wells
|
|
|
|
|
|
(464)
|
Asset retirement obligations, end of period
|
|
|
|
|
$
|
122,048
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 6.
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.
A summary of
the Company’s activity for the three months ended March 31, 2016 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
|
|
Stock
|
|
Performance
|
|
|
|
|
Stock
|
|
Options
|
|
Units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
1,199,647
|
|
|
42,901
|
|
|
315,755
|
|
|
Awards granted (a)
|
|
|
155,706
|
|
|
-
|
|
|
161,361
|
|
|
Options exercised
|
|
|
-
|
|
|
(824)
|
|
|
-
|
|
|
Awards cancelled / forfeited
|
|
|
(20,884)
|
|
|
-
|
|
|
(2,909)
|
|
|
Lapse of restrictions
|
|
|
(124,629)
|
|
|
-
|
|
|
-
|
|
Outstanding at March 31, 2016
|
|
1,209,840
|
|
42,077
|
|
474,207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Weighted average grant date fair value per share
|
|
$
|
91.19
|
|
$
|
-
|
|
$
|
114.81
|
|
|
|
|
|
|
|
|
|
|
|
|
The
Company used the following assumptions to estimate the fair value of
performance unit awards granted during the three months ended March 31, 2016:
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31, 2016
|
|
|
|
|
|
|
Risk-free interest rate
|
|
1.31%
|
Range of volatilities
|
|
31.6% - 59.0%
|
|
|
|
|
|
|
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, 2016:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2016
|
|
$
|
44,810
|
2017
|
|
|
37,003
|
2018
|
|
|
14,541
|
2019
|
|
|
1,102
|
2020
|
|
|
14
|
|
Total
|
|
$
|
97,470
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 7.
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, 2016
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, 2016
and December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2016
|
|
December 31, 2015
|
|
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
(in thousands)
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
641,841
|
|
$
|
641,841
|
|
$
|
819,536
|
|
$
|
819,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
$
|
393
|
|
$
|
393
|
|
$
|
-
|
|
$
|
-
|
|
|
$600 million 7.0% senior notes due 2021 (a)
|
|
$
|
592,729
|
|
$
|
606,000
|
|
$
|
592,414
|
|
$
|
595,500
|
|
|
$600 million 6.5% senior notes due 2022 (a)
|
|
$
|
591,834
|
|
$
|
606,000
|
|
$
|
591,549
|
|
$
|
579,000
|
|
|
$600 million 5.5% senior notes due 2022 (a)
|
|
$
|
593,117
|
|
$
|
589,500
|
|
$
|
592,899
|
|
$
|
553,500
|
|
|
$1,550 million 5.5% senior notes due 2023 (a)
|
|
$
|
1,555,174
|
|
$
|
1,542,875
|
|
$
|
1,555,326
|
|
$
|
1,453,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2016
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, 2016
and
December 31, 2015. The Company nets the fair value of derivative instruments by
counterparty in the Company’s consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 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 thousands)
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Fair Value
|
|
|
Sheet
|
|
|
Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
-
|
|
$
|
551,755
|
|
$
|
-
|
|
$
|
551,755
|
|
$
|
(23,986)
|
|
$
|
527,769
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
121,559
|
|
|
-
|
|
|
121,559
|
|
|
(7,487)
|
|
|
114,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(23,986)
|
|
|
-
|
|
|
(23,986)
|
|
|
23,986
|
|
|
-
|
|
|
Noncurrent:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
|
-
|
|
|
(7,880)
|
|
|
-
|
|
|
(7,880)
|
|
|
7,487
|
|
|
(393)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative instruments
|
|
$
|
-
|
|
$
|
641,448
|
|
$
|
-
|
|
$
|
641,448
|
|
$
|
-
|
|
$
|
641,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
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December 31, 2015
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Fair Value Measurements Using
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Net
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Quoted Prices
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Gross
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Fair Value
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in Active
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Significant
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Amounts
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Presented
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Markets for
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Other
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Significant
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Offset in the
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in the
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Identical
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Observable
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Unobservable
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Consolidated
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Consolidated
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Assets
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Inputs
|
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Inputs
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Total
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Balance
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Balance
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(in thousands)
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(Level 1)
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(Level 2)
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(Level 3)
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Fair Value
|
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Sheet
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Sheet
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Assets:
|
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Current:
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Commodity derivatives
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$
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-
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$
|
684,029
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$
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-
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$
|
684,029
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|
$
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(31,531)
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$
|
652,498
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Noncurrent:
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Commodity derivatives
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-
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175,267
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|
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-
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175,267
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(8,229)
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|
167,038
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Liabilities:
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Current:
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Commodity derivatives
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-
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|
(31,531)
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-
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|
(31,531)
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31,531
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-
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Noncurrent:
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Commodity derivatives
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-
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|
(8,229)
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-
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|
(8,229)
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|
8,229
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|
|
-
|
|
|
|
|
|
|
|
|
|
|
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|
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Net derivative instruments
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|
$
|
-
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$
|
819,536
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|
$
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-
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$
|
819,536
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$
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-
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|
$
|
819,536
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|
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Concentrations
of credit risk.
At
March 31, 2016
,
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 8 for additional
information regarding the Company’s derivative activities and counterparties.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
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 its
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 or by individual well for those
wells not constituting part of a 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 its 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) proved reserves and risk-adjusted
probable and possible reserves, and (vii) other sources of income and expenses
from integrated assets.
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.
As a result of the carrying amount of certain of the
Company’s long-lived assets being less than their expected undiscounted future
net cash flows, the Company recognized a non-cash charge against earnings for
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:
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Estimated
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Carrying
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Fair Value
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Impairment
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(in thousands)
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Amount
|
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(Level 3)
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Expense
|
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|
March 2016
|
|
$
|
3,437,612
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|
$
|
1,912,967
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|
$
|
1,524,645
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It
is reasonably possible that the estimate of undiscounted future net cash flows
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, (ii) increases or decreases in production and
capital costs, (iii) future reserve 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.
Based on the factors above as of
March 31, 2016
, the Company
determined that undiscounted future cash flows attributable to a certain
depletion group indicated that the carrying amount was expected to be
recovered; however, it may be at risk for impairment if management’s estimates
of future cash flows further decline.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 8.
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 statements of operations as
they occur.
The following
table summarizes the gain reported in earnings related to the commodity
derivative instruments for the three months ended
March 31, 2016
and 2015:
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|
Three Months Ended
|
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|
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March 31,
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(in thousands)
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|
|
2016
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|
|
2015
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|
|
|
|
|
|
|
|
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|
|
Gain on derivatives:
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
71,140
|
|
$
|
110,280
|
|
|
Natural gas derivatives
|
|
|
8,702
|
|
|
5,060
|
|
|
|
Total
|
|
$
|
79,842
|
|
$
|
115,340
|
|
|
|
|
|
|
|
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|
|
The following table
represents the Company’s net cash receipts from derivatives for the three
months ended March 31, 2016 and 2015:
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|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
March 31,
|
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
|
Oil derivatives
|
|
$
|
251,127
|
|
$
|
160,186
|
|
|
Natural gas derivatives
|
|
|
6,803
|
|
|
6,970
|
|
|
|
Total
|
|
$
|
257,930
|
|
$
|
167,156
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Commodity derivative
contracts at March 31, 2016.
The following table sets forth the
Company’s outstanding derivative contracts at
March 31, 2016
. When
aggregating multiple contracts, the weighted average contract price is disclosed.
All of the Company’s derivative contracts at
March
31, 2016 are expected to settle by December 31, 2017.
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
|
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Total
|
Oil Swaps: (a)
|
|
|
|
|
|
|
|
|
|
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
5,985,000
|
|
5,460,000
|
|
5,054,000
|
|
16,499,000
|
|
|
Price per Bbl
|
|
|
$
|
73.38
|
$
|
74.21
|
$
|
59.38
|
$
|
69.37
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
4,594,000
|
|
4,358,000
|
|
3,825,000
|
|
3,825,000
|
|
16,602,000
|
|
|
Price per Bbl
|
$
|
60.61
|
$
|
60.97
|
$
|
51.97
|
$
|
51.97
|
$
|
56.72
|
Oil Basis Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
|
|
5,914,000
|
|
5,520,000
|
|
5,060,000
|
|
16,494,000
|
|
|
Price per Bbl
|
|
|
$
|
(1.46)
|
$
|
(1.46)
|
$
|
(1.48)
|
$
|
(1.47)
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
4,140,000
|
|
4,064,000
|
|
3,036,000
|
|
3,036,000
|
|
14,276,000
|
|
|
Price per Bbl
|
$
|
(1.24)
|
$
|
(1.27)
|
$
|
(0.43)
|
$
|
(0.43)
|
$
|
(0.90)
|
Natural Gas Swaps: (c)
|
|
|
|
|
|
|
|
|
|
|
|
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
|
7,280,000
|
|
7,360,000
|
|
7,360,000
|
|
22,000,000
|
|
|
Price per MMBtu
|
|
|
$
|
3.02
|
$
|
3.02
|
$
|
3.02
|
$
|
3.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 revolving 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.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
At March 31, 2016, the Company had a net asset position of
$641.4 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 $106.7 million, $100.2 million, $59.1 million and $56.0 million
with Barclays Bank PLC,
J.P. Morgan
Chase Bank, Wells Fargo Bank, N.A. and Societe Generale, respectively.
Note 9.
Debt
The Company’s
debt consisted of the following at March 31, 2016 and December 31, 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Credit facility
|
|
$
|
-
|
|
$
|
-
|
7.0% unsecured senior notes due 2021
|
|
|
600,000
|
|
|
600,000
|
6.5% unsecured senior notes due 2022
|
|
|
600,000
|
|
|
600,000
|
5.5% unsecured senior notes due 2022
|
|
|
600,000
|
|
|
600,000
|
5.5% unsecured senior notes due 2023
|
|
|
1,550,000
|
|
|
1,550,000
|
Unamortized original issue premium
|
|
|
24,362
|
|
|
25,073
|
Deferred loan costs, net
|
|
|
(41,508)
|
|
|
(42,885)
|
|
Less: current portion
|
|
|
-
|
|
|
-
|
|
|
Total long-term debt
|
|
$
|
3,332,854
|
|
$
|
3,332,188
|
|
|
|
|
|
|
|
|
|
Credit
facility.
The
Company’s credit facility, as amended and restated, has a maturity date of May
9, 2019. In April 2016, the Company completed its annual borrowing base review
where it maintained its $2.5 billion in commitments from its bank group until the
Company’s next scheduled borrowing base redetermination in May 2017. The
Company’s current borrowing base is $2.8 billion, which is a reduction from its
previous borrowing base of $3.25 billion.
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 14.
At
March 31, 2016
, 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, 2016 were as follows:
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
Remaining 2016
|
|
$
|
|
-
|
2017
|
|
|
|
-
|
2018
|
|
|
|
-
|
2019
|
|
|
|
-
|
2020
|
|
|
|
-
|
2021
|
|
|
|
600,000
|
Thereafter
|
|
|
|
2,750,000
|
|
Total
|
$
|
|
3,350,000
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Interest expense.
The following
amounts have been incurred and charged to interest expense for the
three
months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Cash payments for interest
|
|
$
|
42,490
|
|
$
|
46,007
|
Amortization of original issue premium
|
|
|
(711)
|
|
|
(673)
|
Amortization of deferred loan origination costs
|
|
|
2,546
|
|
|
2,463
|
Accretion expense
|
|
|
486
|
|
|
-
|
Net changes in accruals
|
|
|
9,579
|
|
|
6,982
|
|
Interest costs incurred
|
|
|
54,390
|
|
|
54,779
|
Less: capitalized interest
|
|
|
(252)
|
|
|
(1,210)
|
|
Total interest expense
|
|
$
|
54,138
|
|
$
|
53,569
|
|
|
|
|
|
|
|
|
|
|
|
Note 10.
Commitments
and contingencies
Severance agreements.
The Company has
entered into severance and change in control agreements with all of its
officers. The current annual salaries for the Company’s officers covered under
such agreements total approximately $8.4 million.
Indemnifications
.
The Company has agreed to indemnify its
directors and officers with respect to claims and damages arising from certain
acts or omissions taken in such capacity.
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, 2016
and December 31, 2015
, the Company had $13.4 million 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, 2016
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 daywork drilling contracts, water commitment agreements,
throughput volume delivery commitments and power commitments.
The following table summarizes the
Company’s commitments at
March 31, 2016
:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2016
|
|
$
|
39,165
|
2017
|
|
|
24,191
|
2018
|
|
|
64,105
|
2019
|
|
|
17,635
|
2020
|
|
|
11,038
|
2021
|
|
|
7,297
|
Thereafter
|
|
|
37,514
|
|
Total
|
$
|
200,945
|
|
|
|
|
|
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, 2016
and 2015
were approximately $2.0 million and $1.9 million, respectively.
Future
minimum lease commitments under non-cancellable operating leases at
March 31, 2016
were as
follows:
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
Remaining 2016
|
|
$
|
6,211
|
2017
|
|
|
8,313
|
2018
|
|
|
7,530
|
2019
|
|
|
6,059
|
2020
|
|
|
4,780
|
2021
|
|
|
4,097
|
Thereafter
|
|
|
994
|
|
Total
|
$
|
37,984
|
|
|
|
|
|
Note 11.
Income taxes
The effective income tax rates were 36.8 percent
and 35.6 percent for the three months ended
March 31, 2016
and 2015,
respectively. Total income tax expense (benefit) for the three months ended
March 31, 2016
and 2015 differed from amounts computed by applying the United States federal
statutory tax rates to pre-tax income (loss) due primarily to state taxes and
the impact of permanent differences between book and taxable income.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 12.
Related
party transactions
The
following table summarizes amounts paid to and received from related parties
and reported in the Company’s consolidated statements of operations for the
periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid to a partnership in which a director has an ownership
interest (a)
|
|
$
|
1,145
|
|
$
|
1,694
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid to a director and certain officers of the Company (b)
|
|
$
|
160
|
|
$
|
523
|
|
|
|
|
|
|
|
|
|
|
|
Amounts received from certain officers of the Company (c)
|
|
$
|
16
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Amounts include royalties on
certain properties paid to a partnership in which a director of the Company is
the general partner and owns a 3.5 percent partnership interest.
(b)
Amounts include revenue
interests, overriding royalty interests and net profits interests in properties
owned by the Company made to a director and certain officers (or affiliated
entities). Amounts also include payments for lease bonuses to an affiliated
entity of an officer.
(c)
Amounts include payments to the
Company as a result of activity on oil and natural gas properties in which certain
officers (or affiliated entities) have an interest.
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 13.
Net income (loss) per share
The Company uses the two-class method of calculating net
income (loss) per share because certain of the Company’s unvested share-based
awards qualify as participating securities.
The
following table reconciles the Company’s net income (loss) from operations and
income (loss) attributable to common stockholders to the basic and diluted
earnings used to determine the Company’s net income (loss) per share amounts for
the
three
months ended
March 31, 2016
and 2015, respectively, under the two-class method:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in thousands, except per share amounts)
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Net income (loss) as reported
|
$
|
(1,020,480)
|
|
$
|
7,512
|
Participating basic earnings (a)
|
|
-
|
|
|
(74)
|
|
Basic income (loss) attributable to common stockholders
|
|
(1,020,480)
|
|
|
7,438
|
Reallocation of participating earnings
|
|
-
|
|
|
-
|
|
Diluted income (loss) attributable to common stockholders
|
$
|
(1,020,480)
|
|
$
|
7,438
|
|
|
|
|
|
|
|
|
Net income (loss) per common share:
|
|
|
|
|
|
|
Basic
|
$
|
(7.95)
|
|
$
|
0.07
|
|
Diluted
|
$
|
(7.95)
|
|
$
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
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, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
Basic
|
|
128,396
|
|
114,047
|
|
|
Dilutive common stock options
|
|
-
|
|
25
|
|
|
Dilutive performance units
|
|
-
|
|
411
|
|
Diluted
|
|
128,396
|
|
114,483
|
|
|
|
|
|
|
|
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
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
will be between zero and 300 percent of the performance
units granted depending on the Company’s performance at the end of the
performance period.
Note 14.
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 9 for a summary of
the Company’s senior notes. In accordance with practices accepted by the United
States Securities and Exchange Commission (“SEC”), 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, 2016 and
December 31, 2015
,
condensed consolidating statements of operations for the
three
months ended
March 31, 2016 and 2015
and condensed
consolidating statements of cash flows for the
three
months ended
March 31, 2016 and 2015,
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, 2016
Unaudited
Condensed
Consolidating Balance Sheet
|
March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
8,741,696
|
|
$
|
927,203
|
|
$
|
(9,668,899)
|
|
$
|
-
|
Other current assets
|
|
|
607,022
|
|
|
781,545
|
|
|
-
|
|
|
1,388,567
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
9,387,417
|
|
|
-
|
|
|
9,387,417
|
Property and equipment, net
|
|
|
-
|
|
|
182,473
|
|
|
-
|
|
|
182,473
|
Investment in subsidiaries
|
|
|
2,058,208
|
|
|
-
|
|
|
(2,058,208)
|
|
|
-
|
Other long-term assets
|
|
|
138,625
|
|
|
189,439
|
|
|
-
|
|
|
328,064
|
|
Total assets
|
|
$
|
11,545,551
|
|
$
|
11,468,077
|
|
$
|
(11,727,107)
|
|
$
|
11,286,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
927,203
|
|
$
|
8,741,696
|
|
$
|
(9,668,899)
|
|
$
|
-
|
Other current liabilities
|
|
|
79,533
|
|
|
525,415
|
|
|
-
|
|
|
604,948
|
Long-term debt
|
|
|
3,332,854
|
|
|
-
|
|
|
-
|
|
|
3,332,854
|
Other long-term liabilities
|
|
|
1,047,189
|
|
|
142,758
|
|
|
-
|
|
|
1,189,947
|
Equity
|
|
|
6,158,772
|
|
|
2,058,208
|
|
|
(2,058,208)
|
|
|
6,158,772
|
|
Total liabilities and equity
|
|
$
|
11,545,551
|
|
$
|
11,468,077
|
|
$
|
(11,727,107)
|
|
$
|
11,286,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable - related parties
|
|
$
|
8,502,099
|
|
$
|
1,162,297
|
|
$
|
(9,664,396)
|
|
$
|
-
|
Other current assets
|
|
|
753,716
|
|
|
560,834
|
|
|
-
|
|
|
1,314,550
|
Oil and natural gas properties, net
|
|
|
-
|
|
|
10,798,497
|
|
|
-
|
|
|
10,798,497
|
Property and equipment, net
|
|
|
-
|
|
|
178,450
|
|
|
-
|
|
|
178,450
|
Investment in subsidiaries
|
|
|
3,698,485
|
|
|
-
|
|
|
(3,698,485)
|
|
|
-
|
Other long-term assets
|
|
|
182,623
|
|
|
167,756
|
|
|
-
|
|
|
350,379
|
|
Total assets
|
|
$
|
13,136,923
|
|
$
|
12,867,834
|
|
$
|
(13,362,881)
|
|
$
|
12,641,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable - related parties
|
|
$
|
1,162,297
|
|
$
|
8,502,099
|
|
$
|
(9,664,396)
|
|
$
|
-
|
Other current liabilities
|
|
|
69,514
|
|
|
526,906
|
|
|
-
|
|
|
596,420
|
Long-term debt
|
|
|
3,332,188
|
|
|
-
|
|
|
-
|
|
|
3,332,188
|
Other long-term liabilities
|
|
|
1,630,373
|
|
|
140,344
|
|
|
-
|
|
|
1,770,717
|
Equity
|
|
|
6,942,551
|
|
|
3,698,485
|
|
|
(3,698,485)
|
|
|
6,942,551
|
|
Total liabilities and equity
|
|
$
|
13,136,923
|
|
$
|
12,867,834
|
|
$
|
(13,362,881)
|
|
$
|
12,641,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Condensed
Consolidating Statement of Operations
|
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
283,564
|
|
$
|
-
|
|
$
|
283,564
|
Total operating costs and expenses
|
|
|
79,316
|
|
|
(1,916,459)
|
|
|
-
|
|
|
(1,837,143)
|
|
Income (loss) from operations
|
|
|
79,316
|
|
|
(1,632,895)
|
|
|
-
|
|
|
(1,553,579)
|
Interest expense
|
|
|
(53,291)
|
|
|
(847)
|
|
|
-
|
|
|
(54,138)
|
Other, net
|
|
|
(1,640,277)
|
|
|
(6,535)
|
|
|
1,640,277
|
|
|
(6,535)
|
|
Loss before income taxes
|
|
|
(1,614,252)
|
|
|
(1,640,277)
|
|
|
1,640,277
|
|
|
(1,614,252)
|
Income tax benefit
|
|
|
593,772
|
|
|
-
|
|
|
-
|
|
|
593,772
|
|
Net loss
|
|
$
|
(1,020,480)
|
|
$
|
(1,640,277)
|
|
$
|
1,640,277
|
|
$
|
(1,020,480)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
|
Three Months Ended March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
-
|
|
$
|
413,522
|
|
$
|
-
|
|
$
|
413,522
|
Total operating costs and expenses
|
|
|
114,604
|
|
|
(458,593)
|
|
|
-
|
|
|
(343,989)
|
|
Income (loss) from operations
|
|
|
114,604
|
|
|
(45,071)
|
|
|
-
|
|
|
69,533
|
Interest expense
|
|
|
(53,569)
|
|
|
-
|
|
|
-
|
|
|
(53,569)
|
Other, net
|
|
|
(49,373)
|
|
|
(4,302)
|
|
|
49,373
|
|
|
(4,302)
|
|
Income (loss) before income taxes
|
|
|
11,662
|
|
|
(49,373)
|
|
|
49,373
|
|
|
11,662
|
Income tax expense
|
|
|
(4,150)
|
|
|
-
|
|
|
-
|
|
|
(4,150)
|
|
Net income (loss)
|
|
$
|
7,512
|
|
$
|
(49,373)
|
|
$
|
49,373
|
|
$
|
7,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Condensed
Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
Consolidating
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(247,781)
|
|
$
|
360,056
|
|
$
|
-
|
|
$
|
112,275
|
Net cash flows provided by (used in) investing activities
|
|
|
257,930
|
|
|
(121,785)
|
|
|
-
|
|
|
136,145
|
Net cash flows used in financing activities
|
|
|
(10,149)
|
|
|
-
|
|
|
-
|
|
|
(10,149)
|
|
Net increase in cash and cash equivalents
|
|
|
-
|
|
|
238,271
|
|
|
-
|
|
|
238,271
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
228,550
|
|
|
-
|
|
|
228,550
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
466,821
|
|
$
|
-
|
|
$
|
466,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
|
Three Months Ended March 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Subsidiary
|
|
|
Consolidating
|
|
|
|
(in thousands)
|
|
|
Issuer
|
|
|
Guarantors
|
|
|
Entries
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash flows provided by (used in) operating activities
|
|
$
|
(766,210)
|
|
$
|
892,459
|
|
$
|
-
|
|
$
|
126,249
|
Net cash flows provided by (used in) investing activities
|
|
|
167,156
|
|
|
(818,920)
|
|
|
-
|
|
|
(651,764)
|
Net cash flows provided by (used in) financing activities
|
|
|
599,054
|
|
|
(73,539)
|
|
|
-
|
|
|
525,515
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
21
|
|
|
-
|
|
|
21
|
|
Cash and cash equivalents at end of period
|
|
$
|
-
|
|
$
|
21
|
|
$
|
-
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 15.
Subsequent
event
s
New
commodity derivative contracts.
After
March 31, 2016, the Company entered into the following oil price swaps and
natural gas price 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)
|
|
684,000
|
|
545,000
|
|
767,000
|
|
512,000
|
|
2,508,000
|
|
|
Price per Bbl
|
$
|
46.14
|
$
|
46.38
|
$
|
46.36
|
$
|
46.48
|
$
|
46.33
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,635,000
|
|
1,635,000
|
|
1,635,000
|
|
1,635,000
|
|
6,540,000
|
|
|
Price per Bbl
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
Natural Gas Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
3,150,000
|
|
3,185,000
|
|
2,760,000
|
|
2,760,000
|
|
11,855,000
|
|
|
Price per MMBtu
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil price swaps are based on the NYMEX – WTI
monthly average futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
|
The index prices for the natural gas price swaps are based on the
NYMEX – Henry Hub last trading day futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Concho Resources Inc.
Condensed Notes to
Consolidated Financial Statements
March 31, 2016
Unaudited
Note 16.
Supplementary
information
Capitalized
costs
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
15,240,182
|
|
$
|
14,940,259
|
|
Unproved
|
|
|
977,305
|
|
|
906,048
|
|
Less: accumulated depletion
|
|
|
(6,830,070)
|
|
|
(5,047,810)
|
|
|
Net capitalized costs for oil and natural gas properties
|
|
$
|
9,387,417
|
|
$
|
10,798,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
incurred for oil and natural gas producing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
252,352
|
|
$
|
-
|
|
Unproved
|
|
|
138,640
|
|
|
16,013
|
Exploration
|
|
|
170,572
|
|
|
429,169
|
Development
|
|
|
83,104
|
|
|
301,744
|
|
Total costs incurred for oil and natural gas properties
|
|
$
|
644,668
|
|
$
|
746,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table below provides the amount of asset retirement obligations
included in the costs incurred table shown above:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Exploration costs
|
|
$
|
231
|
|
$
|
618
|
Development costs
|
|
|
229
|
|
|
935
|
|
Total asset retirement obligations
|
|
$
|
460
|
|
$
|
1,553
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 also at the
forefront of applying new technologies, such as horizontal drilling and
enhanced completion techniques, throughout our three core operating areas: the
New Mexico Shelf, the Delaware Basin and the Midland Basin. In the New Mexico
Shelf, we primarily target the Yeso formation with horizontal drilling; in the
Delaware Basin, we use horizontal drilling to target the Bone Spring formation
(including the Avalon shale and the Bone Spring sands) and the Wolfcamp shale
formation; and in the Midland Basin, we target the Wolfcamp and Spraberry
formations with horizontal drilling.
Oil comprised 59 percent of our 623.5 MMBoe of estimated proved
reserves at December 31, 2015 and 63.8 percent of our 12.7 MMBoe of
production for the three months ended
March
31, 2016
.
We seek to operate the wells in which we own an
interest, and we operated wells that accounted for 93 percent of our proved developed
producing PV-10 and 78.9 percent of our 7,636 gross wells at
December 31, 2015
. 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, 2016 and 2015
included the following highlights:
·
Net loss was $
1.0 b
illion ($(7.95)
per diluted share) as compared to net income of $7.5
million ($0.06
per
diluted share) for the first three months of 2016 and 2015, respectively. The decrease
was primarily due to:
•
$1.5
billion in impairments of long-lived assets during the three months ended March
31, 2016, primarily attributable to properties in our New Mexico Shelf area;
•
$129.9
million decrease in oil and natural gas revenues as a result of a
36 percent decrease in commodity price realizations per Boe
(excluding the effects of derivative activities), partially
offset by
a 7
percent increase in
production
;
•
$42.9
million increase in depreciation, depletion and amortization expense, primarily
due to a higher rate per Boe and increased production
associated
with new wells that were successfully drilled and completed in 2015 and 2016
;
•
$
35.5 million decrease in the gain on derivatives during
the three months ended March 31, 2016, as compared to 2015; and
•
$17.1
million increase in exploration and abandonment expense due
primarily to leasehold abandonments during the three months
ended
March 31,
2016 as compared to 2015;
partially offset
by:
•
$598.0
million change in our income tax provision due to the decrease in income before
income taxes; and
•
$111.1
million increase in (gain) loss on disposition of assets, net primarily due to
our February 2016 asset divestiture.
·
Average daily sales volumes increased by 6 percent to
139,482
Boe per day during the first three months of
2016, as compared to 132,187 Boe per day during the first three months of 2015.
The increase is primarily attributable to
our
successful drilling and completion efforts during 2015 and 2016, offset by
normal production declines.
·
Net cash provided by operating activities decreased by
approximately $13.9 million to $112.3
million
for
the first three months of 2016, as compared to $126.2
m
illion
in the first three months of 2015, primarily due to a decrease in oil and
natural gas revenues, partially offset by positive variances in working capital
changes.
·
Cash increased by approximately $238.3 million during the first three
months of 2016 primarily as a result of operating cash flows and our
divestiture that closed in February 2016, partially offset by the cash
consideration related to our asset acquisition that closed in March 2016.
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 continue to manage oil prices and production controls;
·
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;
·
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 8 and 15 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, 2016 and additional derivative contracts entered into
subsequent to March 31, 2016, respectively.
Oil and natural gas prices have been subject to
significant fluctuations during the past several years. In general, average oil
and natural gas prices were significantly lower during the comparable periods of
2016 measured against 2015. The following table sets forth the average New York
Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months
ended
March 31, 2016
and 2015, as well as the high and low NYMEX
prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Average NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
$
|
33.73
|
|
$
|
48.80
|
|
Natural gas (MMBtu)
|
|
$
|
1.99
|
|
$
|
2.82
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices:
|
|
|
|
|
|
|
|
Oil (Bbl):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
41.45
|
|
$
|
53.53
|
|
|
Low
|
|
$
|
26.21
|
|
$
|
43.46
|
|
Natural gas (MMBtu):
|
|
|
|
|
|
|
|
|
High
|
|
$
|
2.47
|
|
$
|
3.23
|
|
|
Low
|
|
$
|
1.64
|
|
$
|
2.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Further, the NYMEX oil price and NYMEX natural
gas price reached highs and lows of $46.03 and $35.70 per Bbl and $2.18 and
$1.90 per MMBtu, respectively, during the period from
March 31, 2016
to May 2, 2016. At May 2, 2016, the NYMEX oil price and NYMEX natural gas price
were $44.78 per Bbl and $2.04 per MMBtu, respectively.
Our total natural gas revenues are derived from
the value of the natural gas liquids contained in our natural gas and the value
of the dry natural gas residue. For the three months ended March 31, 2016 and
2015 our realized natural gas prices (excluding the effects of derivatives)
were below the related NYMEX natural gas price primarily due to a downward
trend in the average Mont Belvieu price for a blended barrel of natural gas
liquids. The average Mont Belvieu price was $14.48 per Bbl and $19.30 per Bbl
during the three months ended March 31, 2016 and 2015, respectively, a decrease
of 25 percent.
Recent Events
2016 capital budget.
In November 2015, we announced our 2016 base capital budget, excluding
acquisitions, of approximately $1.4 billion, with drilling and completion
capital accounting for approximately $1.2 billion.
During 2016, our current intent is to adjust our capital
spending to be within our cash flows, excluding unbudgeted acquisitions. Based
on current commodity prices and costs, our capital plan is in the range of $1.1
billion to $1.3 billion. However, if we were to outspend our cash flows, we
expect to be able to use our (i) cash on hand, (ii) credit facility and (iii)
other financing sources. 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 and market conditions.
In addition, under certain circumstances, we may consider increasing,
decreasing or reallocating our capital spending plans. Our 2016 capital program
is expected to continue focusing on horizontal drilling across all our core
areas.
Asset acquisition.
In
March 2016, we completed an acquisition of 80 percent of a third-party seller’s
interest in certain oil and natural gas properties and related assets in the
southern Delaware Basin. As consideration for the acquisition, we issued to the
seller approximately 2.2 million shares of common stock with an approximate
value of $230.8 million, $146.2 million in cash and $40.0 million to carry a
portion of the seller’s future development costs in these properties.
Asset divestiture.
In February 2016, we sold certain assets in the northern Delaware Basin for
estimated proceeds of approximately $294.1 million, subject to customary
post-closing adjustments, and recognized a pre-tax gain of approximately $111.1
million.
Derivative
Financial Instruments
Derivative financial instrument exposure.
At
March 31, 2016
, the fair value of our financial derivatives was a net
asset
of $
641.4
million. All of our counterparties to these financial derivatives
are parties or affiliates of parties to our credit facility and have their
outstanding debt commitments and derivative exposures collateralized pursuant
to our credit facility. 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. 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 or its affiliates.
New commodity derivative contracts.
After March 31, 2016, we entered into the following
oil price swaps and natural gas price 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)
|
|
684,000
|
|
545,000
|
|
767,000
|
|
512,000
|
|
2,508,000
|
|
|
Price per Bbl
|
$
|
46.14
|
$
|
46.38
|
$
|
46.36
|
$
|
46.48
|
$
|
46.33
|
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl)
|
|
1,635,000
|
|
1,635,000
|
|
1,635,000
|
|
1,635,000
|
|
6,540,000
|
|
|
Price per Bbl
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
$
|
48.42
|
Natural Gas Swaps: (b)
|
|
|
|
|
|
|
|
|
|
|
|
2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
3,150,000
|
|
3,185,000
|
|
2,760,000
|
|
2,760,000
|
|
11,855,000
|
|
|
Price per MMBtu
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
$
|
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The index prices for the oil price swaps are based on the NYMEX – West
Texas Intermediate (“WTI”) monthly
|
|
average futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
|
The index prices for the natural gas price swaps are based on the
NYMEX – Henry Hub last trading day futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations
The following table sets forth summary
information concerning our production and operating data for the three months
ended
March 31, 2016
and 2015. Because of normal production
declines, increased or decreased drilling activities, fluctuations in commodity
prices and the effects of acquisitions or divestitures, the historical
information presented below should not be interpreted as being indicative of
future results.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating data:
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
8,100
|
|
|
8,066
|
|
|
Natural gas (MMcf)
|
|
|
27,557
|
|
|
22,985
|
|
|
Total (MBoe)
|
|
|
12,693
|
|
|
11,897
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes:
|
|
|
|
|
|
|
|
|
Oil (Bbl)
|
|
|
89,011
|
|
|
89,622
|
|
|
Natural gas (Mcf)
|
|
|
302,824
|
|
|
255,389
|
|
|
Total (Boe)
|
|
|
139,482
|
|
|
132,187
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl)
|
|
$
|
29.90
|
|
$
|
43.34
|
|
|
Oil, with derivatives (Bbl) (a)
|
|
$
|
60.90
|
|
$
|
63.20
|
|
|
Natural gas, without derivatives (Mcf)
|
|
$
|
1.50
|
|
$
|
2.78
|
|
|
Natural gas, with derivatives (Mcf) (a)
|
|
$
|
1.75
|
|
$
|
3.08
|
|
|
Total, without derivatives (Boe)
|
|
$
|
22.34
|
|
$
|
34.76
|
|
|
Total, with derivatives (Boe) (a)
|
|
$
|
42.66
|
|
$
|
48.81
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe:
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs
|
|
$
|
7.28
|
|
$
|
7.64
|
|
|
Oil and natural gas taxes
|
|
$
|
1.78
|
|
$
|
2.91
|
|
|
Depreciation, depletion and amortization
|
|
$
|
24.43
|
|
$
|
22.46
|
|
|
General and administrative
|
|
$
|
4.24
|
|
$
|
4.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes the
effect of net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
251,127
|
|
$
|
160,186
|
|
|
|
Natural gas derivatives
|
|
|
6,803
|
|
|
6,970
|
|
|
|
|
Total
|
|
$
|
257,930
|
|
$
|
167,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The presentation
of average prices with derivatives is a non-GAAP measure as a result of
including the net cash receipts from 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, 2016 Compared to Three Months Ended March 31, 2015
Oil and natural gas
revenues.
Revenue from oil and natural gas operations was
$283.6 million for the three months ended
March 31, 2016
, a
decrease of
$129.9 million (31
percent
) from $413.5 million for
2015
.
This decrease was primarily due to the decrease in realized oil and natural gas
prices, partially offset by increased production due to our successful drilling
efforts during 2015 and 2016 offset by normal production declines. Specific
factors affecting oil and natural gas revenues include the following:
·
total oil production was 8,100
MBbl
for the
three months ended
March 31, 2016
, an
increase
of 34
MBbl
from 8,066
MBbl
for
2015
;
·
average realized oil price (excluding the effects of derivative
activities) was
$29.90
per Bbl during the three months ended
March 31, 2016
, a
decrease of 31
percent
from
$43.34
per Bbl
during
2015
.
For the three months
ended March 31, 2016, our crude oil price differential relative to NYMEX was
$(3.83) per Bbl, or a realization of approximately 88.6 percent, as compared to
a crude oil price differential relative to NYMEX of $(5.46) per Bbl, or a
realization of approximately 88.8 percent, for 2015. We incur fixed deductions
from the posted Midland oil price based on the location of our oil within the
Permian Basin. Due to lower oil prices during the first quarter of 2016 as
compared to 2015, these fixed deductions had a greater percentage impact on our
realized oil price. Additionally, the basis differential between the location
of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil
has a direct effect on our realized oil price. For the three months ended March
31, 2016 and 2015, the average market basis differential between WTI-Midland
and WTI-Cushing was a price benefit of $
0.14
per Bbl and
reduction of $
(1.98)
per
Bbl, respectively;
·
total natural gas production was 27,557
MMcf
for the three months ended
March 31, 2016
, an
increase
of 4,572
MMcf
(20
percent
) from 22,985
MMcf
for
2015
;
and
·
average realized natural gas price (excluding the effects of
derivative activities) was
$1.50
per Mcf during the
three months ended
March 31, 2016
, a decrease of 46
percent
from
$2.78
per Mcf during
2015.
For the three months ended March 31, 2016 and 2015, we realized approximately
75.4 percent and 98.6 percent, respectively, of the average NYMEX natural gas
prices for the respective periods. Our total natural gas revenues are derived
from the value of the natural gas liquids contained in our natural gas and the
value of the dry natural gas residue. During the three months ended March 31,
2016 and 2015, our realized natural gas price (excluding the effects of
derivatives) fell below the related NYMEX natural gas price primarily due to a
downward trend in the average Mont Belvieu price for a blended barrel of
natural gas liquids. The average Mont Belvieu price was $14.48
per
Bbl
and $19.30
per Bbl
during the three months ended March 31, 2016 and 2015, respectively, a decrease
of 25 percent.
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. We do not expect the plant to be back to full capacity until sometime
during the second quarter of 2016.
Production expenses.
The following table provides the
components of our total oil and natural gas production costs for the three
months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
87,052
|
|
$
|
6.86
|
|
$
|
83,658
|
|
$
|
7.03
|
Workover costs
|
|
|
5,380
|
|
|
0.42
|
|
|
7,211
|
|
|
0.61
|
Taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem
|
|
|
5,522
|
|
|
0.44
|
|
|
5,255
|
|
|
0.44
|
|
Production
|
|
|
17,003
|
|
|
1.34
|
|
|
29,411
|
|
|
2.47
|
|
|
Total oil and natural gas production expenses
|
|
$
|
114,957
|
|
$
|
9.06
|
|
$
|
125,535
|
|
$
|
10.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, we have
some control over lease operating expenses and workover costs on properties we
operate, but production and ad valorem taxes are related to commodity prices.
Lease operating expenses were $87.1 million ($6.86
per Boe) for the three months ended
March 31,
2016
, which was an increase of
$3.4 million from $83.7 million ($7.03 per Boe) for the three months ended
March 31, 2015
.
During the first quarter of 2016, we experienced a slight increase in lease
operating expenses due primarily to
additional
producing wells during the period as compared 2015, partially
offset by
a
more favorable vendor pricing environment
. The decrease in lease operating expenses per Boe was primarily
due to
increased production efficiencies
.
Workover expenses were approximately
$5.4 million and $7.2 million for the three months ended
March 31, 2016
and 2015, respectively. The decrease was primarily related to less overall
activity during 2016 as compared to 2015 and a more favorable vendor pricing
environment.
Production taxes per unit of production were $1.34
per Boe during the three months ended
March
31, 2016
, a decrease of 46 percent
from $2.47 per Boe during
2015
. The decrease was directly related to the decrease
in oil and natural gas prices and due to tax credits of approximately $3.7
million received during the first quarter of 2016 related to certain wells in
Texas qualifying for reduced severance tax rates. Over the same period, our per
Boe prices (excluding the effects of derivatives) decreased 36 percent.
Exploration
and abandonments expense.
The following table provides a breakdown of our exploration and abandonments
expense for the three months ended
March 31,
2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Geological and geophysical
|
|
$
|
1,348
|
|
$
|
1,432
|
Exploratory dry hole costs
|
|
|
-
|
|
|
781
|
Leasehold abandonments
|
|
|
20,652
|
|
|
1,919
|
Other
|
|
|
860
|
|
|
1,623
|
|
Total exploration and abandonments
|
|
$
|
22,860
|
|
$
|
5,755
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2016 and 2015
, we recorded approximately $20.7 million and
$1.9 million, respectively, of leasehold abandonments. For the three
months ended
March 31, 2016,
our abandonments were primarily related to
acreage in our New Mexico Shelf area in locations where we have 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, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
Per
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas properties
|
|
$
|
304,745
|
|
$
|
24.01
|
|
$
|
262,280
|
|
$
|
22.05
|
Depreciation of other property and equipment
|
|
|
4,972
|
|
|
0.39
|
|
|
4,560
|
|
|
0.38
|
Amortization of intangible assets - operating rights
|
|
|
365
|
|
|
0.03
|
|
|
365
|
|
|
0.03
|
|
Total depletion, depreciation and amortization
|
|
$
|
310,082
|
|
$
|
24.43
|
|
$
|
267,205
|
|
$
|
22.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period
end
|
|
$
|
42.77
|
|
|
|
|
$
|
79.21
|
|
|
|
Natural gas price used to estimate proved natural gas
reserves at period end
|
|
$
|
2.40
|
|
|
|
|
$
|
3.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of proved oil and natural gas
properties was $304.7 million ($24.01 per Boe) for the three months ended March
31, 2016, an increase of $42.4 million (16 percent) from $262.3 million
($22.05 per Boe) for 2015. The increase in depletion expense was primarily due
to a higher depletion rate per Boe in addition to increased production
associated with new wells that were successfully drilled and completed in 2015
and 2016. The increase in depletion expense per Boe period over period was
primarily due to
a decrease in
proved reserves caused by (i) lower commodity prices period over period and
(ii) reclassification of proved reserves to unproven that are no longer
expected to be developed within the five years of their initial recording
required by SEC rules during the fourth quarter of 2015, partially offset by a
reduction in the net book value of our oil and natural gas properties due to a
non-cash impairment charge of approximately $52.9 million recorded in the
fourth quarter of 2015.
The increase in depreciation expense was
primarily associated with additional other property and equipment related to
buildings and other items as a result of our increased number of employees.
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 or by individual well for those wells not constituting
part of a 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) proved reserves
and risk-adjusted probable and possible reserves, and (vii) other sources of
income and expenses from integrated assets.
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.
As a result of the carrying amount of certain
of our long-lived assets and their integrated assets being less than their
expected undiscounted future net cash flows, we recognized a non-cash charge
against earnings for the amount by which the carrying amount exceeded the
estimated fair value of the assets. For the three months ended March 31, 2016,
this amount was approximately $1.5 billion and was primarily attributable to properties
in our New Mexico Shelf area.
It is reasonably possible that the estimate of
undiscounted future net cash flows 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 prices, (ii) increases or decreases
in production and capital costs, (iii) future reserve 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.
Based on economic factors as of March 31, 2016,
we determined that undiscounted future cash flows attributable to a certain
depletion group with net book value of approximately $1.8 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, 2016. We
estimate that, if this depletion group was to become impaired in a future
period, we could recognize non-cash impairment in that period of approximately
$1.0 billion.
General and administrative expenses.
The following table provides components of our general and
administrative expenses for the three months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Per
|
|
|
|
|
Per
|
(in thousands, except per unit amounts)
|
|
Amount
|
|
Boe
|
|
Amount
|
|
Boe
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses
|
|
$
|
44,279
|
|
$
|
3.49
|
|
$
|
49,670
|
|
$
|
4.18
|
Non-cash stock-based compensation
|
|
|
16,022
|
|
|
1.26
|
|
|
15,495
|
|
|
1.30
|
Less: Third-party operating fee reimbursements
|
|
|
(6,506)
|
|
|
(0.51)
|
|
|
(6,364)
|
|
|
(0.53)
|
|
Total general and administrative expenses
|
|
$
|
53,795
|
|
$
|
4.24
|
|
$
|
58,801
|
|
$
|
4.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were
approximately $53.8 million ($4.24 per Boe) for the three months ended
March 31, 2016
,
a decrease of $5.0 million (9 percent) from $58.8 million ($4.95 per Boe) for
2015
. This
decrease was primarily a result of a general company-wide initiative to reduce
general and administrative costs.
The
decrease in total general and administrative expenses per Boe was primarily due
to the company-wide initiative to reduce general and administrative costs noted
above and increased production from our wells successfully drilled and
completed in 2015 and 2016.
As the operator of certain oil and natural gas properties
in which we own an interest, we earn overhead reimbursements during the
drilling and production phases of the property.
We
earned reimbursements of $6.5 million and $6.4 million during the three months
ended
March 31, 2016
and 2015, respectively. This reimbursement is
reflected as a reduction of general and administrative expenses in the
consolidated statements of operations.
Gain on derivatives.
The following table sets forth the gain on derivatives for the
three months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Gain on derivatives:
|
|
|
|
|
|
|
|
Oil derivatives
|
|
$
|
71,140
|
|
$
|
110,280
|
|
Natural gas derivatives
|
|
|
8,702
|
|
|
5,060
|
|
|
Total
|
|
$
|
79,842
|
|
$
|
115,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table
represents our net cash receipts from derivatives for the three months ended
March 31, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash receipts from derivatives:
|
|
|
|
|
Oil derivatives
|
|
$
|
251,127
|
|
$
|
160,186
|
|
Natural gas derivatives
|
|
|
6,803
|
|
|
6,970
|
|
|
Total
|
|
$
|
257,930
|
|
$
|
167,156
|
|
|
|
|
|
|
|
|
|
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.
Gain on disposition of assets, net.
In February 2016, we sold certain assets in the northern
Delaware Basin for estimated proceeds of approximately $294.1 million, subject
to customary post-closing adjustments, and recognized a pre-tax gain of
approximately $111.1 million.
Interest expense.
The following table sets forth interest
expense, weighted average interest rates and weighted average debt balances for
the three months ended March 31, 2016 and 2015:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
March 31,
|
(dollars in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
54,138
|
|
$
|
53,569
|
Capitalized interest
|
|
|
252
|
|
|
1,210
|
|
Interest expense, excluding impact of capitalized interest
|
|
$
|
54,390
|
|
$
|
54,779
|
|
|
|
|
|
|
|
Weighted average interest rate - credit facility
|
|
|
-
|
|
|
2.4%
|
Weighted average interest rate - senior notes
|
|
|
5.9%
|
|
|
5.9%
|
|
Total weighted average interest rate
|
|
|
5.9%
|
|
|
5.7%
|
|
|
|
|
|
|
|
|
Weighted average credit facility balance
|
|
$
|
-
|
|
$
|
252,528
|
Weighted average senior notes balance
|
|
|
3,350,000
|
|
|
3,350,000
|
|
Total weighted average debt balance
|
|
$
|
3,350,000
|
|
$
|
3,602,528
|
|
|
|
|
|
|
|
|
The decrease in the weighted average debt balance
for the three months ended March 31, 2016 as compared to 2015 was due to the
repayment of our credit facility using a portion of the proceeds from our October
2015 equity offering. The decrease in interest expense was due
to an overall decrease in the weighted average debt balance.
Income tax provisions.
We recorded an income tax benefit
of $593.8 million and income tax expense of $4.2 million for the three months
ended
March 31, 2016
and 2015, respectively. The change in our
income tax provision was primarily due to the decrease in income before income
taxes. The effective income tax rates for the three months ended
March 31, 2016
and 2015 were 36.8 percent and 35.6 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 or 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 and asset retirement obligations, during the
three
months ended
March 31, 2016
and 2015 totaled $253.2 million and $729.4 million, respectively. The
decrease was primarily due to our reduced drilling and completion activity
level during the first quarter of 2016 as compared to the first quarter of
2015. The decrease is primarily related to our intent to adjust our capital
spending to be within our cash flow, excluding unbudgeted acquisitions. The
primary reason for the differences in the costs incurred and cash flow
expenditures was our issuance of approximately 2.2 million shares of common
stock related to our March 2016 acquisition and timing of payments. The 2016 expenditures
were primarily funded in part from (i) cash flows from operations, (ii)
proceeds from our February 2016 divestiture and (iii) our issuance of
approximately 2.2 million shares of common stock related to our March 2016
acquisition.
2016 capital budget.
In November 2015, we announced our 2016 base capital budget,
excluding acquisitions, of approximately $1.4 billion, with drilling and
completion capital accounting for approximately $1.2 billion.
During 2016, our current intent is to adjust our capital
spending to be within our cash flows, excluding unbudgeted acquisitions. Based
on current commodity prices and costs, our capital plan is in the range of $1.1
billion to $1.3 billion. However, if we were to outspend our cash flows, we
expect to be able to use our (i) cash on hand, (ii) credit facility and (iii)
other financing sources. 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 and market conditions.
In addition, under certain circumstances, we may consider increasing,
decreasing or reallocating our capital spending plans. Our 2016 capital program
is expected to continue focusing on horizontal drilling across all our core
areas.
Acquisitions.
The
following table reflects o
ur expenditures for
acquisitions of proved and unproved properties for the three months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
252,352
|
|
$
|
-
|
|
Unproved (a)
|
|
|
138,640
|
|
|
16,013
|
|
|
Total property acquisition costs (b)
|
|
$
|
390,992
|
|
$
|
16,013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Included in the unproved
property acquisition costs above are budgeted leasehold acreage acquisitions
of $16.2 million and $16.0 million for the three months ended March 31, 2016
and 2015, respectively.
|
|
(b)
|
Included in the three months
ended March 31, 2016 are approximately $374.3 million of property acquisition
costs related to our March 2016 unbudgeted acquisition.
|
|
|
|
|
|
|
|
|
|
|
Contractual obligations.
Our contractual obligations include long-term
debt, cash interest expense on debt, operating lease obligations, purchase
obligations, employment agreements with executive officers, derivative
liabilities, investment contributions related to Alpha Crude Connecter, LLC,
our other midstream entity in the southern Delaware Basin and other
obligations. Since December 31, 2015, the changes in our contractual
obligations are not material. See Note 9 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, 2016
.
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 and
cash settlements received from derivatives
, (ii) borrowings under our credit facility, (iii) proceeds
from bond and equity offerings and (iv) proceeds from the sale of assets. In
November 2015, we announced our 2016 base capital budget, excluding
acquisitions, of approximately $1.4 billion. During 2016, our current
intent is to adjust our capital spending to be within our cash flows, excluding
unbudgeted acquisitions. Based on current commodity prices and costs, our
capital plan is in the range of $1.1 billion to $1.3 billion. However, if
we were to outspend our cash flows, we could use our (i) cash on hand, (ii)
credit facility and (iii) other financing sources to fund any cash flow
deficits.
The following table summarizes our changes in
cash and cash equivalents for the three months ended
March 31, 2016
and 2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
March 31,
|
(in thousands)
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
112,275
|
|
$
|
126,249
|
Net cash provided by (used in) investing activities
|
|
|
136,145
|
|
|
(651,764)
|
Net cash provided by (used in) financing activities
|
|
|
(10,149)
|
|
|
525,515
|
|
Net increase in cash and cash equivalents
|
|
$
|
238,271
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from
operating activities.
The decrease in operating cash flows during the
three
months ended March 31, 2016 as compared to
the same period in 2015 was primarily due to (i) a decrease in oil and natural
gas revenues of approximately $129.9 million, partially offset by (i)
approximately $73.7 million of positive variances in operating assets and
liabilities, (ii) approximately $25.4 million decrease in cash taxes, (iii)
approximately $10.6 million decrease in cash production expense and (iv) a cash
decrease in general and administrative expense of approximately $5.5 million.
Our net cash provided by operating
activities included a benefit of approximately $28.8
million
and a reduction of approximately $44.9
million
for the
three
months ended March 31, 2016 and 2015,
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 used in investing activities.
During the three months
ended
March
31, 2016
and 2015, we invested approximately $0.4 billion and $0.8 billion,
respectively, for capital expenditures on oil and natural gas properties. Additionally,
we received approximately $292.0 million related to proceeds from the
disposition of assets and approximately $257.9 million from settlements on
derivatives during the three months ended March 31, 2016 as compared to $167.2
million from settlements on derivatives during the comparable period in 2015.
Cash flow from
financing activities.
Net cash used by financing activities
was approximately $10.1 million for the
three
months ended
March 31, 2016, while during 2015 we had net cash provided by financing
activities of approximately $525.5 million. Below is a description of our
financing activities:
·
In March 2015, we issued shares of our common stock in a public
offering and received net proceeds of approximately $741.2 million. We
used a portion of the net proceeds from this offering to repay all outstanding borrowings
under our credit facility and the remainder for general corporate purposes.
·
During the first three months of 2015, we had net payments on our
credit facility of $139.5 million.
·
During the first three months of 2016, we had no outstanding borrowings
under our credit facility.
At
March 31, 2016,
we
had unused commitments of approximately
$2.5
billion
based on bank commitments of $2.5 billion. The maturity date of the credit
facility is May 9, 2019.
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”) or (ii) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). The
credit facility’s interest rates of Eurodollar rate advances and JPM Prime Rate
advances varied, with interest margins ranging from 125 to 225 basis points and
25 to 125 basis points, respectively, 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.
Over the last three years, 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, 2016,
we had approximately $466.8
million
of
cash on hand.
In April 2016, we completed
our annual borrowing base review where we maintained our $2.5 billion in
commitments from our bank group until our next scheduled borrowing base
redetermination in May 2017. Our current borrowing base is $2.8 billion, which
is a reduction from our previous borrowing base of $3.25 billion. There is no
assurance that our borrowing base will not be further reduced, which could
affect our liquidity. Upon a subsequent redetermination, our borrowing base could be
substantially reduced.
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 Standard & Poor’s Ratings Group, Inc. (“S&P”) and
Moody’s Investors Service, Inc. (“Moody’s”), which are subject to regular
reviews. S&P’s corporate rating for us is “BB+” with a stable outlook.
Moody’s corporate rating for us is “Ba1” with a stable outlook. 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, 2016;
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, 2016
was $9.0
billion, consisting of $0.5 billion
of cash and cash equivalents, debt of $
3.3 b
illion
and stockholders’ equity of $
6.2
billion. Our net
debt to book capitalization was 32
percent and
31
percent
at March 31, 2016 and December
31, 2015, respectively. Our ratio of current assets to current liabilities was
2.30
to 1.0 at March 31, 2016 as compared to
2.20 to 1.0 at December 31, 2015.
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, 2016, we received an
average of $29.90
per Bbl of oil and $1.50
per Mcf of natural gas before consideration of
commodity derivative contracts compared to $43.34
per
Bbl of oil and $2.78
per Mcf of natural gas in
the three months ended March
31, 2015.
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 stock-based compensation, valuation of business
combinations, valuation of financial derivative instruments 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,
2016. 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, 2015, filed with the
United States Securities and Exchange Commission (the “SEC”) on February 25,
2016.
Recent
accounting pronouncements.
In May
2014, the Financial Accounting Standards Board (“the FASB”) issued Accounting
Standards Update (“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.
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 2014-09 by one
year. That new standard is now effective for annual reporting periods beginning
after December 15, 2017. An entity can apply ASU 2014-09 using either a full
retrospective method, meaning the standard is applied to all of the periods
presented, or a modified retrospective method, meaning the cumulative effect of
initially applying the standard is recognized in the most current period
presented in the financial statements. We are evaluating the impact that this
new guidance will have on our 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 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 March 2016, the FASB issued ASU
No. 2016-09, “Compensation–Stock Compensations (Topic 718): Improvements
to Employee Share-based Payment Accounting,” which changes the accounting and
presentation for share-based payment arrangements in the following areas: (i)
recognition in the statement of operations of excess tax benefits and
deficiencies; (ii) cash flow presentation of excess tax benefits and
deficiencies; (iii) minimum statutory withholding thresholds and the
classification on the cash flow statement of the withheld amounts; and (iv) an
accounting policy election to recognize forfeitures as they occur. This
guidance is effective for reporting periods beginning after December 15, 2016
and early adoption is permitted. We are evaluating the impact that this new
guidance will have on our consolidated financial statements.