e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2010
or
|
|
|
o |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
|
|
|
Delaware
|
|
76-0818600 |
|
|
|
(State or other jurisdiction
|
|
(I.R.S. Employer |
of incorporation or organization)
|
|
Identification No.) |
|
|
|
550 West Texas Avenue, Suite 100 |
|
|
Midland, Texas
|
|
79701 |
|
|
|
(Address of principal executive offices)
|
|
(Zip code) |
(432) 683-7443
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated filer þ
|
|
Accelerated filer o
|
|
Non-accelerated filer o
|
|
Smaller reporting company o |
|
|
(Do not check if a smaller reporting company)
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
Number
of shares of the registrants common stock outstanding at
November 2, 2010: 99,883,995 shares
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this report that
express a belief, expectation, or intention, or that are not statements of historical fact, are
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the
Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act).
These forward-looking statements include statements, projections and estimates concerning our
operations, performance, business strategy, oil and natural gas reserves, drilling program capital
expenditures, liquidity and capital resources, the timing and success of specific projects,
outcomes and effects of litigation, claims and disputes, derivative activities and potential
financing. Forward-looking statements are generally accompanied by words such as estimate,
project, predict, believe, expect, anticipate, potential, could, may, foresee,
plan, goal or other words that convey the uncertainty of future events or outcomes.
Forward-looking statements are not guarantees of performance. We have based these forward-looking
statements on our current expectations and assumptions about future events. These statements are
based on certain assumptions and analyses made by us in light of our experience and our perception
of historical trends, current conditions and expected future developments as well as other factors
we believe are appropriate under the circumstances. Actual results may differ materially from those
implied or expressed by the forward-looking statements. These forward-looking statements speak only
as of the date of this report, or if earlier, as of the date they were made. We disclaim any
obligation to update or revise these statements unless required by securities law, and we caution
you not to rely on them unduly. While our management considers these expectations and assumptions
to be reasonable, they are inherently subject to significant business, economic, competitive,
regulatory and other risks, contingencies and uncertainties relating to, among other matters, the
risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2009, and in this
report as well as those factors summarized below:
|
|
|
sustained or further declines in the prices we receive for our oil and natural
gas; |
|
|
|
uncertainties about the estimated quantities of oil and natural gas reserves; |
|
|
|
risks related to the integration of the assets of Marbob Energy Corporation and
affiliates (Marbob) and its former employees, along with other recently acquired
assets, with our operations; |
|
|
|
drilling and operating risks; |
|
|
|
the adequacy of our capital resources and liquidity including, but not limited
to, access to additional borrowing capacity under our credit facility; |
|
|
|
the effects of government regulation, permitting and other legal requirements,
including new legislation or regulation of hydraulic fracturing; |
|
|
|
difficult and adverse conditions in the domestic and global capital and credit
markets; |
|
|
|
risks related to the concentration of our operations in the Permian Basin of
Southeast New Mexico and West Texas; |
|
|
|
potential financial losses or earnings reductions from our commodity price risk
management program; |
|
|
|
shortages of oilfield equipment, services and qualified personnel and increased
costs for such equipment, services and personnel; |
|
|
|
risks and liabilities associated with acquired properties or businesses,
including the Marbob assets; |
|
|
|
uncertainties about our ability to successfully execute our business and
financial plans and strategies; |
|
|
|
uncertainties about our ability to replace reserves and economically develop our
current reserves; |
|
|
|
general economic and business conditions, either internationally or domestically
or in the jurisdictions in which we operate; |
|
|
|
competition in the oil and natural gas industry; |
|
|
|
uncertainty concerning our assumed or possible future results of operations; and |
|
|
|
our existing indebtedness, as well as the increase in our indebtedness as a
result of the Marbob acquisition. |
Reserve engineering is a process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the
quality of available data, the interpretation of such data and price and cost assumptions made by
our reserve engineers. In addition, the results of drilling, testing and production activities may
justify revisions of estimates that were made previously. If significant, such revisions would
change the schedule of any further production and development drilling. Accordingly, reserve
estimates may differ from the quantities of oil and natural gas that are ultimately recovered.
ii
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
iii
Concho Resources Inc.
Consolidated Balance Sheets
Unaudited
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands, except share and per share data) |
|
2010 |
|
|
2009 |
|
|
Assets
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
357 |
|
|
$ |
3,234 |
|
Accounts receivable, net of allowance for doubtful accounts: |
|
|
|
|
|
|
|
|
Oil and natural gas |
|
|
99,402 |
|
|
|
69,199 |
|
Joint operations and other |
|
|
101,421 |
|
|
|
100,120 |
|
Related parties |
|
|
311 |
|
|
|
216 |
|
Derivative instruments |
|
|
23,339 |
|
|
|
1,309 |
|
Deferred income taxes |
|
|
2,551 |
|
|
|
29,284 |
|
Prepaid costs and other |
|
|
11,295 |
|
|
|
13,896 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
238,676 |
|
|
|
217,258 |
|
|
|
|
|
|
|
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method |
|
|
3,871,715 |
|
|
|
3,358,004 |
|
Accumulated depletion and depreciation |
|
|
(692,922 |
) |
|
|
(517,421 |
) |
|
|
|
|
|
|
|
Total oil and natural gas properties, net |
|
|
3,178,793 |
|
|
|
2,840,583 |
|
Other property and equipment, net |
|
|
17,105 |
|
|
|
15,706 |
|
|
|
|
|
|
|
|
Total property and equipment, net |
|
|
3,195,898 |
|
|
|
2,856,289 |
|
|
|
|
|
|
|
|
Deferred loan costs, net |
|
|
19,544 |
|
|
|
20,676 |
|
Intangible asset, net operating rights |
|
|
35,360 |
|
|
|
36,522 |
|
Inventory |
|
|
20,903 |
|
|
|
16,255 |
|
Noncurrent derivative instruments |
|
|
20,105 |
|
|
|
23,614 |
|
Other assets |
|
|
11,189 |
|
|
|
471 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,541,675 |
|
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
7,133 |
|
|
$ |
15,443 |
|
Related parties |
|
|
474 |
|
|
|
291 |
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Bank overdrafts |
|
|
38,551 |
|
|
|
3,415 |
|
Revenue payable |
|
|
40,785 |
|
|
|
31,069 |
|
Accrued and prepaid drilling costs |
|
|
174,000 |
|
|
|
164,282 |
|
Derivative instruments |
|
|
27,104 |
|
|
|
62,419 |
|
Other current liabilities |
|
|
62,098 |
|
|
|
60,095 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
350,145 |
|
|
|
337,014 |
|
|
|
|
|
|
|
|
Long-term debt |
|
|
688,620 |
|
|
|
845,836 |
|
Deferred income taxes |
|
|
677,573 |
|
|
|
603,286 |
|
Noncurrent derivative instruments |
|
|
15,713 |
|
|
|
29,337 |
|
Asset retirement obligations and other long-term liabilities |
|
|
21,002 |
|
|
|
20,184 |
|
Commitments and contingencies (Note K) |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, $0.001 par value; 300,000,000 authorized; 91,908,877 and 85,815,926
shares issued at September 30, 2010 and December 31, 2009, respectively |
|
|
92 |
|
|
|
86 |
|
Additional paid-in capital |
|
|
1,270,887 |
|
|
|
1,029,392 |
|
Retained earnings |
|
|
518,853 |
|
|
|
306,367 |
|
Treasury stock, at cost; 27,044 and 12,380 shares at September 30, 2010 and December 31, 2009,
respectively |
|
|
(1,210 |
) |
|
|
(417 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
1,788,622 |
|
|
|
1,335,428 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
3,541,675 |
|
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
1
Concho Resources Inc.
Consolidated Statements of Operations
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands, except per share amounts) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
190,977 |
|
|
$ |
121,301 |
|
|
$ |
528,129 |
|
|
$ |
287,786 |
|
Natural gas sales |
|
|
49,519 |
|
|
|
32,193 |
|
|
|
140,077 |
|
|
|
79,042 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
240,496 |
|
|
|
153,494 |
|
|
|
668,206 |
|
|
|
366,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas production |
|
|
45,072 |
|
|
|
25,439 |
|
|
|
122,220 |
|
|
|
76,022 |
|
Exploration and abandonments |
|
|
3,625 |
|
|
|
2,776 |
|
|
|
5,798 |
|
|
|
10,195 |
|
Depreciation, depletion and amortization |
|
|
61,900 |
|
|
|
54,835 |
|
|
|
169,844 |
|
|
|
157,985 |
|
Accretion of discount on asset retirement obligations |
|
|
405 |
|
|
|
220 |
|
|
|
1,177 |
|
|
|
799 |
|
Impairments of long-lived assets |
|
|
1,922 |
|
|
|
1,131 |
|
|
|
9,234 |
|
|
|
9,686 |
|
General and administrative (including non-cash stock-based
compensation of $3,152 and $2,548 for the three months ended
September 30, 2010 and 2009, respectively, and $8,854 and $6,661
for the nine months ended September 30, 2010 and 2009,
respectively) |
|
|
15,045 |
|
|
|
12,715 |
|
|
|
46,141 |
|
|
|
38,633 |
|
Bad debt expense |
|
|
6 |
|
|
|
|
|
|
|
578 |
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges |
|
|
66,107 |
|
|
|
7,783 |
|
|
|
(62,229 |
) |
|
|
94,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
194,082 |
|
|
|
104,899 |
|
|
|
292,763 |
|
|
|
387,755 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
46,414 |
|
|
|
48,595 |
|
|
|
375,443 |
|
|
|
(20,927 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
(12,036 |
) |
|
|
(6,809 |
) |
|
|
(34,293 |
) |
|
|
(17,379 |
) |
Other, net |
|
|
(3,521 |
) |
|
|
(200 |
) |
|
|
(3,898 |
) |
|
|
(348 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense |
|
|
(15,557 |
) |
|
|
(7,009 |
) |
|
|
(38,191 |
) |
|
|
(17,727 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
30,857 |
|
|
|
41,586 |
|
|
|
337,252 |
|
|
|
(38,654 |
) |
Income tax benefit (expense) |
|
|
(10,082 |
) |
|
|
(21,824 |
) |
|
|
(124,766 |
) |
|
|
11,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
20,775 |
|
|
$ |
19,762 |
|
|
$ |
212,486 |
|
|
$ |
(26,681 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
0.23 |
|
|
$ |
0.23 |
|
|
$ |
2.35 |
|
|
$ |
(0.31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in basic earnings per share |
|
|
91,182 |
|
|
|
85,061 |
|
|
|
90,361 |
|
|
|
84,798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
0.22 |
|
|
$ |
0.23 |
|
|
$ |
2.32 |
|
|
$ |
(0.31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares used in diluted earnings per share |
|
|
92,440 |
|
|
|
86,088 |
|
|
|
91,631 |
|
|
|
84,798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
2
Concho Resources Inc.
Consolidated Statement of Stockholders Equity
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Common Stock |
|
|
Paid-in |
|
|
Retained |
|
|
Treasury Stock |
|
|
Stockholders |
|
(in thousands) |
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Shares |
|
|
Amount |
|
|
Equity |
|
|
BALANCE AT DECEMBER 31, 2009 |
|
|
85,816 |
|
|
$ |
86 |
|
|
$ |
1,029,392 |
|
|
$ |
306,367 |
|
|
|
12 |
|
|
$ |
(417 |
) |
|
$ |
1,335,428 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
212,486 |
|
|
|
|
|
|
|
|
|
|
|
212,486 |
|
Issuance of common stock |
|
|
5,348 |
|
|
|
5 |
|
|
|
219,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
219,308 |
|
Stock options exercised |
|
|
465 |
|
|
|
1 |
|
|
|
4,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,371 |
|
Grants of restricted stock |
|
|
288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancellation of restricted stock |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
8,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,854 |
|
Excess tax benefits related to stock-based compensation |
|
|
|
|
|
|
|
|
|
|
8,968 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,968 |
|
Purchase of treasury stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
(793 |
) |
|
|
(793 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT SEPTEMBER 30, 2010 |
|
|
91,909 |
|
|
$ |
92 |
|
|
$ |
1,270,887 |
|
|
$ |
518,853 |
|
|
|
27 |
|
|
$ |
(1,210 |
) |
|
$ |
1,788,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
Concho Resources Inc.
Consolidated Statements of Cash Flows
Unaudited
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
212,486 |
|
|
$ |
(26,681 |
) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
169,844 |
|
|
|
157,985 |
|
Impairments of long-lived assets |
|
|
9,234 |
|
|
|
9,686 |
|
Accretion of discount on asset retirement obligations |
|
|
1,177 |
|
|
|
799 |
|
Exploration and abandonments, including dry holes |
|
|
4,121 |
|
|
|
6,950 |
|
Non-cash compensation expense |
|
|
8,854 |
|
|
|
6,661 |
|
Bad debt expense |
|
|
578 |
|
|
|
|
|
Deferred income taxes |
|
|
109,988 |
|
|
|
(21,840 |
) |
Loss on sale of assets |
|
|
24 |
|
|
|
147 |
|
(Gain) loss on derivatives not designated as hedges |
|
|
(62,229 |
) |
|
|
94,435 |
|
Other non-cash items |
|
|
3,760 |
|
|
|
2,656 |
|
Changes in operating assets and liabilities, net of acquisitions: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(35,505 |
) |
|
|
(10,367 |
) |
Prepaid costs and other |
|
|
(700 |
) |
|
|
(2,519 |
) |
Inventory |
|
|
(4,673 |
) |
|
|
(3,979 |
) |
Accounts payable |
|
|
(8,127 |
) |
|
|
5,029 |
|
Revenue payable |
|
|
9,716 |
|
|
|
17,581 |
|
Other current liabilities |
|
|
(15,792 |
) |
|
|
(4,465 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
402,756 |
|
|
|
232,078 |
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Capital expenditures on oil and natural gas properties |
|
|
(486,903 |
) |
|
|
(316,756 |
) |
Acquisition of oil and natural gas properties |
|
|
(17,730 |
) |
|
|
|
|
Additions to other property and equipment |
|
|
(3,750 |
) |
|
|
(3,716 |
) |
Proceeds from the sale of oil and natural gas properties and other assets |
|
|
790 |
|
|
|
1,004 |
|
Settlements received from (paid on) derivatives not designated as hedges |
|
|
(5,231 |
) |
|
|
77,590 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(512,824 |
) |
|
|
(241,878 |
) |
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Proceeds from issuance of long-term debt |
|
|
840,500 |
|
|
|
672,650 |
|
Payments of long-term debt |
|
|
(998,000 |
) |
|
|
(656,916 |
) |
Net proceeds from issuance of common stock |
|
|
219,308 |
|
|
|
|
|
Exercise of stock options |
|
|
4,371 |
|
|
|
4,501 |
|
Excess tax benefit related to stock-based compensation |
|
|
8,968 |
|
|
|
3,357 |
|
Payments for loan origination costs |
|
|
(2,299 |
) |
|
|
(8,933 |
) |
Purchase of treasury stock |
|
|
(793 |
) |
|
|
(292 |
) |
Bank overdrafts |
|
|
35,136 |
|
|
|
(6,624 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
107,191 |
|
|
|
7,743 |
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(2,877 |
) |
|
|
(2,057 |
) |
Cash and cash equivalents at beginning of period |
|
|
3,234 |
|
|
|
17,752 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
357 |
|
|
$ |
15,695 |
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOWS: |
|
|
|
|
|
|
|
|
Cash paid for interest and fees, net of $119 and $33 capitalized interest |
|
$ |
27,627 |
|
|
$ |
13,291 |
|
Cash paid for income taxes |
|
$ |
17,771 |
|
|
$ |
5,598 |
|
NON-CASH INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Deferred tax effect of acquired oil and natural gas properties |
|
$ |
|
|
|
$ |
(835 |
) |
The accompanying notes are an integral part of these consolidated financial statements.
4
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note A. Organization and nature of operations
Concho Resources Inc. (the Company or Concho) is a Delaware corporation formed on
February 22, 2006. The Companys principal business is the acquisition, development and exploration
of oil and natural gas properties in the Permian Basin region of Southeast New Mexico and West
Texas.
Note B. Summary of significant accounting policies
Principles of consolidation. The consolidated financial statements of the Company include the
accounts of the Company and its wholly-owned subsidiaries. All intercompany balances and
transactions have been eliminated.
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 (U.S. GAAP) requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and expenses during the
reporting 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 and
commodity price outlooks. Other significant estimates include, but are not limited to, asset
retirement obligations, fair value of derivative financial instruments, purchase price allocations
for business combinations and fair value of stock-based compensation.
Interim financial statements. The accompanying consolidated financial statements of the
Company have not been audited by the Companys independent registered public accounting firm,
except that the consolidated balance sheet at December 31, 2009 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 Companys financial
position at September 30, 2010, its results of operations for the three and nine months ended
September 30, 2010 and 2009 and its cash flows for the nine months ended September 30, 2010 and
2009. 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 or omitted from these consolidated financial
statements. Accordingly, these consolidated financial statements should be read with the audited
consolidated financial statements and notes thereto included in the Companys Annual Report on Form
10-K for the year ended December 31, 2009.
Deferred loan costs. Deferred loan costs are stated at cost, net of amortization, which is
computed using the effective interest and straight-line methods.
5
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Future amortization expense of deferred loan costs at September 30, 2010 was as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2010 |
|
$ |
1,232 |
|
2011 |
|
|
4,973 |
|
2012 |
|
|
5,057 |
|
2013 |
|
|
3,433 |
|
2014 |
|
|
1,132 |
|
Thereafter |
|
|
3,717 |
|
|
|
|
|
Total |
|
$ |
19,544 |
|
|
|
|
|
Intangible assets. The Company capitalized certain operating rights acquired in 2008. The
gross operating rights, which have no residual value, are amortized over the estimated economic
life of approximately 25 years. Impairment will be assessed if indicators of potential impairment
exist or when there is a material change in the remaining useful economic life. The following table
reflects the gross and net intangible assets at September 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Gross intangible operating rights |
|
$ |
38,717 |
|
|
$ |
38,717 |
|
Accumulated amortization |
|
|
(3,357 |
) |
|
|
(2,195 |
) |
|
|
|
|
|
|
|
Net intangible operating rights |
|
$ |
35,360 |
|
|
$ |
36,522 |
|
|
|
|
|
|
|
|
The following table reflects amortization expense for the three and nine months ended
September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
|
Amortization expense |
|
$ |
388 |
|
|
$ |
387 |
|
|
$ |
1,162 |
|
|
$ |
1,168 |
|
6
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table reflects the estimated aggregate amortization expense for each of the
periods presented below at September 30, 2010:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2010 |
|
$ |
386 |
|
2011 |
|
|
1,549 |
|
2012 |
|
|
1,549 |
|
2013 |
|
|
1,549 |
|
2014 |
|
|
1,549 |
|
Thereafter |
|
|
28,778 |
|
|
|
|
|
Total |
|
$ |
35,360 |
|
|
|
|
|
Oil and natural gas sales and imbalances. Oil and natural gas revenues are recorded at the
time of delivery of such products to pipelines for the account of the purchaser or at the time of
physical transfer of such products to the purchaser. The Company follows the sales method of
accounting for oil and natural gas sales, recognizing revenues based on the Companys share of
actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are
generated on properties for which two or more owners have the right to take production in-kind
and, in doing so, take more or less than their respective entitled percentage. Imbalances are
tracked by well, but the Company does not record any receivable from or payable to the other owners
unless the imbalance has reached a level at which it exceeds the remaining reserves in the
respective well. If reserves are insufficient to offset the imbalance and the Company is in an
overtake position, a liability is recorded for the amount of shortfall in reserves valued at a
contract price or the market price in effect at the time the imbalance is generated. If the Company
is in an undertake position, a receivable is recorded for an amount that is reasonably expected to
be received, not to exceed the current market value of such imbalance.
The following tables reflect the Companys natural gas imbalance positions at September 30,
2010 and December 31, 2009 as well as amounts reflected in oil and natural gas production expense
for the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
(dollars in thousands) |
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
Natural gas imbalance receivable (included in other assets) |
|
$ |
432 |
|
|
$ |
444 |
|
Undertake position (Mcf) |
|
|
|
|
|
|
|
|
|
|
96,002 |
|
|
|
98,584 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas imbalance liability (included in asset retirement obligations and other
long-term liabilities) |
|
$ |
512 |
|
|
$ |
533 |
|
Overtake position (Mcf) |
|
|
|
|
|
|
|
|
|
|
96,483 |
|
|
|
101,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
(dollars in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Value of net undertake arising during the period decreasing
oil and natural gas
production expense |
|
$ |
(14 |
) |
|
$ |
(9 |
) |
|
$ |
(9 |
) |
|
$ |
(49 |
) |
Net undertake position arising during the period (Mcf) |
|
|
(3,221 |
) |
|
|
(1,882 |
) |
|
|
(2,213 |
) |
|
|
(11,951 |
) |
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price per share of the aggregate treasury
shares held.
7
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
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 $3.5 million and $3.2 million for the three
months ended September 30, 2010 and 2009, respectively, and $10.0 million and $8.6 million for the
nine months ended September 30, 2010 and 2009, respectively.
Recent accounting pronouncements.
Various topics. In February 2010, the Financial Accounting Standards Board (the FASB) issued
an update to various topics, which eliminated outdated provisions and inconsistencies in the
Accounting Standards Codification (the Codification), and clarified certain guidance to reflect
the FASBs original intent. The update is effective for the first reporting period, including
interim periods, beginning after issuance of the update, except for the amendments affecting
embedded derivatives and reorganizations. In addition to amending the Codification, the FASB made
corresponding changes to the legacy accounting literature to facilitate historical research. These
changes are included in an appendix to the update. The Company adopted the update effective January
1, 2010, and the adoption did not have a significant impact on the Companys consolidated financial
statements.
Accounting for extractive activities. In April 2010, the FASB issued an amendment to a
paragraph in the accounting standard for oil and natural gas extractive activities accounting. The
standard adds to the Codification the SECs Modernization of Oil and Gas Reporting release. The
Company adopted the update effective April 20, 2010, and the adoption did not have a significant
impact on the Companys consolidated financial statements.
Note C. 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. The capitalized exploratory well costs are
presented in unproved properties in the consolidated balance sheets. If the exploratory well is
determined to be impaired, the well costs are charged to expense.
The following table reflects the Companys capitalized exploratory well activity during the
three and nine months ended September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
(in thousands) |
|
September 30, 2010 |
|
|
September 30, 2010 |
|
|
Beginning capitalized exploratory well costs |
|
$ |
32,862 |
|
|
$ |
8,668 |
|
Additions to exploratory well costs pending the
determination of proved reserves |
|
|
60,649 |
|
|
|
125,145 |
|
Reclassifications due to determination of proved reserves |
|
|
(62,488 |
) |
|
|
(102,790 |
) |
Exploratory well costs charged to expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending capitalized exploratory well costs |
|
$ |
31,023 |
|
|
$ |
31,023 |
|
|
|
|
|
|
|
|
8
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table provides an aging, at September 30, 2010 and December 31, 2009, of
capitalized exploratory well costs based on the date drilling was completed:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Wells in drilling progress |
|
$ |
9,731 |
|
|
$ |
1,767 |
|
Capitalized exploratory well costs that have been
capitalized for a period of one year or less |
|
|
21,292 |
|
|
|
6,901 |
|
Capitalized exploratory well costs that have been
capitalized for a period greater than one year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalized exploratory well costs |
|
$ |
31,023 |
|
|
$ |
8,668 |
|
|
|
|
|
|
|
|
At September 30, 2010, the Company had 41 gross exploratory wells waiting on their completion,
including 28 wells in the Texas Permian area, 11 wells in the New Mexico Permian area and two wells
in the emerging plays area.
Note D. Business combinations
Wolfberry acquisitions. In December 2009, together with the acquisition of related additional
interests that closed in 2010, the Company closed two acquisitions (the Wolfberry Acquisitions)
of interests in producing and non-producing assets in the Wolfberry play in the Permian Basin for
approximately $270.7 million. The Wolfberry Acquisitions were primarily funded with borrowings
under the Companys credit facility. The Companys 2009 results of operations do not include any
production, revenues or costs from the Wolfberry Acquisitions.
The following table represents the allocation of the total purchase price of the Wolfberry
Acquisitions to the acquired assets and liabilities. The allocation represents the fair values
assigned to each of the assets acquired and liabilities assumed:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Fair value of the Wolfberry Acquisitions net assets: |
|
|
|
|
Proved oil and natural gas properties |
|
$ |
212,987 |
|
Unproved oil and natural gas properties |
|
|
58,222 |
|
|
|
|
|
Total assets acquired |
|
|
271,209 |
|
|
|
|
|
|
Asset retirement obligations assumed |
|
|
(464 |
) |
|
|
|
|
Net purchase price |
|
$ |
270,745 |
|
|
|
|
|
Note E. Asset retirement obligations
The Companys asset retirement obligations represent the estimated present value of the
estimated cash flows the Company will incur to plug, abandon and remediate its producing properties
at the end of their productive lives, in accordance with applicable state laws. The Company does
not provide for a market risk premium associated with asset retirement obligations because a
reliable estimate cannot be determined. The Company has no assets that are legally restricted for
purposes of settling asset retirement obligations.
9
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table summarizes the Companys asset retirement obligation transactions recorded
during the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Asset retirement obligations, beginning of period |
|
$ |
22,057 |
|
|
$ |
14,386 |
|
|
$ |
22,754 |
|
|
$ |
16,809 |
|
Liabilities incurred from new wells |
|
|
1,144 |
|
|
|
132 |
|
|
|
2,255 |
|
|
|
402 |
|
Accretion expense |
|
|
405 |
|
|
|
220 |
|
|
|
1,177 |
|
|
|
799 |
|
Disposition of wells |
|
|
|
|
|
|
(81 |
) |
|
|
|
|
|
|
(223 |
) |
Liabilities settled upon plugging and
abandoning wells |
|
|
(522 |
) |
|
|
(630 |
) |
|
|
(819 |
) |
|
|
(983 |
) |
Revision of estimates |
|
|
(626 |
) |
|
|
107 |
|
|
|
(2,909 |
) |
|
|
(2,670 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of period |
|
$ |
22,458 |
|
|
$ |
14,134 |
|
|
$ |
22,458 |
|
|
$ |
14,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note F. Stockholders equity
Equity issuance. On February 1, 2010, the Company issued 5,347,500 shares of its common stock
at $42.75 per share. After deducting underwriting discounts of approximately $9.1 million and
transaction costs, the Company received net proceeds of approximately $219.3 million. The net
proceeds from this offering were used to repay a portion of the borrowings under the Companys
credit facility.
Private placement of equity. On July 19, 2010, the Company entered into a Common Stock
Purchase Agreement (the Purchase Agreement) with certain third-party accredited investors (the
Purchasers) to sell 6,622,517 shares of its common stock at a price of $45.30 per share in a
private placement (the Private Placement) for aggregate cash consideration of approximately $300
million. Also, the Company entered into a registration rights agreement with the investors. The
Company paid approximately $7.3 million in transaction costs, which includes the placement agent
fee. The common stock was issued and sold simultaneously with the closing of the acquisition of
substantially all of the oil and natural gas properties and related assets owned by Marbob Energy
Corporation and certain affiliated entities (collectively, Marbob) (the Marbob Acquisition) on
October 7, 2010 (See Note Q). The Company used the net proceeds to finance a portion of the Marbob
Acquisition.
Treasury stock. The restrictions on certain restricted stock awards issued to certain of the
Companys officers, directors and key employees lapsed, and upon the lapse of restrictions these
individuals became liable for income taxes on the value of such shares. In accordance with the
Companys 2006 Stock Incentive Plan and the applicable restricted stock award agreements, some of
such persons elected to deliver shares of the Companys common stock to the Company in exchange for
cash used to satisfy such tax liability. In total, at September 30, 2010 and December 31, 2009, the
Company had acquired 27,044 and 12,380 shares, respectively, that were held as treasury stock in
the approximate amounts of $1.2 million and $0.4 million, respectively.
Note G. Incentive plans
Defined contribution plan. The Company sponsors a 401(k) defined contribution plan for the
benefit of substantially all employees and maintained certain other acquired plans. Currently, the
Company matches 100 percent of employee contributions, not to exceed 6 percent of the employees
annual salary. The Company contributions to the plans for the three months ended September 30, 2010
and 2009, were approximately $0.3 million and $0.3 million, respectively, and approximately $0.4
million and $0.8 million for the nine months ended September 30, 2010 and 2009, respectively.
10
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Stock incentive plan. The Companys 2006 Stock Incentive Plan (together with applicable stock
option agreements and restricted stock agreements, the Plan) provides for granting stock options
and restricted stock awards to employees and individuals associated with the Company. The
following table shows the number of existing awards and awards available under the Plan at
September 30, 2010:
|
|
|
|
|
|
|
Number of |
|
|
Common Shares |
|
Approved and authorized awards |
|
|
5,850,000 |
|
Stock option grants, net of forfeitures |
|
|
(3,463,720 |
) |
Restricted stock grants, net of forfeitures |
|
|
(1,085,140 |
) |
|
|
|
|
|
Awards available for future grant |
|
|
1,301,140 |
|
|
|
|
|
|
Restricted stock awards. All restricted shares are treated as issued and outstanding in the
accompanying consolidated balance sheets. Holders of restricted stock are eligible to vote and
receive dividends, if any. If an employee terminates employment prior the restriction lapse date,
the awarded shares that have not vested as of the date of termination of employment are forfeited
and cancelled and are no longer considered issued and outstanding. A summary of the Companys
restricted stock awards activity under the Plan for the nine months ended September 30, 2010 is
presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
Grant Date |
|
|
Restricted |
|
Fair Value |
|
|
Shares |
|
Per Share |
|
Restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009 |
|
|
497,257 |
|
|
|
|
|
Shares granted |
|
|
288,315 |
|
|
$ |
50.20 |
|
Shares cancelled / forteited |
|
|
(8,229 |
) |
|
|
|
|
Lapse of restrictions |
|
|
(168,295 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2010 |
|
|
609,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table summarizes information about stock-based compensation for the Companys
restricted stock awards for the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Grant date fair value for awards during the period and change in fair value due to modification: |
Employee grants |
|
$ |
1,916 |
|
|
$ |
382 |
|
|
$ |
9,257 |
(a) |
|
$ |
5,002 |
|
Officer and director grants |
|
|
215 |
|
|
|
84 |
|
|
|
5,290 |
|
|
|
1,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,131 |
|
|
$ |
466 |
|
|
$ |
14,547 |
|
|
$ |
6,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from restricted stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
1,450 |
|
|
$ |
792 |
|
|
$ |
3,568 |
|
|
$ |
2,185 |
|
Officer and director grants |
|
|
1,138 |
|
|
|
441 |
|
|
|
3,134 |
|
|
|
1,248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,588 |
|
|
$ |
1,233 |
|
|
$ |
6,702 |
|
|
$ |
3,433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to restricted stock |
|
$ |
972 |
|
|
$ |
137 |
|
|
$ |
2,525 |
|
|
$ |
1,064 |
|
Deductions in current taxable income related to restricted stock |
|
$ |
6,227 |
|
|
$ |
699 |
|
|
$ |
9,186 |
|
|
$ |
5,066 |
|
|
|
|
(a) |
|
Includes effects of modifications to certain stock-based awards for the nine months ended September 30, 2009. |
Stock option awards. A summary of the Companys stock option awards activity under the
Plan for the nine months ended September 30, 2010 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
|
|
Number of |
|
Exercise |
|
|
Options |
|
Price |
|
Stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009 |
|
|
2,156,503 |
|
|
$ |
14.11 |
|
Options granted |
|
|
|
|
|
$ |
|
|
Options exercised |
|
|
(465,365 |
) |
|
$ |
9.39 |
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2010 |
|
|
1,691,138 |
|
|
$ |
15.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at end of period |
|
|
1,287,609 |
|
|
$ |
13.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period |
|
|
875,525 |
|
|
$ |
16.09 |
|
|
|
|
|
|
|
|
|
|
12
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table summarizes information about the Companys vested and exercisable stock
options outstanding at September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
|
|
Number |
|
|
Remaining |
|
|
Average |
|
|
|
|
|
|
|
|
of Stock |
|
|
Contractual |
|
|
Exercise |
|
|
Intrinsic |
|
|
|
|
|
Options |
|
|
Life |
|
|
Price |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
Vested options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$8.00 |
|
|
584,332 |
|
|
1.74 years |
|
$ |
8.00 |
|
|
$ |
33,991 |
|
Exercise price |
|
$12.00 |
|
|
92,450 |
|
|
4.24 years |
|
$ |
12.00 |
|
|
|
5,008 |
|
Exercise price |
|
$12.50 - $15.50 |
|
|
311,250 |
|
|
6.12 years |
|
$ |
14.49 |
|
|
|
16,086 |
|
Exercise price |
|
$20.00 - $23.00 |
|
|
234,453 |
|
|
7.55 years |
|
$ |
21.67 |
|
|
|
10,433 |
|
Exercise price |
|
$28.00 - $37.27 |
|
|
65,124 |
|
|
7.76 years |
|
$ |
32.00 |
|
|
|
2,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,287,609 |
|
|
4.34 years |
|
$ |
13.56 |
|
|
$ |
67,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise price |
|
$8.00 |
|
|
190,076 |
|
|
2.76 years |
|
$ |
8.00 |
|
|
$ |
11,057 |
|
Exercise price |
|
$12.00 |
|
|
74,622 |
|
|
4.95 years |
|
$ |
12.00 |
|
|
|
4,042 |
|
Exercise price |
|
$12.50 - $15.50 |
|
|
311,250 |
|
|
6.12 years |
|
$ |
14.49 |
|
|
|
16,086 |
|
Exercise price |
|
$20.00 - $23.00 |
|
|
234,453 |
|
|
7.55 years |
|
$ |
21.67 |
|
|
|
10,433 |
|
Exercise price |
|
$28.00 - $37.27 |
|
|
65,124 |
|
|
7.76 years |
|
$ |
32.00 |
|
|
|
2,225 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
875,525 |
|
|
5.80 years |
|
$ |
16.09 |
|
|
$ |
43,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The following table summarizes information about stock-based compensation for stock options
for the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Grant date fair value for awards during the period and change in fair value due to modification: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
|
|
|
$ |
50 |
|
|
$ |
|
|
|
$ |
50 |
|
Officer and director grants (a) |
|
|
|
|
|
|
2,907 |
|
|
|
|
|
|
|
4,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
|
|
|
$ |
2,957 |
|
|
$ |
|
|
|
$ |
4,411 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense from stock options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee grants |
|
$ |
39 |
|
|
$ |
132 |
|
|
$ |
125 |
|
|
$ |
273 |
|
Officer and director grants |
|
|
525 |
|
|
|
1,183 |
|
|
|
2,027 |
|
|
|
2,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
564 |
|
|
$ |
1,315 |
|
|
$ |
2,152 |
|
|
$ |
3,228 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes and other information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit related to stock options |
|
$ |
213 |
|
|
$ |
194 |
|
|
$ |
812 |
|
|
$ |
1,000 |
|
Deductions in current taxable income related to stock
options exercised |
|
$ |
1,548 |
|
|
$ |
1,729 |
|
|
$ |
19,672 |
|
|
$ |
8,886 |
|
|
|
|
(a) |
|
The three and nine months ended September 30, 2009 include effects of modifications to certain stock-based awards. |
The Company used the simplified method that is accepted by the United States Securities and
Exchange Commission (SEC) to calculate the expected term for stock options granted during the
nine months ended September 30, 2009, since it did not have sufficient historical exercise data to
provide a reasonable basis upon which to estimate expected term due to the limited period of time
its shares of common stock have been publicly traded. Expected volatilities are based on a
combination of historical and implied volatilities of comparable companies.
Future stock-based compensation expense. Future stock-based compensation expense based on the
awards outstanding at September 30, 2010 is summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted |
|
|
Stock |
|
|
|
|
(in thousands) |
|
Stock |
|
|
Options |
|
|
Total |
|
|
Remaining 2010 |
|
$ |
2,599 |
|
|
$ |
501 |
|
|
$ |
3,100 |
|
2011 |
|
|
6,914 |
|
|
|
879 |
|
|
|
7,793 |
|
2012 |
|
|
4,039 |
|
|
|
184 |
|
|
|
4,223 |
|
2013 |
|
|
1,594 |
|
|
|
15 |
|
|
|
1,609 |
|
2014 |
|
|
90 |
|
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
15,236 |
|
|
$ |
1,579 |
|
|
$ |
16,815 |
|
|
|
|
|
|
|
|
|
|
|
14
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note H. Disclosures about fair value of financial instruments
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 companys 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, investments and interest
rate swaps. The Companys valuation models are primarily industry-standard models that
consider various inputs including: (i) quoted forward prices for commodities, (ii) time
value and (iii) current market and contractual prices for the underlying instruments, as
well as other relevant economic measures. The Company utilizes its counterparties
valuations to assess the reasonableness of its prices and valuation techniques. |
|
|
|
Level 3: |
|
Measured based on 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). Level 3 instruments primarily include
derivative instruments, such as commodity price collars and floors, as well as
investments. The Companys 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. Although the
Company utilizes its counterparties valuations to assess the reasonableness of its
prices and valuation techniques, the Company does not have sufficient corroborating
market evidence to support classifying these assets and liabilities as Level 2. |
15
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The fair value input hierarchy level to which an asset or liability measurement in its
entirety falls is determined based on the lowest level input that is significant to the measurement
in its entirety. The following table presents the Companys assets and liabilities that are
measured at fair value on a recurring basis at September 30, 2010, for each of the fair value
hierarchy levels:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at Reporting Date Using |
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
Fair Value at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
September 30, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2010 |
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
90,616 |
|
|
$ |
|
|
|
$ |
90,616 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
5,651 |
|
|
|
5,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90,616 |
|
|
|
5,651 |
|
|
|
96,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(83,879 |
) |
|
|
|
|
|
|
(83,879 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(4,816 |
) |
|
|
|
|
|
|
(4,816 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(6,945 |
) |
|
|
|
|
|
|
(6,945 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(95,640 |
) |
|
|
|
|
|
|
(95,640 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets (liabilities) |
|
$ |
|
|
|
$ |
(5,024 |
) |
|
$ |
5,651 |
|
|
$ |
627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth a reconciliation of changes in the fair value of financial
assets (liabilities) classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
(945 |
) |
Realized and unrealized gains, net |
|
|
9,730 |
|
Settlements (receipts), net |
|
|
(3,134 |
) |
|
|
|
|
Balance at September 30, 2010 |
|
$ |
5,651 |
|
|
|
|
|
|
|
|
|
|
Total gains for the period included in earnings attributable to the change in
unrealized gains relating to assets
(liabilities) still held at the reporting date |
|
$ |
6,596 |
|
|
|
|
|
16
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following table presents the carrying amounts and fair values of the Companys financial
instruments at September 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010 |
|
December 31, 2009 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
(in thousands) |
|
Value |
|
Value |
|
Value |
|
Value |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
43,444 |
|
|
$ |
43,444 |
|
|
$ |
24,923 |
|
|
$ |
24,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
$ |
42,817 |
|
|
$ |
42,817 |
|
|
$ |
91,756 |
|
|
$ |
91,756 |
|
Credit facility |
|
$ |
392,500 |
|
|
$ |
396,491 |
|
|
$ |
550,000 |
|
|
$ |
528,849 |
|
8.625% senior notes due 2017 |
|
$ |
296,120 |
|
|
$ |
318,000 |
|
|
$ |
295,836 |
|
|
$ |
315,000 |
|
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.
Credit facility. The fair value of the Companys credit facility is estimated by discounting
the principal and interest payments at the Companys credit adjusted discount rate at the reporting
date.
Senior notes. The fair value of the Companys senior notes is based on quoted market prices.
17
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Derivative instruments. The fair value of the Companys derivative instruments are 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 Companys 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 (i) summarize the
valuation of each of the Companys financial instruments by required pricing levels and (ii)
summarize 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
Companys consolidated balance sheets at September 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
Fair Value |
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
September 30, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2010 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
$ |
|
|
|
$ |
47,557 |
|
|
$ |
|
|
|
$ |
47,557 |
|
Commodity derivative price collar
contracts |
|
|
|
|
|
|
|
|
|
|
5,651 |
|
|
|
5,651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47,557 |
|
|
|
5,651 |
|
|
|
53,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
43,059 |
|
|
|
|
|
|
|
43,059 |
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,059 |
|
|
|
|
|
|
|
43,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
(48,233 |
) |
|
|
|
|
|
|
(48,233 |
) |
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
(4,044 |
) |
|
|
|
|
|
|
(4,044 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(4,696 |
) |
|
|
|
|
|
|
(4,696 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(56,973 |
) |
|
|
|
|
|
|
(56,973 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap
contracts |
|
|
|
|
|
|
(35,646 |
) |
|
|
|
|
|
|
(35,646 |
) |
Commodity derivative basis swap
contracts |
|
|
|
|
|
|
(772 |
) |
|
|
|
|
|
|
(772 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(2,249 |
) |
|
|
|
|
|
|
(2,249 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,667 |
) |
|
|
|
|
|
|
(38,667 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets |
|
$ |
|
|
|
$ |
(5,024 |
) |
|
$ |
5,651 |
|
|
$ |
627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial assets, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3,765 |
) |
|
(b) Total noncurrent financial assets, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Total |
|
|
|
Quoted Prices in |
|
|
Other |
|
|
Significant |
|
|
Fair Value |
|
|
|
Active Markets for |
|
|
Observable |
|
|
Unobservable |
|
|
at |
|
|
|
Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
|
December 31, |
|
(in thousands) |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
2009 |
|
|
Assets (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
$ |
|
|
|
$ |
13,850 |
|
|
$ |
|
|
|
$ |
13,850 |
|
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
134 |
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,850 |
|
|
|
134 |
|
|
|
13,984 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
35,016 |
|
|
|
|
|
|
|
35,016 |
|
Interest rate derivative swap contracts |
|
|
|
|
|
|
1,369 |
|
|
|
|
|
|
|
1,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,385 |
|
|
|
|
|
|
|
36,385 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(65,351 |
) |
|
|
|
|
|
|
(65,351 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(5,254 |
) |
|
|
|
|
|
|
(5,254 |
) |
Interest rate derivative swap contracts |
|
|
|
|
|
|
(3,870 |
) |
|
|
|
|
|
|
(3,870 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(619 |
) |
|
|
(619 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(74,475 |
) |
|
|
(619 |
) |
|
|
(75,094 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent:(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts |
|
|
|
|
|
|
(38,259 |
) |
|
|
|
|
|
|
(38,259 |
) |
Commodity derivative basis swap contracts |
|
|
|
|
|
|
(3,389 |
) |
|
|
|
|
|
|
(3,389 |
) |
Commodity derivative price collar contracts |
|
|
|
|
|
|
|
|
|
|
(460 |
) |
|
|
(460 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(41,648 |
) |
|
|
(460 |
) |
|
|
(42,108 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities |
|
$ |
|
|
|
$ |
(65,888 |
) |
|
$ |
(945 |
) |
|
$ |
(66,833 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Total current financial liabilities, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(61,110 |
) |
(b) Total noncurrent financial liabilities, gross basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,723 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(66,833 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of derivative instruments reported in the Companys consolidated balance
sheets are subject to netting arrangements and qualify for net presentation. The following
table reports the net basis derivative fair values as reported in the consolidated balance
sheets at September 30, 2010 and December 31, 2009: |
19
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Consolidated Balance Sheet Classification: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
23,339 |
|
|
$ |
1,309 |
|
Liabilities |
|
|
(27,104 |
) |
|
|
(62,419 |
) |
|
|
|
|
|
|
|
Net current |
|
$ |
(3,765 |
) |
|
$ |
(61,110 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts: |
|
|
|
|
|
|
|
|
Assets |
|
$ |
20,105 |
|
|
$ |
23,614 |
|
Liabilities |
|
|
(15,713 |
) |
|
|
(29,337 |
) |
|
|
|
|
|
|
|
Net noncurrent |
|
$ |
4,392 |
|
|
$ |
(5,723 |
) |
|
|
|
|
|
|
|
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
Companys consolidated balance sheets. The following methods and assumptions were used to estimate
the fair values:
Impairments of long-lived assets The Company reviews its long-lived assets to be held and
used, including proved oil and natural gas properties, whenever events or circumstances indicate
that the carrying value of those assets may not be recoverable. 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. In that circumstance, the Company 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 reviews its
oil and natural gas properties by amortization base or by individual well for those wells not
constituting part of an amortization base. For each property determined to be impaired, an
impairment loss equal to the difference between the carrying value of the properties and the
estimated fair value (discounted future cash flows) of the properties would be recognized at that
time. Estimating future cash flows involves the use of judgments, including estimation of the
proved and unproved oil and natural gas reserve quantities, timing of development and production,
expected future commodity prices, capital expenditures and production costs.
The Company periodically reviews its proved oil and natural gas properties that are sensitive
to oil and natural gas prices for impairment. Due primarily to downward adjustments to the
economically recoverable resource potential associated with declines in commodity prices and well
performance, the Company recognized impairment expense related to its proved oil and natural gas
properties. The following table reports the carrying amounts, estimated fair values and impairment
expense of long-lived assets for the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying |
|
Estimated |
|
Impairment |
(in thousands) |
|
Amount |
|
Fair Value |
|
Expense |
|
Three Months Ended September 30, 2010 |
|
$ |
4,083 |
|
|
$ |
2,161 |
|
|
$ |
1,922 |
|
Three Months Ended September 30, 2009 |
|
$ |
1,760 |
|
|
$ |
629 |
|
|
$ |
1,131 |
|
Nine Months Ended September 30, 2010 |
|
$ |
17,859 |
|
|
$ |
8,625 |
|
|
$ |
9,234 |
|
Nine Months Ended September 30, 2009 |
|
$ |
15,935 |
|
|
$ |
6,249 |
|
|
$ |
9,686 |
|
20
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Asset retirement obligations The Company estimates the fair value of asset retirement
obligations based on discounted cash flow projections using numerous estimates, assumptions and
judgments regarding such factors as the existence of a legal obligation for an asset retirement
obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and
inflation rates. See Note E for a summary of changes in asset retirement obligations.
Measurement information for assets that are measured at fair value on a nonrecurring basis was
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
Significant |
|
|
|
|
|
|
Quoted Prices in |
|
Other |
|
Significant |
|
|
|
|
Active Markets for |
|
Observable |
|
Unobservable |
|
Total |
|
|
Identical Assets |
|
Inputs |
|
Inputs |
|
Impairment |
(in thousands) |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Loss |
|
Three Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
2,161 |
|
|
$ |
1,922 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
1,144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
629 |
|
|
$ |
1,131 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
8,625 |
|
|
$ |
9,234 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
2,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of long-lived assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
6,249 |
|
|
$ |
9,686 |
|
Asset retirement obligations incurred in current period |
|
|
|
|
|
|
|
|
|
|
402 |
|
|
|
|
|
Note I. Derivative financial instruments
The Company uses derivative financial contracts to manage exposures to commodity price and
interest rate fluctuations. Commodity hedges 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 Companys
capital budget and expenditure plans and (iii) support the economics associated with acquisitions.
Interest rate hedges are used to mitigate the cash flow risk associated with rising interest rates.
The Company does not enter into derivative financial instruments for speculative or trading
purposes. The Company also may enter into physical delivery contracts to effectively provide
commodity price hedges. Because these 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 Companys consolidated financial statements.
Currently, 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.
21
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
New commodity derivative contracts in the first nine months of 2010. During the nine months
ended September 30, 2010, the Company entered into additional commodity derivative contracts to
hedge a portion of its estimated future production. The following table summarizes information
about these additional commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
670,000 |
|
|
$ |
83.72 |
(a) |
|
|
1/1/10 12/31/10 |
|
Price swap |
|
|
195,000 |
|
|
$ |
76.85 |
(a) |
|
|
3/1/10 12/31/10 |
|
Price swap |
|
|
1,463,000 |
|
|
$ |
88.63 |
(a) |
|
|
5/1/10 12/31/10 |
|
Price swap |
|
|
3,714,000 |
|
|
$ |
85.15 |
(a) |
|
|
1/1/11 12/31/11 |
|
Price swap |
|
|
3,573,000 |
|
|
$ |
88.56 |
(a) |
|
|
1/1/12 12/31/12 |
|
Price swap |
|
|
261,000 |
|
|
$ |
82.50 |
(a) |
|
|
7/1/12 12/31/12 |
|
Price swap |
|
|
1,380,000 |
|
|
$ |
82.58 |
(a) |
|
|
1/1/13 12/31/13 |
|
Price swap |
|
|
1,248,000 |
|
|
$ |
83.94 |
(a) |
|
|
1/1/14 12/31/14 |
|
Price swap |
|
|
600,000 |
|
|
$ |
84.50 |
(a) |
|
|
1/1/15 6/30/15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
418,000 |
|
|
$ |
5.99 |
(b) |
|
|
2/1/10 12/31/10 |
|
Price swap |
|
|
1,250,000 |
|
|
$ |
5.55 |
(b) |
|
|
3/1/10 12/31/10 |
|
Price swap |
|
|
5,076,000 |
|
|
$ |
6.14 |
(b) |
|
|
1/1/11 12/31/11 |
|
Price swap |
|
|
300,000 |
|
|
$ |
6.54 |
(b) |
|
|
1/1/12 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
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. |
22
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Commodity derivative contracts at September 30, 2010. The following table sets forth the
Companys outstanding commodity derivative contracts at September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
Total |
|
Oil Swaps: (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,651,936 |
|
|
|
1,651,936 |
|
Price per Bbl |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
76.43 |
|
|
$ |
76.43 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
1,858,436 |
|
|
|
1,781,436 |
|
|
|
1,665,436 |
|
|
|
1,567,436 |
|
|
|
6,872,744 |
|
Price per Bbl |
|
$ |
81.34 |
|
|
$ |
81.54 |
|
|
$ |
81.77 |
|
|
$ |
82.00 |
|
|
$ |
81.65 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
1,113,000 |
|
|
|
1,098,000 |
|
|
|
1,069,000 |
|
|
|
1,058,000 |
|
|
|
4,338,000 |
|
Price per Bbl |
|
$ |
92.37 |
|
|
$ |
92.52 |
|
|
$ |
92.99 |
|
|
$ |
93.14 |
|
|
$ |
92.75 |
|
2013: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
345,000 |
|
|
|
345,000 |
|
|
|
345,000 |
|
|
|
345,000 |
|
|
|
1,380,000 |
|
Price per Bbl |
|
$ |
82.58 |
|
|
$ |
82.58 |
|
|
$ |
82.58 |
|
|
$ |
82.58 |
|
|
$ |
82.58 |
|
2014: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
312,000 |
|
|
|
312,000 |
|
|
|
312,000 |
|
|
|
312,000 |
|
|
|
1,248,000 |
|
Price per Bbl |
|
$ |
83.94 |
|
|
$ |
83.94 |
|
|
$ |
83.94 |
|
|
$ |
83.94 |
|
|
$ |
83.94 |
|
2015: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl) |
|
|
300,000 |
|
|
|
300,000 |
|
|
|
|
|
|
|
|
|
|
|
600,000 |
|
Price per Bbl |
|
$ |
84.50 |
|
|
$ |
84.50 |
|
|
|
|
|
|
|
|
|
|
$ |
84.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,258,000 |
|
|
|
2,258,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.03 |
|
|
$ |
6.03 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,569,000 |
|
|
|
3,069,000 |
|
|
|
3,069,000 |
|
|
|
3,069,000 |
|
|
|
10,776,000 |
|
Price per MMBtu |
|
$ |
6.36 |
|
|
$ |
6.62 |
|
|
$ |
6.62 |
|
|
$ |
6.62 |
|
|
$ |
6.58 |
|
2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
300,000 |
|
Price per MMBtu |
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
$ |
6.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
|
|
1,500,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.00 - $6.80 |
|
|
$ |
6.00 - $6.80 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,500,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,500,000 |
|
Price per MMBtu |
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
6.00 - $6.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Swaps: (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,100,000 |
|
|
|
2,100,000 |
|
Price per MMBtu |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.85 |
|
|
$ |
0.85 |
|
2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu) |
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
1,800,000 |
|
|
|
7,200,000 |
|
Price per MMBtu |
|
$ |
0.87 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.76 |
|
|
$ |
0.79 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
monthly average futures price. |
|
(b) |
|
The index prices for the natural gas price swaps and collars are based on the NYMEX-Henry Hub
last trading day futures price. |
|
(c) |
|
The basis differential between the El Paso Permian delivery point and NYMEX Henry Hub delivery
point. |
23
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Interest rate derivative contracts. The Company has interest rate swaps which fix the
LIBOR interest rate on $300 million of the Companys bank debt at 1.90 percent for three years
beginning in May 2009. For this portion of the Companys bank debt, the all-in interest rate will
be calculated by adding the fixed rate of 1.90 percent to a margin that ranges from 2.00 percent to
3.00 percent, depending on the amount of bank debt outstanding.
The following table summarizes the gains and losses reported in earnings related to the
commodity and interest rate derivative instruments for the three and nine months ended September
30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Gain (loss) on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments on) receipts from derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
1,034 |
|
|
$ |
13,971 |
|
|
$ |
(11,951 |
) |
|
$ |
70,383 |
|
Natural gas |
|
|
4,258 |
|
|
|
3,395 |
|
|
|
10,378 |
|
|
|
9,227 |
|
Interest rate derivatives |
|
|
(1,224 |
) |
|
|
(1,241 |
) |
|
|
(3,658 |
) |
|
|
(2,020 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
(79,815 |
) |
|
|
(12,821 |
) |
|
|
40,926 |
|
|
|
(156,920 |
) |
Natural gas |
|
|
10,300 |
|
|
|
(8,442 |
) |
|
|
30,978 |
|
|
|
(13,460 |
) |
Interest rate derivatives |
|
|
(660 |
) |
|
|
(2,645 |
) |
|
|
(4,444 |
) |
|
|
(1,645 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives not designated as hedges |
|
$ |
(66,107 |
) |
|
$ |
(7,783 |
) |
|
$ |
62,229 |
|
|
$ |
(94,435 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
All of the Companys derivative contracts at September 30, 2010 are expected to settle by
June 30, 2015.
Note J. Debt
The Companys debt consisted of the following at September 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Credit facility |
|
$ |
392,500 |
|
|
$ |
550,000 |
|
8.625% unsecured senior notes due 2017 |
|
|
300,000 |
|
|
|
300,000 |
|
Less: unamortized original issue discount |
|
|
(3,880 |
) |
|
|
(4,164 |
) |
Less: current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
688,620 |
|
|
$ |
845,836 |
|
|
|
|
|
|
|
|
Credit facility. The Companys credit facility, as amended (the Credit Facility), has a
maturity date of July 31, 2013. At September 30, 2010, the Companys borrowing base was $1.2
billion, it had letters of credit outstanding under the Credit Facility of approximately $25,000,
and its availability to borrow additional funds was approximately $807.5 million. On October 7,
2010, in connection with the closing of the Marbob Acquisition (See Note Q), the Company entered
into an amendment to its Credit Facility to increase the borrowing base from $1.2 billion to $2.0
billion. The next scheduled borrowing base redetermination will be in April 2011. Between scheduled
borrowing base redeterminations, the Company and, if requested by 66 2/3 percent of the lenders,
the lenders may each request one special redetermination.
24
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Advances on the Credit Facility bear interest, at the Companys option, based on (i) the prime
rate of JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at September 30, 2010) or (ii) a
Eurodollar rate (substantially equal to the London Interbank Offered Rate). At September 30, 2010,
the interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest
margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per
annum depending on the debt balance outstanding. At September 30, 2010, the Company paid
commitment fees on the unused portion of the available borrowing base of 50 basis points per annum.
The Credit Facility also includes a same-day advance facility under which the Company may
borrow funds from the administrative agent. Same-day advances cannot exceed $25 million and the
maturity dates cannot exceed fourteen days. The interest rate on the same-day advance facility is
the JPM Prime Rate plus the applicable interest margin.
The Companys obligations under the Credit Facility are secured by a first lien on
substantially all of the Companys oil and natural gas properties. In addition, all of the
Companys subsidiaries are guarantors and all general partner, limited partner and membership
interests in the Companys subsidiaries owned by the Company have been pledged to secure borrowings
under the Credit Facility. The Credit Facility contains various restrictive covenants and
compliance requirements which include (a) maintenance of certain financial ratios, including (i) a
quarterly ratio of total debt to consolidated earnings before interest expense, income taxes,
depletion, depreciation, and amortization, exploration expense and other noncash income and
expenses to be no greater than 4.0 to 1.0, and (ii) a ratio of current assets to current
liabilities, excluding noncash assets and liabilities related to financial derivatives and asset
retirement obligations and including the unfunded amounts under the Credit Facility, to be no less
than 1.0 to 1.0; (b) limits on the incurrence of additional indebtedness and certain types of
liens; (c) restrictions as to mergers, combinations and dispositions of assets; and (d)
restrictions on the payment of cash dividends. At September 30, 2010, the Company was in compliance
with its covenants under the Credit Facility.
8.625% unsecured senior notes. On September 18, 2009, the Company completed its public
offering of $300 million aggregate principal amount of 8.625% senior notes due 2017 (the Senior
Notes). The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by
all of the Companys subsidiaries.
The Senior Notes will mature on October 1, 2017, and interest is payable on the Senior Notes
each April 1 and October 1. The Company received net proceeds of $288.2 million (net of related
estimated offering costs), which were used to repay a portion of the outstanding borrowings under
the Credit Facility.
The Company may redeem some or all of the Senior Notes at any time on or after October 1, 2013
at the redemption prices specified in the indenture governing the Senior Notes. The Company may
also redeem up to 35 percent of the Senior Notes using all or a portion of the net proceeds of
certain public sales of equity interests completed before October 1, 2012 at a redemption price as
specified in the indenture. If the Company sells certain assets or experiences specific kinds of
change of control, each as described in the indenture, each holder of the Senior Notes will have
the right to require the Company to repurchase the Senior Notes at a purchase price described in
the indenture plus accrued and unpaid interest, if any, to the date of repurchase. At September 30,
2010, the Company was in compliance with its covenants in the indenture governing the Senior Notes.
25
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Future interest expense from the original issue discount on the Senior Notes at September 30,
2010 was as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2010 |
|
$ |
100 |
|
2011 |
|
|
421 |
|
2012 |
|
|
462 |
|
2013 |
|
|
507 |
|
2014 |
|
|
557 |
|
Thereafter |
|
|
1,833 |
|
|
|
|
|
Total |
|
$ |
3,880 |
|
|
|
|
|
Principal maturities of debt. Principal maturities of debt outstanding at September 30, 2010
are as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
2010 |
|
$ |
|
|
2011 |
|
|
|
|
2012 |
|
|
|
|
2013 |
|
|
392,500 |
|
2014 and thereafter |
|
|
300,000 |
|
|
|
|
|
Total |
|
$ |
692,500 |
|
|
|
|
|
Interest expense. The following amounts have been incurred and charged to interest expense
for the three and nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Cash payments for interest |
|
$ |
5,983 |
|
|
$ |
6,395 |
|
|
$ |
27,746 |
|
|
$ |
13,324 |
|
Amortization of original issue discount |
|
|
97 |
|
|
|
13 |
|
|
|
284 |
|
|
|
13 |
|
Amortization of deferred loan costs |
|
|
1,227 |
|
|
|
883 |
|
|
|
3,431 |
|
|
|
2,596 |
|
Write-off of deferred loan costs and
original issue discount |
|
|
|
|
|
|
57 |
|
|
|
|
|
|
|
57 |
|
Net changes in accruals |
|
|
4,792 |
|
|
|
(524 |
) |
|
|
2,951 |
|
|
|
1,422 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest costs incurred |
|
|
12,099 |
|
|
|
6,824 |
|
|
|
34,412 |
|
|
|
17,412 |
|
Less: capitalized interest |
|
|
(63 |
) |
|
|
(15 |
) |
|
|
(119 |
) |
|
|
(33 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
12,036 |
|
|
$ |
6,809 |
|
|
$ |
34,293 |
|
|
$ |
17,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note K. Commitments and contingencies
Severance agreements. The Company has entered into severance and change in control agreements
with all of its senior officers. The current annual salaries for the Companys senior officers
covered under such agreements total approximately $2.1 million.
Indemnification. The Company has agreed to indemnify its directors and officers for 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 Companys 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 quarter-by-quarter basis and will
establish and adjust any reserves as appropriate to reflect its assessment of the then current
status of the matters.
Daywork commitments. The Company periodically enters into contractual arrangements under
which the Company is committed to expend funds to drill wells in the future, including agreements
to secure drilling rig services, which require the Company to make future minimum payments to the
rig operators. The Company records drilling commitments in the periods in which well capital is
incurred or rig services are provided. The following table summarizes the Companys future
drilling commitments at September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period |
|
|
|
|
|
|
Less than |
|
|
1 - 3 |
|
|
3 - 5 |
|
|
More than |
|
(in thousands) |
|
Total |
|
|
1 year |
|
|
years |
|
|
years |
|
|
5 years |
|
|
Daywork drilling contracts with related parties (a) |
|
$ |
1,000 |
|
|
$ |
1,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Other daywork drilling contracts |
|
|
250 |
|
|
|
250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual drilling commitments |
|
$ |
1,250 |
|
|
$ |
1,250 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists of daywork drilling contracts with Silver Oak Drilling, LLC, an affiliate
of Chase Oil Corporation (Chase Oil), a stockholder of the Company. |
27
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
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 September 30, 2010 and 2009 were approximately $0.3 million and $0.7 million,
respectively, and approximately $1.4 million and $1.9 million for the nine months ended September
30, 2010 and 2009, respectively. Future minimum lease commitments under non-cancellable operating
leases at September 30, 2010 were as follows:
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Remaining 2010 |
|
$ |
847 |
|
2011 |
|
|
2,445 |
|
2012 |
|
|
2,199 |
|
2013 |
|
|
2,151 |
|
2014 and thereafter |
|
|
5,903 |
|
|
|
|
|
Total |
|
$ |
13,545 |
|
|
|
|
|
Note L. Income taxes
The Company uses an asset and liability approach for financial accounting and reporting for
income taxes. The Companys objectives of accounting for income taxes are to recognize (i) the
amount of taxes payable or refundable for the current year and (ii) deferred tax liabilities and
assets for the future tax consequences of events that have been recognized in its financial
statements or tax returns. The Company and its subsidiaries file a federal corporate income tax
return on a consolidated basis. The tax returns and the amount of taxable income or loss are
subject to examination by federal and state taxing authorities.
The Company continually assesses both positive and negative evidence to determine whether it
is more likely than not that deferred tax assets can be realized prior to their expiration.
Management monitors Company-specific, oil and natural gas industry and worldwide economic factors
and assesses the likelihood that the Companys net operating loss carryforwards (NOLs) and other
deferred tax attributes in the United States, state, and local tax jurisdictions will be utilized
prior to their expiration. At September 30, 2010, the Company had no valuation allowances related
to its deferred tax assets.
At September 30, 2010, the Company did not have any significant uncertain tax positions
requiring recognition in the financial statements. The tax years 2004 through 2009 remain subject
to examination by the major tax jurisdictions.
28
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Income tax provision. The Companys income tax provision (benefit) and amounts separately
allocated were attributable to the following items for the three and nine months ended September
30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Tax expense (benefit) related to income (loss) from operations |
|
$ |
10,082 |
|
|
$ |
21,824 |
|
|
$ |
124,766 |
|
|
$ |
(11,973 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefits related to stock-based compensation |
|
|
(2,265 |
) |
|
|
(365 |
) |
|
|
(8,968 |
) |
|
|
(3,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7,817 |
|
|
$ |
21,459 |
|
|
$ |
115,798 |
|
|
$ |
(15,330 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys income tax provision (benefit) attributable to income (loss) from
operations consisted of the following for the three and nine months ended September 30, 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
$ |
18 |
|
|
$ |
2,766 |
|
|
$ |
12,524 |
|
|
$ |
8,060 |
|
U.S. state and local |
|
|
529 |
|
|
|
1,099 |
|
|
|
2,254 |
|
|
|
1,807 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
547 |
|
|
|
3,865 |
|
|
|
14,778 |
|
|
|
9,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal |
|
|
8,715 |
|
|
|
15,941 |
|
|
|
98,307 |
|
|
|
(19,162 |
) |
U.S. state and local |
|
|
820 |
|
|
|
2,018 |
|
|
|
11,681 |
|
|
|
(2,678 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,535 |
|
|
|
17,959 |
|
|
|
109,988 |
|
|
|
(21,840 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
10,082 |
|
|
$ |
21,824 |
|
|
$ |
124,766 |
|
|
$ |
(11,973 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
29
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
The Companys provision for income taxes differed from the U.S. federal statutory rate of 35
percent primarily due to state income taxes and non-deductible expenses. The reconciliation between
the tax expense computed by multiplying pretax income by the U.S. federal statutory rate and the
reported amounts of income tax expense (benefit) was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Income (loss) at U.S. federal statutory rate |
|
$ |
10,800 |
|
|
$ |
14,555 |
|
|
$ |
118,038 |
|
|
$ |
(13,529 |
) |
State income taxes (net of federal tax effect) |
|
|
824 |
|
|
|
1,762 |
|
|
|
9,005 |
|
|
|
(830 |
) |
Statutory depletion |
|
|
(54 |
) |
|
|
|
|
|
|
(232 |
) |
|
|
|
|
Nondeductible expense & other |
|
|
(1,488 |
) |
|
|
5,507 |
|
|
|
(2,045 |
) |
|
|
2,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) |
|
$ |
10,082 |
|
|
$ |
21,824 |
|
|
$ |
124,766 |
|
|
$ |
(11,973 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
32.7 |
% |
|
|
52.5 |
% |
|
|
37.0 |
% |
|
|
31.0 |
% |
Note M. Related parties
The following tables summarize charges incurred with and payments made to the Companys
related parties and reported in the consolidated statements of operations, as well as outstanding
payables and receivables included in the consolidated balance sheets for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Charges incurred with Chase Oil and affiliates (a) |
|
$ |
11,395 |
|
|
$ |
5,670 |
|
|
$ |
26,902 |
|
|
$ |
18,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working interests owned by employees: (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues distributed to employees |
|
$ |
49 |
|
|
$ |
130 |
|
|
$ |
220 |
|
|
$ |
192 |
|
Joint interest payments received from employees |
|
$ |
293 |
|
|
$ |
95 |
|
|
$ |
868 |
|
|
$ |
979 |
|
Acquisition of oil and natural gas interests from an employee |
|
$ |
363 |
|
|
$ |
|
|
|
$ |
363 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overriding royalty interests paid to Chase Oil affiliates (c) |
|
$ |
412 |
|
|
$ |
402 |
|
|
$ |
1,458 |
|
|
$ |
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty interests paid to a director of the Company (d) |
|
$ |
42 |
|
|
$ |
39 |
|
|
$ |
121 |
|
|
$ |
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts paid under consulting agreement with Steven L. Beal (e) |
|
$ |
64 |
|
|
$ |
63 |
|
|
$ |
194 |
|
|
$ |
63 |
|
30
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
(in thousands) |
|
2010 |
|
2009 |
Amounts included in accounts receivable related parties: |
|
|
|
|
|
|
|
|
Chase Oil and affiliates (a) |
|
$ |
197 |
|
|
$ |
87 |
|
Working interests owned by employees (b) |
|
$ |
114 |
|
|
$ |
129 |
|
|
|
|
|
|
|
|
|
|
Amounts included in accounts payable related parties: |
|
|
|
|
|
|
|
|
Chase Oil and affiliates (a) |
|
$ |
|
|
|
$ |
9 |
|
Working interests owned by employees (b) |
|
$ |
9 |
|
|
$ |
15 |
|
Overriding royalty interests of Chase Oil affiliates (c) |
|
$ |
454 |
|
|
$ |
255 |
|
Royalty interests of a director of the Company (d) |
|
$ |
11 |
|
|
$ |
12 |
|
|
|
|
(a) |
|
The Company incurred charges for services rendered in the ordinary course of business from
Chase Oil and its affiliates including a drilling contractor, an oilfield services company, a
supply company, a drilling fluids supply company, a pipe and tubing supplier, a fixed base
operator of aircraft services and a software company. The tables above summarize the charges
incurred as well as outstanding payables and receivables. |
|
(b) |
|
The Company purchased oil and natural gas properties from third parties in which employees of
the Company owned a working interest. The tables above summarize the Companys activities
with these employees. During the three and nine months ended September 30, 2010, the Company
acquired oil and natural gas interests from an employee of the Company. |
|
(c) |
|
Certain persons affiliated with Chase Oil own overriding royalty interests in certain of the
Companys properties. The tables above summarize the amounts paid attributable to such
interests and amounts due at period end. |
|
(d) |
|
Royalties are paid on certain properties, located in Andrews County, Texas, to a partnership
of which one of the Companys directors is the general partner and owns a 3.5 percent
partnership interest. The tables above summarize the amounts paid attributable to such
interest and amounts due at period end. |
|
(e) |
|
On June 30, 2009, Steven L. Beal, the Companys then president and chief operating officer,
retired from such positions. On June 9, 2009, the Company entered into a consulting agreement
(the Consulting Agreement) with Mr. Beal, under which Mr. Beal began serving as a consultant
to the Company on July 1, 2009. Either the Company or Mr. Beal may terminate the consulting
relationship at any time by giving ninety days written notice to the other party; however, the
Company may terminate the relationship immediately for cause. During the term of the
consulting relationship, Mr. Beal will receive a consulting fee of $20,000 per month and a
monthly reimbursement for his medical and dental coverage costs. If Mr. Beal dies during the
term of the Consulting Agreement, his estate will receive a $60,000 lump sum payment. As part
of the consulting agreement, certain of Mr. Beals stock-based awards were modified to permit
vesting and exercise under the original terms of the stock-based awards as if Mr. Beal were
still an employee of the Company while he is performing consulting services for the Company.
The tables above summarize the Companys activities pursuant to the consulting agreement with
this director. |
Saltwater disposal services agreement. Among the assets the Company acquired from Chase Oil
is an undivided interest in a saltwater gathering and disposal system, which is owned and
maintained under a written agreement among the Company and Chase Oil and certain of its affiliates,
and under which the Company as operator gathers and disposes of produced water. The system is owned
jointly by the Company and Chase Oil and its affiliates in undivided ownership percentages, which
are annually redetermined as of January 1 on the basis of each partys percentage contribution of
the total volume of produced water disposed of through the system during the prior calendar year.
As of January 1, 2010, the Company owned 97.5 percent of the system and Chase Oil and its
affiliates owned 2.5 percent.
Purchase of residence. During the second quarter of 2010, the Company purchased the Houston,
Texas residence of an officer of the Company. To effectuate the purchase, the Company engaged a
third-party relocation company, who executed the purchase for
31
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
$920,000 and will subsequently sell the officers residence. The third-party relocation
company appraised the fair value of the residence at $920,000.
Note N. Net income (loss) per share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted
average number of common shares treated as outstanding for the period.
The computation of diluted income (loss) per share reflects the potential dilution that could
occur if securities or other contracts to issue common stock that are dilutive to income (loss)
were exercised or converted into common stock or resulted in the issuance of common stock that
would then share in the earnings of the Company. These amounts include unexercised capital options,
stock options and restricted stock (as issued under the Plan and described in Note G). Potentially
dilutive effects are calculated using the treasury stock method.
The following table is a reconciliation of the basic weighted average common shares
outstanding to diluted weighted average common shares outstanding for the three and nine months
ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
(in thousands) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
91,182 |
|
|
|
85,061 |
|
|
|
90,361 |
|
|
|
84,798 |
|
Dilutive common stock options |
|
|
845 |
|
|
|
789 |
|
|
|
892 |
|
|
|
|
|
Dilutive restricted stock |
|
|
413 |
|
|
|
238 |
|
|
|
378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
92,440 |
|
|
|
86,088 |
|
|
|
91,631 |
|
|
|
84,798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Because the Company reported a net loss for the nine months ended September 30, 2009, a total
of 2,338,749 stock options and 477,795 restricted shares, outstanding at September 30, 2009, were
not included in the diluted loss per share computations. The inclusion of these equity instruments
would have been anti-dilutive; therefore, the weighted average common shares reported for basic and
diluted net loss per share were the same.
32
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note O. Other current liabilities
The following table provides the components of the Companys other current liabilities at
September 30, 2010 and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Other current liabilities: |
|
|
|
|
|
|
|
|
Accrued production costs |
|
$ |
26,360 |
|
|
$ |
24,128 |
|
Payroll related matters |
|
|
9,754 |
|
|
|
14,490 |
|
Accrued interest |
|
|
12,999 |
|
|
|
10,055 |
|
Asset retirement obligations |
|
|
2,182 |
|
|
|
3,262 |
|
Other |
|
|
10,803 |
|
|
|
8,160 |
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
62,098 |
|
|
$ |
60,095 |
|
|
|
|
|
|
|
|
Note P. Subsidiary guarantors
All of the Companys wholly-owned subsidiaries have fully and unconditionally guaranteed the
Senior Notes of the Company (See Note J). In accordance with practices accepted by the 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 September 30, 2010 and December 31, 2009, and Condensed
Consolidating Statements of Operations for the three and nine months ended September 30, 2010 and
2009 and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30,
2010 and 2009, 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 (carrying any investment in
non-guarantor subsidiaries under the equity method), 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.
33
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Condensed Consolidating Balance Sheet
September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable related parties |
|
$ |
3,917,586 |
|
|
$ |
775,450 |
|
|
$ |
(4,692,725 |
) |
|
$ |
311 |
|
Other current assets |
|
|
30,546 |
|
|
|
207,819 |
|
|
|
|
|
|
|
238,365 |
|
Total oil and natural gas properties, net |
|
|
|
|
|
|
3,178,793 |
|
|
|
|
|
|
|
3,178,793 |
|
Total property and equipment, net |
|
|
|
|
|
|
17,105 |
|
|
|
|
|
|
|
17,105 |
|
Investment in subsidiaries |
|
|
1,187,490 |
|
|
|
|
|
|
|
(1,187,490 |
) |
|
|
|
|
Total other long-term assets |
|
|
39,650 |
|
|
|
67,451 |
|
|
|
|
|
|
|
107,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
5,175,272 |
|
|
$ |
4,246,618 |
|
|
$ |
(5,880,215 |
) |
|
$ |
3,541,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable related parties |
|
$ |
1,968,955 |
|
|
$ |
2,724,244 |
|
|
$ |
(4,692,725 |
) |
|
$ |
474 |
|
Other current liabilities |
|
|
36,704 |
|
|
|
312,967 |
|
|
|
|
|
|
|
349,671 |
|
Other long-term liabilities |
|
|
692,371 |
|
|
|
21,917 |
|
|
|
|
|
|
|
714,288 |
|
Long-term debt |
|
|
688,620 |
|
|
|
|
|
|
|
|
|
|
|
688,620 |
|
Equity |
|
|
1,788,622 |
|
|
|
1,187,490 |
|
|
|
(1,187,490 |
) |
|
|
1,788,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
5,175,272 |
|
|
$ |
4,246,618 |
|
|
$ |
(5,880,215 |
) |
|
$ |
3,541,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Balance Sheet
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable related parties |
|
$ |
2,715,307 |
|
|
$ |
1,738,382 |
|
|
$ |
(4,453,473 |
) |
|
$ |
216 |
|
Other current assets |
|
|
33,561 |
|
|
|
183,481 |
|
|
|
|
|
|
|
217,042 |
|
Total oil and natural gas properties, net |
|
|
|
|
|
|
2,840,583 |
|
|
|
|
|
|
|
2,840,583 |
|
Total property and equipment, net |
|
|
|
|
|
|
15,706 |
|
|
|
|
|
|
|
15,706 |
|
Investment in subsidiaries |
|
|
876,154 |
|
|
|
|
|
|
|
(876,154 |
) |
|
|
|
|
Total other long-term assets |
|
|
44,291 |
|
|
|
53,247 |
|
|
|
|
|
|
|
97,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
3,669,313 |
|
|
$ |
4,831,399 |
|
|
$ |
(5,329,627 |
) |
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable related parties |
|
$ |
790,251 |
|
|
$ |
3,663,513 |
|
|
$ |
(4,453,473 |
) |
|
$ |
291 |
|
Other current liabilities |
|
|
68,706 |
|
|
|
268,017 |
|
|
|
|
|
|
|
336,723 |
|
Other long-term liabilities |
|
|
629,092 |
|
|
|
23,715 |
|
|
|
|
|
|
|
652,807 |
|
Long-term debt |
|
|
845,836 |
|
|
|
|
|
|
|
|
|
|
|
845,836 |
|
Equity |
|
|
1,335,428 |
|
|
|
876,154 |
|
|
|
(876,154 |
) |
|
|
1,335,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity |
|
$ |
3,669,313 |
|
|
$ |
4,831,399 |
|
|
$ |
(5,329,627 |
) |
|
$ |
3,171,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
240,496 |
|
|
$ |
|
|
|
$ |
240,496 |
|
Total operating costs and expenses |
|
|
(64,846 |
) |
|
|
(129,236 |
) |
|
|
|
|
|
|
(194,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(64,846 |
) |
|
|
111,260 |
|
|
|
|
|
|
|
46,414 |
|
Interest expense |
|
|
(12,036 |
) |
|
|
|
|
|
|
|
|
|
|
(12,036 |
) |
Other, net |
|
|
107,739 |
|
|
|
(3,521 |
) |
|
|
(107,739 |
) |
|
|
(3,521 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
30,857 |
|
|
|
107,739 |
|
|
|
(107,739 |
) |
|
|
30,857 |
|
Income tax expense |
|
|
(10,082 |
) |
|
|
|
|
|
|
|
|
|
|
(10,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
20,775 |
|
|
$ |
107,739 |
|
|
$ |
(107,739 |
) |
|
$ |
20,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
153,494 |
|
|
$ |
|
|
|
$ |
153,494 |
|
Total operating costs and expenses |
|
|
(9,083 |
) |
|
|
(95,816 |
) |
|
|
|
|
|
|
(104,899 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(9,083 |
) |
|
|
57,678 |
|
|
|
|
|
|
|
48,595 |
|
Interest expense |
|
|
(6,809 |
) |
|
|
|
|
|
|
|
|
|
|
(6,809 |
) |
Other, net |
|
|
57,478 |
|
|
|
(200 |
) |
|
|
(57,478 |
) |
|
|
(200 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
41,586 |
|
|
|
57,478 |
|
|
|
(57,478 |
) |
|
|
41,586 |
|
Income tax expense |
|
|
(21,824 |
) |
|
|
|
|
|
|
|
|
|
|
(21,824 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
19,762 |
|
|
$ |
57,478 |
|
|
$ |
(57,478 |
) |
|
$ |
19,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
668,206 |
|
|
$ |
|
|
|
$ |
668,206 |
|
Total operating costs and expenses |
|
|
60,209 |
|
|
|
(352,972 |
) |
|
|
|
|
|
|
(292,763 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
60,209 |
|
|
|
315,234 |
|
|
|
|
|
|
|
375,443 |
|
Interest expense |
|
|
(34,293 |
) |
|
|
|
|
|
|
|
|
|
|
(34,293 |
) |
Other, net |
|
|
311,336 |
|
|
|
(3,898 |
) |
|
|
(311,336 |
) |
|
|
(3,898 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
337,252 |
|
|
|
311,336 |
|
|
|
(311,336 |
) |
|
|
337,252 |
|
Income tax expense |
|
|
(124,766 |
) |
|
|
|
|
|
|
|
|
|
|
(124,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
212,486 |
|
|
$ |
311,336 |
|
|
$ |
(311,336 |
) |
|
$ |
212,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Total operating revenues |
|
$ |
|
|
|
$ |
366,828 |
|
|
$ |
|
|
|
$ |
366,828 |
|
Total operating costs and expenses |
|
|
(86,376 |
) |
|
|
(301,379 |
) |
|
|
|
|
|
|
(387,755 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(86,376 |
) |
|
|
65,449 |
|
|
|
|
|
|
|
(20,927 |
) |
Interest expense |
|
|
(17,379 |
) |
|
|
|
|
|
|
|
|
|
|
(17,379 |
) |
Other, net |
|
|
65,101 |
|
|
|
(348 |
) |
|
|
(65,101 |
) |
|
|
(348 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(38,654 |
) |
|
|
65,101 |
|
|
|
(65,101 |
) |
|
|
(38,654 |
) |
Income tax benefit |
|
|
11,973 |
|
|
|
|
|
|
|
|
|
|
|
11,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(26,681 |
) |
|
$ |
65,101 |
|
|
$ |
(65,101 |
) |
|
$ |
(26,681 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
36
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Net cash flows provided by (used in) operating activities |
|
$ |
(68,526 |
) |
|
$ |
471,282 |
|
|
$ |
|
|
|
$ |
402,756 |
|
Net cash flows used in investing activities |
|
|
(3,539 |
) |
|
|
(509,285 |
) |
|
|
|
|
|
|
(512,824 |
) |
Net cash flows provided by financing activities |
|
|
72,055 |
|
|
|
35,136 |
|
|
|
|
|
|
|
107,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(10 |
) |
|
|
(2,867 |
) |
|
|
|
|
|
|
(2,877 |
) |
Cash and cash equivalents at beginning of period |
|
|
48 |
|
|
|
3,186 |
|
|
|
|
|
|
|
3,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
38 |
|
|
$ |
319 |
|
|
$ |
|
|
|
$ |
357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent |
|
|
Subsidiary |
|
|
Consolidating |
|
|
|
|
(in thousands) |
|
Issuer |
|
|
Guarantors |
|
|
Entries |
|
|
Total |
|
|
Net cash flows provided by (used in) operating
activities |
|
$ |
(91,954 |
) |
|
$ |
324,032 |
|
|
$ |
|
|
|
$ |
232,078 |
|
Net cash flows provided by (used in) investing
activities |
|
|
77,590 |
|
|
|
(319,468 |
) |
|
|
|
|
|
|
(241,878 |
) |
Net cash flows provided by (used in) financing activities |
|
|
14,367 |
|
|
|
(6,624 |
) |
|
|
|
|
|
|
7,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash
equivalents |
|
|
3 |
|
|
|
(2,060 |
) |
|
|
|
|
|
|
(2,057 |
) |
Cash and cash equivalents at beginning of period . |
|
|
|
|
|
|
17,752 |
|
|
|
|
|
|
|
17,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period . |
|
$ |
3 |
|
|
$ |
15,692 |
|
|
$ |
|
|
|
$ |
15,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note Q. Subsequent events
Marbob Acquisition. On July 19, 2010, the Company entered into an asset purchase agreement to
acquire certain of the oil and natural gas leases, interests, properties and related assets owned
by Marbob for aggregate consideration of (i) cash in the amount of $1.45 billion, (ii) the issuance
by the Company to Marbob of an 8 percent unsecured promissory note due 2018 in the aggregate
principal amount of $150 million and (iii) the issuance to Marbob of approximately 1.1 million
shares of the Companys common stock, subject to purchase price adjustments, which included
downward purchase price adjustments based on the exercise of third parties of contractual
preferential rights to purchase certain interests in properties to be acquired from Marbob.
In October 2010, the Company closed the Marbob Acquisition. At closing, the Company paid
approximately $1.1 billion in cash plus the unsecured promissory note and common stock described
above for a total purchase price of approximately $1.3 billion. The total purchase price as
originally announced was reduced due to third party contractual preferential rights to purchase
certain of the interests in the Marbob properties. The Marbob Acquisition remains subject to
certain post-closing adjustments. Certain of the third parties contractual preferential rights
became subject to litigation, as discussed below. The Company funded the cash consideration in the
Marbob Acquisition with borrowings under its Credit Facility and proceeds from the Private
Placement.
Marbob preferential rights. Certain of the Marbob interests in properties contained
contractual preferential rights to purchase by third parties if Marbob were to sell them. Marbob
informed the Company of its receipt of a notice from BP America Production Company (BP) electing
to exercise its contractual preferential purchase right to purchase interests in certain of
Marbobs properties as a result of the Marbob Acquisition.
On July 20, 2010, BP announced it was selling all its assets in the Permian Basin to a
subsidiary of Apache Corporation (Apache). Marbob and BP owned common interests in certain
properties subject to contractual preferential rights to purchase. BP and Apache contested Marbobs
ability to exercise its contractual preferential rights in this situation. As a result, Marbob and
the Company filed suit against BP and Apache seeking declaratory judgment and injunctive relief to
protect Marbobs contractual right to have the option to purchase these interests in these common
properties.
On October 15, 2010, the Company and Marbob resolved the litigation with BP and Apache related
to the disputed contractual preferential rights. As a result of the settlement, we acquired a
non-operated interest in substantially all of the oil and natural gas assets subject to the
litigation for approximately $286 million. This acquisition remains subject to certain post-closing
adjustments. The Company funded the acquisition with borrowings under its Credit Facility.
New commodity derivative contracts. In October 2010, the Company entered into the following
oil price swaps to hedge additional amounts of its estimated future oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price(a) |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
378,000 |
|
|
$ |
85.62 |
|
|
|
1/1/11 - 6/30/11 |
|
Price swap |
|
|
200,000 |
|
|
$ |
83.47 |
|
|
|
1/1/11 - 11/30/11 |
|
Price swap |
|
|
2,568,000 |
|
|
$ |
85.98 |
|
|
|
1/1/11 - 12/31/11 |
|
Price swap |
|
|
96,000 |
|
|
$ |
86.80 |
|
|
|
7/1/11 - 12/31/11 |
|
Price swap |
|
|
540,000 |
|
|
$ |
86.84 |
|
|
|
1/1/12 - 6/30/12 |
|
Price swap |
|
|
389,000 |
|
|
$ |
86.95 |
|
|
|
1/1/12 - 11/30/12 |
|
Price swap |
|
|
1,914,000 |
|
|
$ |
87.58 |
|
|
|
1/1/12 - 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
monthly average futures price. |
38
Concho Resources Inc.
Condensed Notes to Consolidated Financial Statements
September 30, 2010
Unaudited
Note R. Supplementary information
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Oil and natural gas properties: |
|
|
|
|
|
|
|
|
Proved |
|
$ |
3,647,441 |
|
|
$ |
3,139,424 |
|
Unproved |
|
|
224,274 |
|
|
|
218,580 |
|
Less: accumulated depletion |
|
|
(692,922 |
) |
|
|
(517,421 |
) |
|
|
|
|
|
|
|
Net capitalized costs for oil and natural gas properties |
|
$ |
3,178,793 |
|
|
$ |
2,840,583 |
|
|
|
|
|
|
|
|
Costs incurred for oil and natural gas producing activities (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Property acquisition costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
3,762 |
|
|
$ |
(467 |
) |
|
$ |
17,501 |
|
|
$ |
(1,475 |
) |
Unproved |
|
|
10,874 |
|
|
|
7,618 |
|
|
|
31,903 |
|
|
|
12,200 |
|
Exploration |
|
|
74,740 |
|
|
|
26,065 |
|
|
|
136,673 |
|
|
|
111,005 |
|
Development |
|
|
88,310 |
|
|
|
64,554 |
|
|
|
334,222 |
|
|
|
179,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred for oil and natural gas properties |
|
$ |
177,686 |
|
|
$ |
97,770 |
|
|
$ |
520,299 |
|
|
$ |
301,513 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The costs incurred for oil and natural gas producing activities includes the following
amounts of asset retirement obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Proved property acquisition costs |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Exploration costs |
|
|
321 |
|
|
|
(70 |
) |
|
|
573 |
|
|
|
150 |
|
Development costs |
|
|
197 |
|
|
|
309 |
|
|
|
(1,227 |
) |
|
|
(2,418 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
518 |
|
|
$ |
239 |
|
|
$ |
(654 |
) |
|
$ |
(2,268 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
39
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist 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, as well as the
selected historical consolidated financial data and Managements Discussion and Analysis of
Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the
year ended December 31, 2009.
During the fourth quarter of 2009, we closed the Wolfberry Acquisitions, as discussed below.
The results of these acquisitions are included in our results of operations beginning January 1,
2010. As a result, many comparisons between periods will be difficult or impossible.
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 these 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 and
exploration of producing oil and natural gas properties. Our core operations are primarily focused
in the Permian Basin of Southeast New Mexico and West Texas. We have also acquired significant
acreage positions in and are actively involved in the drilling or participating in drilling of
emerging plays including the Bone Spring located in the Permian Basin of Southeast New Mexico and
the Bakken play in the Williston Basin of North Dakota, where we are applying horizontal drilling,
advanced fracture stimulation and enhanced recovery technologies. Crude oil comprised 67 percent of
our 211.5 million barrels of oil equivalent (MMBoe) of estimated net proved reserves at December
31, 2009, and 68 percent of our 10.6 MMBoe of production for the nine months ended September 30,
2010. We seek to operate the wells in which we own an interest, and we operated wells that
accounted for 95.3 percent of our proved developed producing cash flows discounted to present value
at 10 percent (PV-10) and 66.4 percent of our 3,960 gross wells at December 31, 2009. 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.
Commodity Prices
Our results of operations are heavily influenced by commodity prices. Factors that may impact
future commodity prices, including the price of oil and natural gas, include:
|
|
|
developments generally impacting the Middle East, including Iraq and Iran; |
|
|
|
|
the extent to which members of the Organization of Petroleum Exporting Countries and
other oil exporting nations are able to continue to manage oil supply through export
quotas; |
|
|
|
|
the overall global demand for oil; and |
|
|
|
|
overall North American natural gas supply and demand fundamentals, including: |
|
§ |
|
the impact of any decline in the United States economy, |
|
|
§ |
|
weather conditions, and |
|
|
§ |
|
liquefied natural gas deliveries to 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 Note I of the Condensed Notes to
Consolidated Financial Statements included in Item 1. Consolidated Financial Statements
(Unaudited) for additional information regarding our commodity hedge positions at September 30,
2010.
40
Oil and natural gas prices have been subject to significant fluctuations during the past
several years. In general, oil prices were significantly higher during the comparable periods of
2010 measured against 2009, while natural gas prices were moderately higher. The following table
sets forth the average NYMEX oil and natural gas prices for the three and nine months ended
September 30, 2010 and 2009, as well as the high and low NYMEX prices for the same periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Average NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
$ |
76.09 |
|
|
$ |
68.24 |
|
|
$ |
77.60 |
|
|
$ |
57.22 |
|
Natural gas (MMBtu) |
|
$ |
4.24 |
|
|
$ |
3.42 |
|
|
$ |
4.54 |
|
|
$ |
3.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High and Low NYMEX prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
82.55 |
|
|
$ |
74.37 |
|
|
$ |
86.84 |
|
|
$ |
74.37 |
|
Low |
|
$ |
71.63 |
|
|
$ |
59.52 |
|
|
$ |
68.01 |
|
|
$ |
33.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMBtu): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
4.92 |
|
|
$ |
4.88 |
|
|
$ |
6.01 |
|
|
$ |
6.07 |
|
Low |
|
$ |
3.65 |
|
|
$ |
2.51 |
|
|
$ |
3.65 |
|
|
$ |
2.51 |
|
Further,
the NYMEX oil price and NYMEX natural gas price reached highs and
lows of $83.90 and
$79.49 per Bbl and $4.04 and $3.29 per MMBtu, respectively, during the period from October 1,
2010 to November 2, 2010. At November 2, 2010, the NYMEX oil price and NYMEX natural gas price were
$83.90 per Bbl and $3.87 per MMBtu, respectively.
Recent Events
Marbob acquisition. On July 19, 2010, we entered into an asset purchase agreement to acquire
substantially all of the oil and natural gas leases, interests, properties and related assets owned
by Marbob Energy Corporation and certain affiliates (Marbob) for aggregate consideration of (i)
cash in the amount of $1.45 billion, (ii) our issuance to Marbob of an 8 percent unsecured
promissory note due 2018 in the aggregate principal amount of $150 million and (iii) the issuance
to Marbob of approximately 1.1 million shares of our common stock, subject to purchase price
adjustments, which included downward purchase price adjustments based on the exercise of third
parties of contractual preferential rights to purchase certain interests in properties to be
acquired from Marbob.
The Marbob assets are primarily located in the Permian Basin of Southeast New Mexico,
including a large acreage position contiguous to our core Yeso play on the Southeast New Mexico
Shelf and a significant acreage position in the emerging Bone Spring play in Southeast New Mexico.
These assets are a complement to our New Mexico Shelf position and significantly increase our Yeso
drilling inventory. In addition, Marbobs Bone Spring acreage, when coupled with our existing
acreage, gives us a significant acreage position in one of the newest emerging plays in the
industry and adds a significant new area of potential growth to our portfolio. We also retained
most of Marbobs experienced technical and operational staff.
In October 2010, we closed the Marbob acquisition. At closing, we paid approximately $1.1
billion in cash plus the unsecured promissory note and common stock described above for a total
purchase price of approximately $1.3 billion. The total purchase price as originally announced was
reduced due to third party contractual preferential rights to purchase certain of the interests in
the Marbob properties. The Marbob acquisition remains subject to certain post-closing adjustments.
Certain of the third parties contractual preferential rights became subject to litigation as
discussed below. We funded the Marbob acquisition with borrowings under our credit facility and
proceeds from the private placement, discussed later.
Marbob preferential rights. Certain of the Marbob interests in properties contained
contractual preferential rights to purchase by third parties if Marbob were to sell them. Marbob
informed us of its receipt of a notice from BP America Production Company (BP) electing to
exercise its contractual preferential purchase right to purchase interests in certain of Marbobs
properties as a result of the Marbob acquisition.
41
On July 20, 2010, BP announced it was selling all its assets in the Permian Basin to a
subsidiary of Apache Corporation (Apache). Marbob and BP owned common interests in certain
properties subject to contractual preferential rights to purchase. BP and Apache contested Marbobs
ability to exercise its contractual preferential rights in this situation. As a result, Marbob and
we filed suit against BP and Apache seeking declaratory judgment and injunctive relief to protect
Marbobs contractual right to have the option to purchase these interests in these common
properties.
On October 15, 2010, we and Marbob resolved the litigation with BP and Apache related to the
disputed contractual preferential rights. As a result of the settlement, we acquired a non-operated
interest in substantially all the oil and natural gas assets subject to the litigation for
approximately $286 million. This acquisition remains subject to certain post-closing adjustments.
We funded the acquisition with borrowings under our credit facility.
Private placement of equity. On July 19, 2010, we entered into a common stock purchase
agreement with certain third-party accredited investors to sell 6.6 million shares of our common
stock at a price of $45.30 per share in a private placement for aggregate cash consideration of
approximately $300 million. We paid approximately $7.3 million in transaction costs, which includes
the placement agent fee. On October 7, 2010, we closed the private placement simultaneously with
the closing of the Marbob acquisition.
Credit facility amendment . On October 7, 2010, we amended our credit facility simultaneously
with the closing of the Marbob acquisition to increase the borrowing base from $1.2 billion to $2.0
billion. We paid our bank group approximately $23.6 million associated with the amendment to
increase the borrowing base. Pro forma at September 30, 2010, after taking into account the
closing of the Marbob acquisition, the resolution of the Marbob preferential right dispute, the closing of the
credit facility amendment, the private placement and estimated related transaction costs, we
estimate our outstanding indebtedness under our credit facility would have been approximately $1.5
billion and our availability under our credit facility would have been approximately $470 million.
2011 capital budget. In November 2010, we announced our 2011 capital budget of approximately
$1.1 billion, which we expect can be funded substantially within our cash flow, based on current
commodity prices and our expectations. As our size and financial flexibility have grown, we now
take a longer-term view on spending substantially within our cash flow, and our spending during any
specific period may exceed our cash flow for that period. However, our capital budget is largely
discretionary, and if we experience sustained oil and natural gas prices significantly below the
current levels or substantial increases in our drilling and completion costs, we may reduce our
capital spending program to be substantially within our cash flow.
Our capital budget does not include acquisitions (other than the customary purchase of
leasehold acreage). The following is a summary of our 2011 capital budget:
|
|
|
|
|
|
|
2011 |
|
(in millions) |
|
Budget |
|
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
736 |
|
Projects operated by third parties |
|
|
68 |
|
Emerging plays, acquisition of leasehold acreage and other
property interests, geological and geophysical and other |
|
|
200 |
|
Facilities
and other capital in our core operating areas |
|
|
100 |
|
|
|
|
|
Total |
|
$ |
1,104 |
|
|
|
|
|
Equity issuance. On February 1, 2010, we issued approximately 5.3 million shares of our common
stock at $42.75 per share in a public offering. After deducting underwriting discounts of
approximately $9.1 million and transaction costs, we received net proceeds of approximately $219.3
million. The net proceeds from this offering were used to repay a portion of the borrowings under
our credit facility.
Wolfberry acquisitions. In December 2009, together with the acquisition of related additional
interests that closed in 2010, we closed two acquisitions of interests in producing and
non-producing assets in the Wolfberry play of the Permian Basin for approximately $270.7 million in
cash (the Wolfberry Acquisitions). The Wolfberry Acquisitions were primarily funded with
borrowings under our credit facility. Our 2009 results of operations do not include any
production, revenues or costs from the Wolfberry Acquisitions.
2010 capital budget. In August 2010, we announced the increase of our 2010 capital budget to
$700 million. After considering additional operations on assets acquired as a result of the Marbob
acquisition and the Marbob preferential right dispute, we expect
42
2010 capital expenditures to total
approximately $760 million, which does not include the costs of acquisitions other than customary
leasehold purchases of leasehold acreage. Based on current commodity prices and our
expectations, we believe our 2010 planned capital expenditures, excluding the effects of
acquisitions, will exceed our 2010 cash flow. As our size and financial flexibility have grown, we
now take a longer-term view on spending substantially within our cash flow, and our spending during
any specific period may exceed our cash flow for that period. However, our capital expenditure plan
is largely discretionary, and if we experience sustained oil and natural gas prices significantly
below the current levels or substantial increases in our drilling and completion costs, we may
reduce our capital spending program to be substantially within our cash flow. The following is a
summary of our 2010 capital budget and current 2010 planned capital expenditures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current 2010 |
|
|
|
2010 |
|
|
Planned Capital |
|
(in millions) |
|
Budget |
|
|
Expenditures (a) |
|
|
Drilling and recompletion opportunities in our core operating area |
|
$ |
538 |
|
|
$ |
592 |
|
Projects operated by third parties |
|
|
10 |
|
|
|
10 |
|
Emerging plays, acquisition of leasehold acreage and other property interests,
geological and geophysical and other |
|
|
117 |
|
|
|
118 |
|
Facilities
and other capital in our core operating areas |
|
|
35 |
|
|
|
40 |
|
|
|
|
|
|
|
|
Total |
|
$ |
700 |
|
|
$ |
760 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes estimated planned capital expenditures on the assets acquired as a result of the
Marbob acquisition and the Marbob preferential right dispute. |
Derivative Financial Instruments
Derivative financial instrument exposure. At September 30, 2010, the fair value of our
financial derivatives was a net asset of $0.6 million. All of our counterparties to these financial
derivatives are a party 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.
43
New commodity derivative contracts. During the nine months ended September 30, 2010, we
entered into additional commodity derivative contracts to hedge a portion of our estimated future
production. The following table summarizes information about these additional commodity derivative
contracts for the nine months ended September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price |
|
Period |
|
Oil (volumes in Bbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
670,000 |
|
|
$ |
83.72 |
(a) |
|
|
1/1/10 12/31/10 |
|
Price swap |
|
|
195,000 |
|
|
$ |
76.85 |
(a) |
|
|
3/1/10 12/31/10 |
|
Price swap |
|
|
1,463,000 |
|
|
$ |
88.63 |
(a) |
|
|
5/1/10 12/31/10 |
|
Price swap |
|
|
3,714,000 |
|
|
$ |
85.15 |
(a) |
|
|
1/1/11 12/31/11 |
|
Price swap |
|
|
3,573,000 |
|
|
$ |
88.56 |
(a) |
|
|
1/1/12 12/31/12 |
|
Price swap |
|
|
261,000 |
|
|
$ |
82.50 |
(a) |
|
|
7/1/12 12/31/12 |
|
Price swap |
|
|
1,380,000 |
|
|
$ |
82.58 |
(a) |
|
|
1/1/13 12/31/13 |
|
Price swap |
|
|
1,248,000 |
|
|
$ |
83.94 |
(a) |
|
|
1/1/14 12/31/14 |
|
Price swap |
|
|
600,000 |
|
|
$ |
84.50 |
(a) |
|
|
1/1/15 6/30/15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (volumes in MMBtus): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
418,000 |
|
|
$ |
5.99 |
(b) |
|
|
2/1/10 12/31/10 |
|
Price swap |
|
|
1,250,000 |
|
|
$ |
5.55 |
(b) |
|
|
3/1/10 12/31/10 |
|
Price swap |
|
|
5,076,000 |
|
|
$ |
6.14 |
(b) |
|
|
1/1/11 12/31/11 |
|
Price swap |
|
|
300,000 |
|
|
$ |
6.54 |
(b) |
|
|
1/1/12 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate 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. |
In October 2010, we entered into the following oil price swaps to hedge additional
amounts of our estimated future oil production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate |
|
Index |
|
Contract |
|
|
Volume |
|
Price (a) |
|
Period |
|
Oil (volumes in Bbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Price swap |
|
|
378,000 |
|
|
$ |
85.62 |
|
|
|
1/1/11 6/30/11 |
|
Price swap |
|
|
200,000 |
|
|
$ |
83.47 |
|
|
|
1/1/11 11/30/11 |
|
Price swap |
|
|
2,568,000 |
|
|
$ |
85.98 |
|
|
|
1/1/11 12/31/11 |
|
Price swap |
|
|
96,000 |
|
|
$ |
86.80 |
|
|
|
7/1/11 12/31/11 |
|
Price swap |
|
|
540,000 |
|
|
$ |
86.84 |
|
|
|
1/1/12 6/30/12 |
|
Price swap |
|
|
389,000 |
|
|
$ |
86.95 |
|
|
|
1/1/12 11/30/12 |
|
Price swap |
|
|
1,914,000 |
|
|
$ |
87.58 |
|
|
|
1/1/12 12/31/12 |
|
|
|
|
(a) |
|
The index prices for the oil price swaps are based on the NYMEX-West Texas Intermediate
monthly average futures price. |
44
Results of Operations
The following table sets forth summary information concerning our production results,
average sales prices and operating costs and expenses for the three and nine months ended September
30, 2010 and 2009. The actual historical data in this table excludes results from the Wolfberry
Acquisitions for periods prior to January 1, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Production and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
2,656 |
|
|
|
1,912 |
|
|
|
7,163 |
|
|
|
5,430 |
|
Natural gas (MMcf) |
|
|
7,460 |
|
|
|
5,753 |
|
|
|
20,393 |
|
|
|
16,122 |
|
Total (MBoe) |
|
|
3,899 |
|
|
|
2,871 |
|
|
|
10,562 |
|
|
|
8,117 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl) |
|
|
28,870 |
|
|
|
20,783 |
|
|
|
26,238 |
|
|
|
19,890 |
|
Natural gas (Mcf) |
|
|
81,087 |
|
|
|
62,533 |
|
|
|
74,700 |
|
|
|
59,055 |
|
Total (Boe) |
|
|
42,384 |
|
|
|
31,205 |
|
|
|
38,688 |
|
|
|
29,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl) |
|
$ |
71.90 |
|
|
$ |
63.44 |
|
|
$ |
73.73 |
|
|
$ |
53.00 |
|
Oil, with derivatives (Bbl) (a) |
|
$ |
72.29 |
|
|
$ |
70.75 |
|
|
$ |
72.06 |
|
|
$ |
65.96 |
|
Natural gas, without derivatives (Mcf) |
|
$ |
6.64 |
|
|
$ |
5.60 |
|
|
$ |
6.87 |
|
|
$ |
4.90 |
|
Natural gas, with derivatives (Mcf) (a) |
|
$ |
7.21 |
|
|
$ |
6.19 |
|
|
$ |
7.38 |
|
|
$ |
5.48 |
|
Total, without derivatives (Boe) |
|
$ |
61.68 |
|
|
$ |
53.46 |
|
|
$ |
63.27 |
|
|
$ |
45.19 |
|
Total, with derivatives (Boe) (a) |
|
$ |
63.04 |
|
|
$ |
59.51 |
|
|
$ |
63.12 |
|
|
$ |
55.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses and workover costs |
|
$ |
5.70 |
|
|
$ |
4.81 |
|
|
$ |
6.07 |
|
|
$ |
5.74 |
|
Oil and natural gas taxes |
|
$ |
5.86 |
|
|
$ |
4.05 |
|
|
$ |
5.50 |
|
|
$ |
3.63 |
|
Depreciation, depletion and amortization |
|
$ |
15.88 |
|
|
$ |
19.10 |
|
|
$ |
16.08 |
|
|
$ |
19.46 |
|
General and administrative |
|
$ |
3.86 |
|
|
$ |
4.43 |
|
|
$ |
4.37 |
|
|
$ |
4.76 |
|
|
|
|
(a) |
|
Includes the effect of the cash settlements received from (paid on) commodity
derivatives not designated as hedges and reported in operating costs and expenses.
The following table reflects the amounts of cash settlements received from (paid on)
commodity derivatives not designated as hedges that were included in computing
average prices with derivatives and reconciles to the amount in gain (loss) on
derivatives not designated as hedges as reported in the consolidated statements of
operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
Gain (loss) on derivatives not designated as hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash (payments on) receipts from oil derivatives |
|
$ |
1,034 |
|
|
$ |
13,971 |
|
|
$ |
(11,951 |
) |
|
$ |
70,383 |
|
Cash receipts from natural gas derivatives |
|
|
4,258 |
|
|
|
3,395 |
|
|
|
10,378 |
|
|
|
9,227 |
|
Cash payments on interest rate derivatives |
|
|
(1,224 |
) |
|
|
(1,241 |
) |
|
|
(3,658 |
) |
|
|
(2,020 |
) |
Unrealized mark-to-market gain (loss) on commodity and interest rate
derivatives |
|
|
(70,175 |
) |
|
|
(23,908 |
) |
|
|
67,460 |
|
|
|
(172,025 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not designated as hedges |
|
$ |
(66,107 |
) |
|
$ |
(7,783 |
) |
|
$ |
62,229 |
|
|
$ |
(94,435 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
45
The following table presents selected financial and operating information for the fields
which represented greater than 15 percent of our total proved reserves at December 31, 2009 and
2008, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
West |
|
Grayburg |
|
Grayburg |
|
West |
|
Grayburg |
|
Grayburg |
|
|
Wolfberry |
|
Jackson |
|
Jackson |
|
Wolfberry |
|
Jackson |
|
Jackson |
Production and operating data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl) |
|
|
455 |
|
|
|
451 |
|
|
|
390 |
|
|
|
1,142 |
|
|
|
1,248 |
|
|
|
1,038 |
|
Natural gas (MMcf) |
|
|
1,378 |
|
|
|
1,250 |
|
|
|
1,068 |
|
|
|
3,356 |
|
|
|
3,532 |
|
|
|
2,972 |
|
Total (MBoe) |
|
|
684 |
|
|
|
660 |
|
|
|
568 |
|
|
|
1,701 |
|
|
|
1,837 |
|
|
|
1,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, without derivatives (Bbl) |
|
$ |
73.45 |
|
|
$ |
71.87 |
|
|
$ |
64.89 |
|
|
$ |
75.55 |
|
|
$ |
73.80 |
|
|
$ |
53.54 |
|
Natural gas, without derivatives (Mcf) |
|
$ |
6.91 |
|
|
$ |
7.20 |
|
|
$ |
5.89 |
|
|
$ |
7.19 |
|
|
$ |
7.32 |
|
|
$ |
5.09 |
|
Total, without derivatives (Boe) |
|
$ |
62.70 |
|
|
$ |
62.82 |
|
|
$ |
55.62 |
|
|
$ |
64.89 |
|
|
$ |
64.23 |
|
|
$ |
46.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses including workovers |
|
$ |
4.63 |
|
|
$ |
5.03 |
|
|
$ |
4.74 |
|
|
$ |
4.50 |
|
|
$ |
5.77 |
|
|
$ |
5.77 |
|
Oil and natural gas taxes |
|
$ |
4.06 |
|
|
$ |
5.43 |
|
|
$ |
4.73 |
|
|
$ |
4.27 |
|
|
$ |
5.55 |
|
|
$ |
3.95 |
|
46
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
Oil and natural gas revenues. Revenue from oil and natural gas operations was $240.5
million for the three months ended September 30, 2010, an increase of $87.0 million (57 percent)
from $153.5 million for the three months ended September 30, 2009. This increase was primarily due
to increases in realized oil and natural gas prices and increased production (i) as a result of the
Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010.
Specifically the:
|
|
|
average realized oil price (excluding the effects of derivative activities) was
$71.90 per Bbl during the three months ended September 30, 2010, an increase of 13
percent from $63.44 per Bbl during the three months ended September 30, 2009; |
|
|
|
|
total oil production was 2,656 MBbl for the three months ended September 30, 2010, an
increase of 744 MBbl (39 percent) from 1,912 MBbl for the three months ended September
30, 2009; |
|
|
|
|
average realized natural gas price (excluding the effects of derivative activities)
was $6.64 per Mcf during the three months ended September 30, 2010, an increase of 19
percent from $5.60 per Mcf during the three months ended September 30, 2009; and |
|
|
|
|
total natural gas production was 7,460 MMcf for the three months ended September 30,
2010, an increase of 1,707 MMcf (30 percent) from 5,753 MMcf for the three months ended
September 30, 2009. |
Production expenses. The following table provides the components of our total oil and natural
gas production costs for the three months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
22,213 |
|
|
$ |
5.70 |
|
|
$ |
13,573 |
|
|
$ |
4.73 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
2,195 |
|
|
|
0.56 |
|
|
|
954 |
|
|
|
0.33 |
|
Production |
|
|
20,664 |
|
|
|
5.30 |
|
|
|
10,682 |
|
|
|
3.72 |
|
Workover costs |
|
|
|
|
|
|
|
|
|
|
230 |
|
|
|
0.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
45,072 |
|
|
$ |
11.56 |
|
|
$ |
25,439 |
|
|
$ |
8.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
The lease operating expenses during the third quarter of 2009 include the benefit of
approximately $2.3 million ($0.79 per Boe) related to an overestimate of costs in the prior
periods.
Lease operating expenses were $22.2 million ($5.70 per Boe) for the three months ended
September 30, 2010, an increase of $8.6 million (64 percent) from $13.6 million ($4.73 per Boe) for
the three months ended September 30, 2009. The increase in lease operating expenses was primarily
due to (i) our wells successfully drilled and completed in 2009 and 2010, (ii) additional interests
acquired in the Wolfberry Acquisitions in December 2009 and (iii) the benefit of the overestimate
of costs in periods prior to third quarter 2009 mentioned above. The increase in lease operating
expenses per Boe was in part due to the benefit of the overestimate of costs in periods prior to
third quarter 2009 mentioned above, offset in part by additional production from our wells
successfully drilled and completed in 2009 and 2010 where we are receiving benefits from economies
of scale.
Ad valorem taxes have increased primarily as a result of increased valuations of our Texas
properties, and the increase in our number of wells primarily associated with the Wolfberry
Acquisitions and 2009 and 2010 drilling activity.
47
Production taxes per unit of production were $5.30 per Boe during the three months ended
September 30, 2010, an increase of 42 percent from $3.72 per Boe during the three months ended
September 30, 2009. The increase was related to the increase in commodity prices and our increase
in oil and natural gas revenues related to increased volumes coupled
with a $2.2 million ($0.56 per
Boe) increase in production taxes related to prior period adjustments on one of our assets in our
New Mexico Permian area. Over the same period, our per Boe prices (excluding the effects of
derivatives) increased 15 percent.
Workover expenses were approximately $0.2 million for the three months ended September 30,
2009, which were primarily related to workovers in the New Mexico Permian area performed to restore
production.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the three months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Geological and geophysical |
|
$ |
449 |
|
|
$ |
2,120 |
|
Exploratory dry holes |
|
|
|
|
|
|
474 |
|
Leasehold abandonments and other |
|
|
3,176 |
|
|
|
182 |
|
|
|
|
|
|
|
|
Total exploration and abandonments |
|
$ |
3,625 |
|
|
$ |
2,776 |
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, was $0.4 million and $2.1 million for
the three months ended September 30, 2010 and 2009, respectively.
During the three months ended September 30, 2009, we wrote-off additional costs associated
with a prior quarter unsuccessful exploratory well in our Texas Permian area.
For the three months ended September 30, 2010 and 2009, we recorded $3.2 million and $0.2
million, respectively, of leasehold abandonments, which were primarily related to non-core
prospects in our New Mexico Permian and Texas Permian areas.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the three months ended September 30, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties |
|
$ |
60,746 |
|
|
$ |
15.58 |
|
|
$ |
53,824 |
|
|
$ |
18.75 |
|
Depreciation of other property and equipment |
|
|
766 |
|
|
|
0.20 |
|
|
|
624 |
|
|
|
0.22 |
|
Amortization of intangible asset operating rights |
|
|
388 |
|
|
|
0.10 |
|
|
|
387 |
|
|
|
0.13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization |
|
$ |
61,900 |
|
|
$ |
15.88 |
|
|
$ |
54,835 |
|
|
$ |
19.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end |
|
$ |
73.85 |
|
|
|
|
|
|
$ |
67.00 |
|
|
|
|
|
Natural gas price used to estimate proved natural gas reserves at period end |
|
$ |
4.41 |
|
|
|
|
|
|
$ |
3.30 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $60.7 million ($15.58 per Boe) for
the three months ended September 30, 2010, an increase of $6.9 million (13 percent) from $53.8
million ($18.75 per Boe) for the three months ended September 30, 2009.
The increase in depletion expense was primarily due to capitalized costs associated with new
wells that were successfully drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions,
and was offset in part by the increase in the oil and natural gas prices between the periods
utilized to determine proved reserves. The decrease in depletion expense per Boe was primarily due
to (i) the increase in the oil and natural gas prices between the periods utilized to determine
proved reserves, (ii) the increase in proved reserves
48
from the successful 2009 and 2010 drilling of
unproved properties and (iii) the increase in total proved reserves due to the new rules related to
disclosures of oil and natural gas reserves issued by the United States Securities and Exchange
Commission (the SEC).
On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural
gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved
reserves in 2009. We included the additional proved reserves in our depletion computation in the
fourth quarter of 2009 and first three quarters of 2010. Our third quarter of 2010 depletion
expense rate was $15.58 per Boe, which is lower than past quarters in part due to these additional
proved reserves. In the future, making comparisons to prior periods as it relates to our depletion
rate may be difficult as a result of these new SEC rules.
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and
individuals affiliated with Henry Petroleum LP (collectively the Henry Entities). The intangible
asset is currently being amortized over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due primarily to downward adjustments to the economically recoverable proved
reserves associated with declines in commodity prices and well performance, we recognized a
non-cash charge against earnings of $1.9 million during the three months ended September 30, 2010,
which was primarily attributable to natural gas related properties in our New Mexico Permian area.
For the three months ended September 30, 2009, we recognized a non-cash charge against earnings of
$1.1 million, which was primarily attributable to a downward revision of proved reserves primarily
related to a property in our New Mexico Permian area.
General and administrative expenses. The following table provides components of our general
and administrative expenses for the three months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
15,227 |
|
|
$ |
3.92 |
|
|
$ |
10,986 |
|
|
$ |
3.83 |
|
Non-recurring bonus paid to Henry Entities employees |
|
|
121 |
|
|
|
0.03 |
|
|
|
2,369 |
|
|
|
0.83 |
|
Non-cash stock-based compensation stock options |
|
|
564 |
|
|
|
0.14 |
|
|
|
1,315 |
|
|
|
0.46 |
|
Non-cash stock-based compensation restricted stock |
|
|
2,588 |
|
|
|
0.66 |
|
|
|
1,233 |
|
|
|
0.43 |
|
Less: Third-party operating fee reimbursements |
|
|
(3,455 |
) |
|
|
(0.89 |
) |
|
|
(3,188 |
) |
|
|
(1.11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
15,045 |
|
|
$ |
3.86 |
|
|
$ |
12,715 |
|
|
$ |
4.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $15.0 million ($3.86 per Boe) for the three months
ended September 30, 2010, an increase of $2.3 million (18 percent) from $12.7 million ($4.44 per
Boe) for the three months ended September 30, 2009. The increase in general and administrative
expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based
compensation awards and (ii) an increase in the number of employees and related personnel expenses
to handle our increased activities, partially offset by (i) a single month of the non-recurring
bonus due to the Henry Entities employees in the third quarter of 2010 and (ii) an increase in
third-party operating fee reimbursements. The decrease in total general and administrative expenses
per Boe was primarily due to increased production associated with (i) additional production from
our wells successfully drilled and completed in 2009 and 2010 and (ii) additional production from
our Wolfberry Acquisitions for which we added no administrative personnel.
In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of
the Henry Entities former employees a predetermined bonus amount, in addition to the compensation
we pay these employees, at each of the first and second anniversaries of the closing of the
acquisition. Since these employees earned this bonus over the two years following the acquisition
and it is outside
of our control, we are reflecting the cost in our general and administrative costs as
non-recurring. The final payment of the Henry Entities bonuses occurred in July 2010.
49
We earn reimbursements as operator of certain oil and natural gas properties in which we own
interests. As such, we earned reimbursements of $3.5 million and $3.2 million during the three
months ended September 30, 2010 and 2009, respectively. This reimbursement is reflected as a
reduction of general and administrative expenses in the consolidated statements of operations.
Loss on derivatives not designated as hedges. The following table sets forth the cash
settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated
as hedges for the three months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
(1,034 |
) |
|
$ |
(13,971 |
) |
Commodity derivatives natural gas |
|
|
(4,258 |
) |
|
|
(3,395 |
) |
Financial derivatives interest |
|
|
1,224 |
|
|
|
1,241 |
|
|
|
|
|
|
|
|
|
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
79,815 |
|
|
|
12,821 |
|
Commodity derivatives natural gas |
|
|
(10,300 |
) |
|
|
8,442 |
|
Financial derivatives interest |
|
|
660 |
|
|
|
2,645 |
|
|
|
|
|
|
|
|
Loss on derivatives not designated as hedges |
|
$ |
66,107 |
|
|
$ |
7,783 |
|
|
|
|
|
|
|
|
Interest expense. The following table sets forth interest expense, weighted average interest
rates and weighted average debt balances for the three months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
September 30, |
(dollars in thousands) |
|
2010 |
|
2009 |
|
Interest expense |
|
$ |
12,036 |
|
|
$ |
6,809 |
|
|
Weighted average interest rate |
|
|
5.5 |
% |
|
|
3.2 |
% |
|
Weighted average debt balance |
|
$ |
698,038 |
|
|
$ |
664,633 |
|
In September 2009, we refinanced $300 million of our credit facility debt with 8.625 percent
unsecured senior notes. The increase in our weighted average interest rate and the increase in
interest expense of approximately $5.2 million was primarily due to the higher interest rate on the
unsecured senior notes.
Income tax provisions. We recorded income tax expense of $10.1 million and $21.8 million for
the three months ended September 30, 2010 and 2009, respectively. The effective income tax rate for
the three months ended September 30, 2010 and 2009 was 32.7 percent and 52.5 percent, respectively.
At September 30, 2010 and 2009, we estimate our annual effective tax rate to be approximately 37.0
percent and 31.0 percent, respectively, (which is discussed later in this document) and at June 30,
2010 and 2009 we estimated our annual effective tax rate to be 37.4 percent and 42.1 percent,
respectively. The annual effective tax rate is determined by estimating the annual permanent tax
differences and the annual pre-tax book income. Our estimates involve assumptions we believe to be
reasonable at the time of the estimation. The three months ended September 30, 2010 and 2009
includes approximately $1.3 million of tax benefit and
$8.9 million of tax expense, respectively, associated with
the effects of the change in the six months ended June 30, 2010 and 2009 and nine months ended
September 30, 2010 and 2009 estimated annual effective tax rates.
We expect to record an approximate $8 million charge to income tax expense in the fourth
quarter of 2010 to increase the tax rate we have utilized to record our net deferred tax liability.
This increase in tax rate is due to an increase in our overall blended statutory state income tax
rate, which is a result of the assets acquired in the Marbob acquisition and the Marbob
preferential right dispute being located in New Mexico where the state income tax rate is higher
than in Texas.
50
Nine months ended September 30, 2010 Compared to Nine months ended September 30, 2009
Oil and natural gas revenues. Revenue from oil and natural gas operations was $668.2
million for the nine months ended September 30, 2010, an increase of $301.4 million (82 percent)
from $366.8 million for the nine months ended September 30, 2009. This increase was primarily due
to increases in realized oil and natural gas prices and increased production (i) as a result of the
Wolfberry Acquisitions and (ii) due to successful drilling efforts during 2009 and 2010.
Specifically the:
|
|
|
average realized oil price (excluding the effects of derivative activities) was
$73.73 per Bbl during the nine months ended September 30, 2010, an increase of 39
percent from $53.00 per Bbl during the nine months ended September 30, 2009; |
|
|
|
|
total oil production was 7,163 MBbl for the nine months ended September 30, 2010, an
increase of 1,733 MBbl (32 percent) from 5,430 MBbl for the nine months ended September
30, 2009; |
|
|
|
|
average realized natural gas price (excluding the effects of derivative activities)
was $6.87 per Mcf during the nine months ended September 30, 2010, an increase of 40
percent from $4.90 per Mcf during the nine months ended September 30, 2009; and |
|
|
|
|
total natural gas production was 20,393 MMcf for the nine months ended September 30,
2010, an increase of 4,271 MMcf (26 percent) from 16,122 MMcf for the nine months ended
September 30, 2009. |
Production expenses. The following table provides the components of our total oil and natural
gas production costs for the nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Lease operating expenses |
|
$ |
60,928 |
|
|
$ |
5.77 |
|
|
$ |
45,867 |
|
|
$ |
5.65 |
|
Taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ad valorem |
|
|
7,387 |
|
|
|
0.70 |
|
|
|
3,445 |
|
|
|
0.42 |
|
Production |
|
|
50,717 |
|
|
|
4.80 |
|
|
|
26,047 |
|
|
|
3.21 |
|
Workover costs |
|
|
3,188 |
|
|
|
0.30 |
|
|
|
663 |
|
|
|
0.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas production expenses |
|
$ |
122,220 |
|
|
$ |
11.57 |
|
|
$ |
76,022 |
|
|
$ |
9.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Among the cost components of production expenses, in general, we have some control over lease
operating expenses and workover costs on properties we operate, but production and ad valorem taxes
are directly related to commodity price changes.
Lease operating expenses were $60.9 million ($5.77 per Boe) for the nine months ended
September 30, 2010, an increase of $15.1 million (33 percent) from $45.9 million ($5.65 per Boe)
for the nine months ended September 30, 2009. The increase in lease operating expenses was
primarily due to (i) our wells successfully drilled and completed in 2009 and 2010 and (ii)
additional interests acquired in the Wolfberry Acquisitions in December 2009. The increase in lease
operating expenses per Boe was primarily due to (i) our wells successfully drilled and completed in
2009 and 2010 and (ii) additional interests acquired in the Wolfberry Acquisitions in December
2009, offset in part by additional production from our wells successfully drilled and completed in
2009 and 2010 where we are receiving benefits from economies of scale.
Ad valorem taxes have increased primarily as a result of increased valuations of our Texas
properties and the increase in our number of wells primarily associated with the Wolfberry
Acquisitions and 2009 and 2010 drilling activity.
Production taxes per unit of production were $4.80 per Boe during the nine months ended
September 30, 2010, an increase of 50 percent from $3.21 per Boe during the nine months ended
September 30, 2009. The increase was directly related to the increase in commodity prices and our
increase in oil and natural gas revenues related to increased volumes
coupled with a $2.2 million
($0.21 per
51
Boe) increase in production taxes related to prior periods on one of our assets in our New
Mexico Permian area. Over the same period, our per Boe prices (excluding the effects of
derivatives) increased 40 percent.
Workover expenses were approximately $3.2 million and $0.7 million for the nine months ended
September 30, 2010 and 2009, respectively. The 2010 amounts related primarily to increased
workovers during the first two quarters of 2010 in our New Mexico Permian area due to work
performed to restore production, whereas the 2009 amounts related primarily to workovers in our
Texas Permian area.
Exploration and abandonments expense. The following table provides a breakdown of our
exploration and abandonments expense for the nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Geological and geophysical |
|
$ |
1,677 |
|
|
$ |
3,245 |
|
Exploratory dry holes |
|
|
218 |
|
|
|
2,340 |
|
Leasehold abandonments and other |
|
|
3,903 |
|
|
|
4,610 |
|
|
|
|
|
|
|
|
Total exploration and abandonments |
|
$ |
5,798 |
|
|
$ |
10,195 |
|
|
|
|
|
|
|
|
Our geological and geophysical expense, which primarily consists of the costs of acquiring and
processing seismic data, geophysical data and core analysis, was approximately $1.7 million and
$3.2 million for the nine months ended September 30, 2010 and 2009, respectively.
During the nine months ended September 30, 2009, we wrote-off an unsuccessful exploratory well
in our Arkansas emerging play and two unsuccessful exploratory wells in our Texas Permian area.
For the nine months ended September 30, 2010, we recorded $3.9 million of leasehold
abandonments, which were primarily related to non-core prospects in our New Mexico Permian and
Texas Permian areas. For the nine months ended September 30, 2009, we recorded approximately $4.6
million of leasehold abandonments, which related primarily to the write-off of four non-core
prospects in our New Mexico Permian area and three non-core prospects in our Texas Permian area.
Depreciation, depletion and amortization expense. The following table provides components of
our depreciation, depletion and amortization expense for the nine months ended September 30, 2010
and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
Depletion of proved oil and natural gas properties |
|
$ |
166,514 |
|
|
$ |
15.77 |
|
|
$ |
154,819 |
|
|
$ |
19.07 |
|
Depreciation of other property and equipment |
|
|
2,168 |
|
|
|
0.21 |
|
|
|
1,998 |
|
|
|
0.25 |
|
Amortization of intangible asset operating rights |
|
|
1,162 |
|
|
|
0.10 |
|
|
|
1,168 |
|
|
|
0.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortization |
|
$ |
169,844 |
|
|
$ |
16.08 |
|
|
$ |
157,985 |
|
|
$ |
19.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price used to estimate proved oil reserves at period end |
|
$ |
73.85 |
|
|
|
|
|
|
$ |
67.00 |
|
|
|
|
|
Natural gas price used to estimate proved natural gas reserves at period end |
|
$ |
4.41 |
|
|
|
|
|
|
$ |
3.30 |
|
|
|
|
|
Depletion of proved oil and natural gas properties was $166.5 million ($15.77 per Boe)
for the nine months ended September 30, 2010, an increase of $11.7 million (8 percent) from $154.8
million ($19.07 per Boe) for the nine months ended September 30, 2009. The increase in depletion
expense was primarily due to capitalized costs associated with new wells that were successfully
drilled and completed in 2009 and 2010 and the Wolfberry Acquisitions, and was offset in part by
the increase in the oil and natural gas prices between the periods utilized to determine proved
reserves. The decrease in depletion expense per Boe was primarily due to (i) the
52
increase in the
oil and natural gas prices between the periods utilized to determine proved reserves, (ii) the
increase in proved reserves
from the successful 2009 and 2010 drilling of unproved properties and (iii) the increase in
total proved reserves due to the new SEC rules related to disclosures of oil and natural gas
reserves.
On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural
gas reserves. As a result of these new SEC rules, we recorded an additional 13.6 MMBoe of proved
reserves in 2009. We included the additional proved reserves in our depletion computation in the
fourth quarter of 2009 and first three quarters of 2010. Our depletion expense rate for the nine
months ended September 30, 2010, was $15.77 per Boe, which is lower than the same period last year
in part due to these additional proved reserves. In the future, making comparisons to prior periods
as it relates to our depletion rate may be difficult as a result of these new SEC rules.
The amortization of the intangible asset is a result of the value assigned to the operating
rights that we acquired in the July 2008 acquisition of Henry Petroleum LP and certain entities and
individuals affiliated with the Henry Entities. The intangible asset is currently being amortized
over an estimated life of approximately 25 years.
Impairment of long-lived assets. We periodically review our long-lived assets to be held and
used, including proved oil and natural gas properties accounted for under the successful efforts
method of accounting. Due primarily to downward adjustments to the economically recoverable proved
reserves associated with declines in commodity prices and well performance, we recognized a
non-cash charge against earnings of $9.2 million during the nine months ended September 30, 2010,
which was primarily attributable to natural gas related properties in our New Mexico Permian area.
For the nine months ended September 30, 2009, we recognized a non-cash charge against earnings of
$9.7 million, which was primarily attributable to non-core natural gas related properties in our
New Mexico Permian area.
General and administrative expenses. The following table provides components of our general
and administrative expenses for the nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
Per |
|
|
|
|
|
|
Per |
|
(in thousands, except per unit amounts) |
|
Amount |
|
|
Boe |
|
|
Amount |
|
|
Boe |
|
|
General and administrative expenses recurring |
|
$ |
42,223 |
|
|
$ |
4.01 |
|
|
$ |
32,925 |
|
|
$ |
4.06 |
|
Non-recurring bonus paid to Henry Entities employees |
|
|
5,059 |
|
|
|
0.48 |
|
|
|
7,680 |
|
|
|
0.95 |
|
Non-cash stock-based compensation stock options |
|
|
2,152 |
|
|
|
0.20 |
|
|
|
3,228 |
|
|
|
0.40 |
|
Non-cash stock-based compensation restricted stock |
|
|
6,702 |
|
|
|
0.63 |
|
|
|
3,433 |
|
|
|
0.42 |
|
Less: Third-party operating fee reimbursements |
|
|
(9,995 |
) |
|
|
(0.95 |
) |
|
|
(8,633 |
) |
|
|
(1.06 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative expenses |
|
$ |
46,141 |
|
|
|
4.37 |
|
|
$ |
38,633 |
|
|
$ |
4.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses were $46.1 million ($4.37 per Boe) for the nine months
ended September 30, 2010, an increase of $7.5 million (19 percent) from $38.6 million ($4.77 per
Boe) for the nine months ended September 30, 2009. The increase in general and administrative
expenses was primarily due to (i) an increase in non-cash stock-based compensation for stock-based
compensation awards and (ii) an increase in the number of employees and related personnel expenses
to handle our increased activities, partially offset by (i) a decrease in the non-recurring bonus
due to the Henry Entities employees (discussed in the next paragraph) and (ii) an increase in
third-party operating fee reimbursements. The decrease in total general and administrative expenses
per Boe was primarily due to increased production associated with (i) additional production from
our wells successfully drilled and completed in 2009 and 2010 and (ii) additional production from
our Wolfberry Acquisitions for which we added no administrative personnel.
In connection with the Henry Entities acquisition in July 2008, we agreed to pay certain of
the Henry Entities former employees a predetermined bonus amount, in addition to the compensation
we pay these employees, at each of the first and second anniversaries of the closing of the
acquisition. Since these employees earned this bonus over the two years following the acquisition
and it is outside of our control, we are reflecting the cost in our general and administrative
costs as non-recurring. The final payment of the Henry Entities bonuses occurred in July 2010.
53
We earn reimbursements as operator of certain oil and natural gas properties in which we own
interests. As such, we earned reimbursements of $10.0 million and $8.6 million during the nine
months ended September 30, 2010 and 2009, respectively. This reimbursement is reflected as a
reduction of general and administrative expenses in the consolidated statements of operations.
(Gain) loss on derivatives not designated as hedges. The following table sets forth the cash
settlements and the non-cash mark-to-market adjustment for the derivative contracts not designated
as hedges for the nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
September 30, |
|
(in thousands) |
|
2010 |
|
|
2009 |
|
|
Cash payments (receipts): |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
$ |
11,951 |
|
|
$ |
(70,383 |
) |
Commodity derivatives natural gas |
|
|
(10,378 |
) |
|
|
(9,227 |
) |
Financial derivatives interest |
|
|
3,658 |
|
|
|
2,020 |
|
Mark-to-market (gain) loss: |
|
|
|
|
|
|
|
|
Commodity derivatives oil |
|
|
(40,926 |
) |
|
|
156,920 |
|
Commodity derivatives natural gas |
|
|
(30,978 |
) |
|
|
13,460 |
|
Financial derivatives interest |
|
|
4,444 |
|
|
|
1,645 |
|
|
|
|
|
|
|
|
(Gain) loss on derivatives not designated as hedges |
|
$ |
(62,229 |
) |
|
$ |
94,435 |
|
|
|
|
|
|
|
|
Interest expense. The following table sets forth interest expense, weighted average interest
rates and weighted average debt balances for the nine months ended September 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
September 30, |
(dollars in thousands) |
|
2010 |
|
2009 |
|
Interest expense |
|
$ |
34,293 |
|
|
$ |
17,379 |
|
|
Weighted average interest rate |
|
|
5.4 |
% |
|
|
2.7 |
% |
|
Weighted average debt balance |
|
$ |
690,797 |
|
|
$ |
666,864 |
|
In September 2009, we refinanced $300 million of our credit facility debt with 8.625 percent
unsecured senior notes. The increase in our weighted average interest rate and the increase in
interest expense of approximately $16.9 million was primarily due to the higher interest rate on
the unsecured senior notes. The increase in the weighted average debt balance during the nine
months ended September 30, 2010 is due, in part, to our borrowings under our credit facility to
finance the Wolfberry Acquisitions, offset by a partial repayment on our credit facility in
February 2010 with the net proceeds of our equity offering.
Income tax provisions. We recorded income tax expense of $124.8 million and an income tax
benefit of $12.0 million for the nine months ended September 30, 2010 and 2009, respectively. The
effective income tax rate for the nine months ended September 30, 2010 and 2009 was 37.0 percent
and 31.0 percent, respectively. The lower annual effective tax rate in 2009 compared to 2010 is
primarily due to the estimated annual 2010 and 2009 permanent tax differences compared to the
related current estimated annual pre-tax book income. The estimated annual effective tax rate for
2010 and 2009 at June 30, 2010 and 2009 was 37.0 percent and 42.1 percent, respectively, based on
the then estimated 2010 and 2009 annual permanent tax differences and pre-tax book income.
Depending on the levels of estimated permanent differences and annual pre-tax book income and
changes in those amounts between quarters can significantly alter our estimated effective tax
rates between periods.
We expect to record an approximate $8 million charge to income tax expense in the fourth
quarter of 2010 to increase the tax rate we have utilized to record our net deferred tax liability.
This increase in tax rate is due to an increase in our overall blended statutory state income tax
rate, which is a result of the assets acquired in the Marbob acquisition and the Marbob
preferential right dispute being
located in New Mexico where the state income tax rate is higher than in Texas.
54
Capital Commitments, Capital Resources and Liquidity
Capital commitments. Our primary needs for cash are development, exploration and
acquisition of oil and natural gas assets, payment of contractual obligations and working capital
obligations. Funding for these cash needs may be provided by any combination of
internally-generated cash flow, financing under our credit facility, proceeds from the disposition
of assets or alternative financing sources, as discussed in Capital resources below.
Oil and natural gas properties. Our costs incurred on oil and natural gas properties,
excluding acquisitions and asset retirement obligations, during the nine months ended September 30,
2010 and 2009 totaled $471.5 million and $293.1 million, respectively, as compared to the
comparable amount in cash flows used by investing activities of $486.9 million and $316.8 million
for the respective periods. The primary reason for the differences in the costs incurred and cash
flow expenditures is the timing of payments. These expenditures in 2010 were significantly funded
by cash flow from operations (including effects of cash settlements received from (paid on)
derivatives not designated as hedges) and to a lesser extent from borrowing under our credit
facility.
In August 2010, we announced an increase of our 2010 capital budget to $700 million. At the
present, we expect our 2010 planned capital expenditures to be approximately $760 million, which
excludes acquisitions (other than the customary purchase of leasehold acreage) and includes
approximately $57 million of capital expenditures planned for the fourth quarter of 2010 on the
properties acquired in the Marbob acquisition and the Marbob preferential right dispute. Based on
current commodity prices and our expectations, we believe our 2010 planned capital expenditures
will exceed our 2010 cash flow. Originally, our capital budget was front-end loaded, and we
expected to outspend our cash flow in the first half of 2010. We outspent our after-tax operating
cash flow during the nine months ended September 30, 2010 by
over $65 million, excluding
acquisitions. As our size and financial flexibility have grown, we now take a longer-term view on
spending substantially within our cash flow, and our spending during any specific period may exceed
our cash flow for that period. However, our capital budget is largely discretionary, and if we
experience sustained oil and natural gas prices significantly below the current levels or
substantial increases in our drilling and completion costs, we may reduce our capital spending
program to be substantially within our cash flow.
In October 2010, we closed the Marbob acquisition and settled our Marbob preferential right
dispute. For additional information see Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations Recent events.
In October 2010, we announced our plans to divest certain Permian Basin assets which are
generally not in our core areas and which have higher per unit lifting costs than our average
portfolio of assets. Our current expectation is that if we are able to successfully divest of these
assets, the proceeds from this divesture would be over $100 million and that we would close before
the end of 2010.
In November 2010, we announced our 2011 capital budget of approximately $1.1 billion, which we
expect can be funded substantially within our cash flow, based on current commodity prices and our
expectations. As our size and financial flexibility have grown, we now take a longer-term view on
spending substantially within our cash flow, and our spending during any specific period may exceed
our cash flow for that period. However, our capital budget is largely discretionary, and if we
experience sustained oil and natural gas prices significantly below the current levels or
substantial increases in our drilling and completion costs, we may reduce our capital spending
program to be substantially within our cash flow.
Other than the purchase of leasehold acreage, our current 2010 capital expenditure plan and
2011 capital budget is exclusive of acquisitions. We do not have a specific acquisition budget,
since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to
purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer
or seller of properties at various times. We seek to acquire oil and natural gas properties that
provide opportunities for the addition of reserves and production through a combination of
development, high-potential exploration and control of operations that will allow us to apply our
operating expertise.
Although we cannot provide any assurance, we generally attempt to fund our non-acquisition
expenditures with our available cash and cash flow as adjusted from time to time; however, we may
also use our credit facility, or other alternative financing sources, to fund such expenditures.
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 availability of drilling rigs and other services and
equipment, regulatory, technological and competitive developments and market conditions. In
addition, under certain circumstances we would consider increasing or reallocating our capital
spending plans.
Acquisitions. Our expenditures for acquisitions of proved and unproved properties (which
includes customary leasehold acreage acquisitions) during the three months ended September 30, 2010
and 2009 totaled approximately $14.6 million and $7.2 million, respectively, and approximately
$49.4 million and $10.7 million during the nine months ended September 30, 2010 and 2009,
55
respectively. The acquisitions of proved properties during the nine months ended September 30,
2010, primarily relate to additional interests that we closed in 2010 on the Wolfberry Acquisitions
and the acquisition of other Wolfberry assets.
Contractual obligations. Our contractual obligations include long-term debt, cash interest
expense on debt, operating lease obligations, drilling commitments, employment agreements with
executive officers, contractual bonus payments, derivative liabilities and other obligations. Since
December 31, 2009, the material changes in our contractual obligations included a $157.5 million
decrease in outstanding long-term borrowings, a $23.4 million decrease in cash interest expense on
debt and our net commodity derivative is now in an asset position of approximately $0.6 million.
However, subsequent to September 30, 2010, our debt substantially increased as a result of the
closing of the Marbob acquisition and the Marbob preferential right dispute. See Note J of
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 nine months ended September 30, 2010.
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
operating activities (including the cash settlements received from (paid on) derivatives not
designated as hedges presented in our investing activities) and financing provided by our credit
facility. We believe that our cash flows may not be adequate to meet both our short-term working
capital requirements and our current 2010 capital expenditure plans (excluding the Marbob
acquisition and the Marbob preferential right dispute). We believe we have adequate availability
under our credit facility to fund cash flow deficits, though we could reduce our capital spending
program to remain substantially within our cash flow.
Cash flow from operating activities. Our net cash provided by operating activities was $402.8
million and $232.1 million for the nine months ended September 30, 2010 and 2009, respectively. The
increase in operating cash flows during the nine months ended September 30, 2010 over the same
period in 2009 was principally due to increases in average realized oil and natural gas prices
coupled with increased production.
Cash flow used in investing activities. During the nine months ended September 30, 2010 and
2009, we invested $504.6 million and $316.8 million, respectively, for additions to, and
acquisitions of, oil and natural gas properties, inclusive of dry hole costs. Cash flows used in
investing activities were higher during the nine months ended September 30, 2010 over 2009, due to
the Wolfberry Acquisitions and an increase in our capital expenditures on oil and natural gas
properties, offset by settlements paid on derivatives not designated as hedges during the nine
months ended September 30, 2010 as compared to receipts on derivatives not designated as hedges in
the comparable period in 2009.
Cash flow from financing activities. Net cash provided by financing activities was $107.2
million and $7.7 million for the nine months ended September 30, 2010 and 2009, respectively.
During the nine months ended September 30, 2010, we reduced our outstanding balance on our credit
facility by $157.5 million primarily using proceeds from the issuance of common stock. During the
nine months ended September 30, 2009, we had net borrowings of $15.7 million under our credit
facility.
Our credit facility, as amended, has a maturity date of July 31, 2013. At September 30, 2010,
we had letters of credit outstanding under the credit facility of approximately $25,000, and our
availability to borrow additional funds was approximately $807.5 million based on the borrowing
base of $1.2 billion. On October 7, 2010, in connection with the closing of the Marbob acquisition,
we entered into an amendment to our credit facility to increase the borrowing base from $1.2
billion to $2.0 billion, as further discussed below. The next scheduled borrowing base
redetermination will be in April 2011. Between scheduled borrowing base redeterminations, we and,
if requested by 66 2/3 percent of the lenders, the lenders, may each request one special
redetermination.
Advances on the credit facility bear interest, at our option, based on (i) the prime rate of
JPMorgan Chase Bank (JPM Prime Rate) (3.25 percent at September 30, 2010) or (ii) a Eurodollar
rate (substantially equal to the London Interbank Offered Rate). At September 30, 2010, the
interest rates of Eurodollar rate advances and JPM Prime Rate advances varied, with interest
margins ranging from 200 to 300 basis points and 112.5 to 212.5 basis points, respectively, per
annum depending on the debt balance outstanding. At September 30, 2010, we paid commitment fees on
the unused portion of the available borrowing base of 50 basis points per annum.
On July 19, 2010, we entered into a common stock purchase agreement with certain third-party
accredited investors to sell 6.6 million shares of our common stock at a price of $45.30 per share
in a private placement for aggregate cash consideration of approximately $300 million. We paid
approximately $7.3 million of transaction costs, including a placement agent fee. On October 7,
2010, we closed the private placement simultaneously with the closing of the Marbob acquisition.
56
On October 7, 2010, we amended our credit facility simultaneously with the closing of the
Marbob acquisition to increase the borrowing base from $1.2 billion to $2.0 billion. We paid our
bank group, now a total of 34 banks, approximately $23.6 million associated with the amendment and
for the previous commitments to increase the borrowing base. Pro forma at September 30, 2010, after
taking into account the closing of the Marbob acquisition, the
resolution of the Marbob preferential right
dispute, the closing of the credit facility amendment, the private placement and estimated related
transaction costs, we estimate our outstanding indebtedness under our credit facility would have
been approximately $1.5 billion and our availability under our credit facility would have been
approximately $470 million.
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. We may also sell assets and issue securities in exchange
for oil and natural gas assets or interests in oil and natural gas 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
by our board of directors. Utilization of some of these financing sources may require approval from
the lenders under our credit facility.
On February 1, 2010, we issued approximately 5.3 million shares of our common stock at $42.75
per share in a public offering. After deducting underwriting discounts of approximately $9.1
million and transaction costs, we received net proceeds of approximately $219.3 million. The net
proceeds from this offering were used to repay a portion of the borrowing under our credit
facility.
Financial markets. The current state of the financial markets remains uncertain; however, we
have recently seen improvements in the stock market, and the credit markets appear to have
stabilized. There have been financial institutions that have (i) failed and been forced into
government receivership, (ii) received government bail-outs, (iii) declared bankruptcy, (iv) been
forced to seek additional capital and liquidity to maintain viability or (v) merged. The United
States and world economies have experienced and continue to experience volatility, which continues
to impact the financial markets.
At September 30, 2010, we had $807.5 million of available borrowing capacity. Pro forma at
September 30, 2010, after taking into account the closing of the
Marbob acquisition, the resolution of the Marbob
preferential right dispute, the closing of the credit facility amendment, the private placement and
estimated related transaction costs, we estimate our outstanding indebtedness under our credit
facility would have been approximately $1.5 billion and our availability under our credit facility
would have been approximately $470 million. Our credit facility is backed by a large syndicate of
banks. Even in light of the volatility in the financial markets, we believe that the lenders under
our credit facility have the ability to fund additional borrowings we may need for our business.
We pay floating rate interest under our credit facility, and we are unable to predict,
especially in light of the uncertainty in the financial markets, whether we will incur increased
interest costs due to rising interest rates. We have used interest rate derivatives to mitigate
the cost of rising interest rates, and we may enter into additional interest rate derivatives in
the future. Additionally, we may issue additional fixed rate debt in the future to increase
available borrowing capacity under our credit facility, to extend the maturity of some of our
indebtedness or to reduce our exposure to the volatility of interest rates.
In the current financial markets, there is no assurance that we could refinance our credit
facility with comparable terms. Because our credit facility matures in July 2013, we do not expect
to seek refinancing of our credit facility any earlier than 2011.
To the extent we need additional funds beyond those available under our credit facility to
operate our business or make acquisitions, we would have to pursue other financing sources. These
sources could include issuance of (i) fixed and floating rate debt, (ii) convertible securities,
(iii) preferred stock, (iv) common stock or (v) other securities. We may also sell assets.
However, in light of the current financial market conditions there are no assurances that we could
obtain additional funding, or if available, at what cost and terms.
Liquidity. Our principal sources of short-term liquidity are cash on hand and available
borrowing capacity under our credit facility. At September 30, 2010, we had $0.4 million of cash
on hand.
At September 30, 2010, we had $807.5 million of available borrowing capacity. Pro forma at
September 30, 2010, after taking into account the closing of the
Marbob acquisition, the resolution of the Marbob
preferential right dispute, the private placement and estimated related transaction costs, our
outstanding indebtedness under our credit facility would have been approximately $1.5 billion and
availability under our credit facility would have been approximately $471 million. Our borrowing
base is redetermined semi-annually. The next scheduled borrowing base redetermination will be in
April 2011. Between scheduled borrowing base redeterminations, we and, if requested by 66 2/3
percent of the lenders, the lenders, may each request one special redetermination. In general,
redeterminations are based upon a number of factors, including commodity prices and reserve levels.
Upon a redetermination, our
57
borrowing base could be substantially reduced. In light of the current volatility in
commodity prices and the state of the financial markets, there is no assurance that our borrowing
base will not be reduced.
Book capitalization and current ratio. Our book capitalization at September 30, 2010 was $2.5
billion, consisting of debt of $688.6 million and stockholders equity of $1.8 billion. Our debt to
book capitalization was 28 percent and 39 percent at September 30, 2010 and December 31, 2009,
respectively. Our ratio of current assets to current liabilities was 0.69 to 1.0 at September 30,
2010 as compared to 0.64 to 1.0 at December 31, 2009.
At September 30, 2010, after taking into account the closing of the Marbob acquisition and the
Marbob preferential right dispute, the closing of the amendment to the credit facility, the private
placement and estimated related transaction costs, we estimate our debt to book capitalization to
be approximately 48 percent.
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
nine months ended September 30, 2010, we received an average of $73.73 per barrel of oil and $6.87
per Mcf of natural gas before consideration of commodity derivative contracts compared to $53.00
per barrel of oil and $4.90 per Mcf of natural gas in the nine months ended September 30, 2009.
Although certain of our costs are affected by general inflation, inflation does not normally have a
significant effect on our business. In a trend that began in 2004 and continued through the first
six months of 2008, commodity prices for oil and natural gas increased significantly. The higher
prices led to increased activity in the industry and, consequently, rising costs. These cost trends
have put pressure not only on our operating costs but also on capital costs. We expect these costs
to reflect upward pressure during 2010 and 2011 as a result of the recent improvements in oil
prices from 2009.
58
Critical Accounting Policies, Practices and Estimates
Our historical consolidated financial statements and related notes to consolidated
financial statements contain information that is pertinent to our managements 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 managements opinion, the more significant reporting areas impacted by managements
judgments and estimates are revenue recognition, 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 and valuation of stock-based compensation. Managements 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 nine months ended September 30, 2010. See our disclosure of critical accounting policies in the
consolidated financial statements included in our Annual Report on Form 10-K for the year ended
December 31, 2009, filed with the SEC on February 26, 2010.
Recent Accounting Pronouncements
Various topics. In February 2010, the FASB issued an update to various topics, which
eliminated outdated provisions and inconsistencies in the Accounting Standards Codification (the
Codification), and clarified certain guidance to reflect the FASBs original intent. The update
is effective for the first reporting period, including interim periods, beginning after issuance of
the update, except for the amendments affecting embedded derivatives and reorganizations. In
addition to amending the Codification, the FASB made corresponding changes to the legacy accounting
literature to facilitate historical research. These changes are included in an appendix to the
update. We adopted the update effective January 1, 2010, and the adoption did not have a
significant impact on our consolidated financial statements.
Accounting for extractive activities. In April 2010, the FASB issued an amendment to a
paragraph in the accounting standard for oil and natural gas extractive activities accounting. The
standard adds to the Codification the SECs Modernization of Oil and Gas Reporting release. We
adopted the update effective April 20, 2010, and the adoption did not have a significant impact on
our consolidated financial statements.
Accounting for leases. In August 2010, the FASB issued an Exposure Draft proposing a new
approach to lease accounting so that lessors and lessees present relevant, faithfully
representative information about the rights and obligations arising from leases that assists users
of financial statements in their assessment of the amounts, timing and uncertainty of the cash
flows arising from leases.
The existing accounting models for leases require lessees to classify their leases as either
capital leases or operating leases. However, those models have been criticized for failing to meet
the needs of users of financial statements because they do not provide a faithful representation of
leasing transactions. In particular, they omit relevant information about rights and obligations
that meet the definitions of assets and liabilities in the boards conceptual framework. The models
also lead to a lack of comparability and undue complexity because of the sharp bright-line
distinction between capital leases and operating leases. As a result, many users of financial
statements adjust the amounts presented in the statement of financial position to reflect the
assets and liabilities arising from operating leases.
Accordingly, the FASB and the International Accounting Standards Board initiated a joint
project to develop a new approach to lease accounting that would ensure that assets and liabilities
arising under leases are recognized in the statement of financial position.
Currently, we lease vehicles, equipment and office facilities under non-cancellable operating
leases. If the Exposure Draft were to become a standard, we would no longer report lease payments
in the consolidated statements of operations, and we would capitalize these leases on our
consolidated balance sheets and depreciate them over their useful lives. We are currently
evaluating the impact on our consolidated financial statements.
59
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following market risk disclosures should be read in conjunction with the quantitative
and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the
year ended December 31, 2009.
We are exposed to a variety of market risks including credit risk, commodity price risk and
interest rate risk. We address these risks through a program of risk management which includes the
use of derivative instruments. The following quantitative and qualitative information is provided
about financial instruments to which we are a party at September 30, 2010, and from which we may
incur future gains or losses from changes in market interest rates or commodity prices and losses
from extension of credit. We do not enter into derivative or other financial instruments for
speculative or trading purposes.
Hypothetical changes in interest rates and commodity prices chosen for the following estimated
sensitivity analysis are considered to be reasonably possible near-term changes generally based on
consideration of past fluctuations for each risk category. However, since it is not possible to
accurately predict future changes in interest rates and commodity prices, these hypothetical
changes may not necessarily be an indicator of probable future fluctuations.
Credit risk. We monitor our risk of loss due to non-performance by counterparties of their
contractual obligations. Our principal exposure to credit risk is through the sale of our oil and
natural gas production, which we market to energy marketing companies and refineries and to a
lesser extent our derivative counterparties. We monitor our exposure to these counterparties
primarily by reviewing credit ratings, financial statements and payment history. We extend credit
terms based on our evaluation of each counterpartys creditworthiness. Although we have not
generally required our counterparties to provide collateral to support their obligation to us, we
may, if circumstances dictate, require collateral in the future. In this manner, we could further
reduce credit risk.
Commodity price risk. We are exposed to market risk as the prices of oil and natural gas are
subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to
changes in the prices of oil and natural gas we have entered into, and may in the future enter
into, additional commodity price risk management arrangements for a portion of our oil and natural
gas production. The agreements that we have entered into generally have the effect of providing us
with a fixed price for a portion of our expected future oil and natural gas production over a
specified period of time. Our commodity price risk management activities could have the effect of
reducing net income and the value of our common stock. An average increase in the commodity price
of $10.00 per barrel of oil and $1.00 per MMBtu for natural gas from the commodity prices at
September 30, 2010, would have created a net unrealized loss of
approximately $165.3 million on our
commodity price risk management contracts held at September 30, 2010.
At September 30, 2010, we had (i) oil price swaps that settle on a monthly basis covering
future oil production from July 1, 2010 through June 30, 2015 and (ii) a natural gas price swap,
natural gas price collars and natural gas basis swaps covering future natural gas production from
July 1, 2010 to December 31, 2012. See Note I of the Condensed Notes to Consolidated Financial
Statements included in Item 1. Consolidated Financial Statements (Unaudited) for additional
information on our commodity derivative contracts. The average NYMEX oil price and average NYMEX
natural gas price for the nine months ended September 30, 2010, was $77.60 per Bbl and $4.54 per
MMBtu, respectively. At November 2, 2010, the NYMEX oil price
and NYMEX natural gas price were $83.90
per Bbl and $3.87 per MMBtu, respectively. A decrease in oil and natural gas prices would
increase the fair value asset of our commodity derivative contracts from their recorded balance at
September 30, 2010. Changes in the recorded fair value of the undesignated commodity derivative
contracts are marked-to-market through earnings as unrealized gains or losses. The potential
increase in our fair value asset would be recorded in earnings as an unrealized gain. However, an
increase in the average NYMEX oil and natural gas prices above those at September 30, 2010, would
result in a decrease in our fair value asset and be recorded as an unrealized loss in earnings. We
are currently unable to estimate the effects on the earnings of future periods resulting from
changes in the market value of our commodity derivative contracts.
Interest rate risk. Our exposure to changes in interest rates relates primarily to debt
obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain
percentage of total capitalization and by monitoring the effects of market changes in interest
rates. To reduce our exposure to changes in interest rates we have entered into, and may in the
future enter into additional interest rate risk management arrangements for a portion of our
outstanding debt. The agreements that we have entered into generally have the effect of providing
us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate
derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related
to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure
and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest
rates as a result of our credit facility, and the terms of our credit facility require us to pay
higher interest rate margins as we utilize a larger percentage of our available borrowing base.
At September 30, 2010, we had interest rate swaps on $300 million of notional principal that
fixed the LIBOR interest rate (not including the interest rate margins discussed above) at 1.90
percent for the three years beginning in May 2009. An average decrease
60
in future interest rates of 25 basis points from the future rate at September 30, 2010, would
have increased our net unrealized liability on our interest rate risk management contracts by
approximately $1.2 million.
We had total indebtedness of $392.5 million outstanding under our credit facility at September
30, 2010. The impact of a 1 percent increase in interest rates on this amount of debt would result
in increased annual interest expense of approximately $3.9 million.
The fair value of our derivative instruments is determined based on our valuation models. We
did not change our valuation method during 2010. During 2010, we were party to commodity and
interest rate derivative instruments. See Note I of the Condensed Notes to Consolidated Financial
Statements included in Item 1. Consolidated Financial Statements (Unaudited) for additional
information regarding our derivative instruments. The following table reconciles the changes that
occurred in the fair values of our derivative instruments during the nine months ended September
30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments Net Assets (Liabilities) (a) |
|
(in thousands) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Fair value of contracts outstanding at December 31, 2009 |
|
$ |
(64,332 |
) |
|
$ |
(2,501 |
) |
|
$ |
(66,833 |
) |
Changes in fair values (b) |
|
|
70,331 |
|
|
|
(8,102 |
) |
|
|
62,229 |
|
Contract maturities |
|
|
1,573 |
|
|
|
3,658 |
|
|
|
5,231 |
|
|
|
|
|
|
|
|
|
|
|
Fair value of contracts outstanding at September 30, 2010 |
|
$ |
7,572 |
|
|
$ |
(6,945 |
) |
|
$ |
627 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Represents the fair values of open derivative contracts subject to market risk. |
|
(b) |
|
At inception, new derivative contracts entered into by us have no intrinsic value. |
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the
Exchange Act, we have evaluated, under the supervision and with the participation of our
management, including our principal executive officer and principal financial officer, the
effectiveness of the design and operation of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this
report. Our disclosure controls and procedures are designed to provide reasonable assurance that
the information required to be disclosed by us in reports that we file under the Exchange Act is
accumulated and communicated to our management, including our principal executive officer and
principal financial officer, as appropriate, to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time periods specified in
the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and
principal financial officer have concluded that our disclosure controls and procedures were
effective at September 30, 2010 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting. There have been no changes in our
internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act)
that occurred during our last fiscal quarter that have materially affected or are reasonably likely
to materially affect our internal controls over financial reporting.
61
PART II OTHER INFORMATION
Item 1. Legal Proceedings
We are party to the legal proceedings that are described in Notes K and Q of the
Condensed Notes to Consolidated Financial Statements included in Item 1. Consolidated Financial
Statements (Unaudited). We are party to certain proceedings and claims incidental to our business.
While many of these other matters involve inherent uncertainty, we believe that the liability, if
any, ultimately incurred with respect to such other proceedings and claims will not have a material
adverse effect on our consolidated financial position as a whole or on our liquidity, capital
resources or future results of operations.
Item 1A. Risk Factors
In addition to the other information set forth in this Report, you should carefully
consider the risks discussed in the Companys Annual Report on Form 10-K for the year ended
December 31, 2009, under the headings Item 1. Business Competition, Marketing Arrangements and
Applicable Laws and Regulations, Item 1A. Risk Factors and Item 7A. Quantitative and
Qualitative Disclosures About Market Risk, which risks could materially affect the Companys
business, financial condition or future results. Except for the risk factor set forth below, there
have been no material changes in the Companys risk factors from those described in its Annual
Report on Form 10-K for the year ended December 31, 2009, and Item 1A. Risk Factors in our
Quarterly Report on Form 10-Q for the six months ended June 30, 2010.
The risk factor below is intended to replace the risk factor
in our Annual Report on Form 10-K for the year ended December 31,
2009 entitled Our indebtedness could restrict our operations
and make us more vulnerable to adverse economic conditions.
We have substantial indebtedness and may incur substantially more debt. Higher levels of
indebtedness make us more vulnerable to economic downturns and adverse developments in our
business.
We have incurred debt amounting to approximately $688.6 million as of September 30, 2010. At
September 30, 2010, the borrowing base under our credit facility was $1.2 billion. At September 30,
2010, we had $807.5 million of available borrowing capacity. On October 7, 2010, in connection with
the closing of the Marbob acquisition, we entered into an amendment to our credit facility to
increase the borrowing base from $1.2 billion to $2.0 billion. Pro forma at September 30, 2010,
after taking into account the closing of the Marbob acquisition, the
resolution of the Marbob preferential right
dispute, the closing of the credit facility amendment, the private placement and estimated related
transaction costs, we estimate our outstanding indebtedness under our credit facility would have
been approximately $1.5 billion and our availability under our credit facility would have been
approximately $470 million.
As a result of our indebtedness, we will need to use a portion of our cash flow to pay
interest, which will reduce the amount we will have available to finance our operations and other
business activities and could limit our flexibility in planning for or reacting to changes in our
business and the industry in which we operate. Our indebtedness under our credit facility is at a
variable interest rate, and so a rise in interest rates will generate greater interest expense to
the extent we do not have applicable interest rate fluctuation hedges. The amount of our debt may
also cause us to be more vulnerable to economic downturns and adverse developments in our business.
We may incur substantially more debt in the future. The indentures governing our outstanding
8.625 percent unsecured senior notes due 2017 contain restrictions on our incurrence of additional
indebtedness. These restrictions, however, are subject to a number of qualifications and
exceptions, and under certain circumstances, we could incur substantial additional indebtedness in
compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring
obligations that do not constitute indebtedness under the indentures.
Our ability to meet our debt obligations and other expenses will depend on our future
performance, which will be affected by financial, business, economic, regulatory and other factors,
many of which we are unable to control. If our cash flow is not sufficient to service our debt, we
may be required to refinance debt, sell assets or sell additional shares of common stock on terms
that we may not find attractive if it may be done at all. Further, our failure to comply with the
financial and other restrictive covenants relating to our indebtedness could result in a default
under that indebtedness, which could adversely affect our business, financial condition and results
of operations.
62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number |
|
Maximum |
|
|
|
|
|
|
|
|
|
|
of shares |
|
number of |
|
|
|
|
|
|
|
|
|
|
purchased as |
|
shares that |
|
|
Total number |
|
|
|
|
|
part of publicly |
|
may yet be |
|
|
of shares |
|
Average price |
|
announced |
|
purchased |
Period |
|
withheld (1) |
|
per share |
|
plans |
|
under the plan |
|
July 1, 2010 - July 31, 2010 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
August 1, 2010 - August 31, 2010 |
|
|
1,322 |
|
|
$ |
58.19 |
|
|
|
|
|
|
|
|
|
September 1, 2010 - September 30, 2010 |
|
|
2,055 |
|
|
$ |
63.54 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents shares that were withheld by us to satisfy tax withholding obligations of
certain of our officers, directors and key employees that arose upon the lapse of restrictions on
restricted stock. |
63
Item 6. Exhibits
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
2.1 *
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob
Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray,
LLC (filed as Exhibit 2.1 to the Companys Current Report on Form 8-K on July 20, 2010, and
incorporated herein by reference). |
|
|
|
3.1
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Companys Current Report
on Form 8-K on August 8, 2007, and incorporated herein by reference). |
|
|
|
3.2
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as
Exhibit 3.1 to the Companys Current Report on Form 8-K on March 26, 2008, and incorporated
herein by reference). |
|
|
|
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Companys Current Report on
Form S-1/A on July 5, 2007, and incorporated herein by reference). |
|
|
|
10.1
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and
the purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K
on July 20, 2010, and incorporated herein by reference). |
|
|
|
10.2
|
|
Indemnification Agreement, dated September 24, 2010, between Concho Resources Inc. and Don
McCormack (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on September 29,
2010, and incorporated herein by reference). |
|
|
|
10.3
|
|
Registration Rights Agreement, dated October 7, 2010, by and between Concho Resources Inc.
and the purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form
8-K on October 13, 2010, and incorporated herein by reference). |
|
|
|
10.4
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated October 7, 2010, among
Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as
administrative agent (filed as Exhibit 10.2 to the Companys Current Report on Form 8-K on
October 13, 2010, and incorporated herein by reference). |
|
|
|
10.5
(a)
|
|
Promissory Note in the principal amount of $150,000,000 between Concho Resources Inc. and
Pitch Energy Corporation, dated October 7, 2010. |
|
|
|
31.1 (a)
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2 (a)
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1 (b)
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2 (b)
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS (a)
|
|
XBRL Instance Document. |
|
|
|
101.SCH (a)
|
|
XBRL Schema Document. |
|
|
|
101.CAL (a)
|
|
XBRL Calculation Linkbase Document. |
|
|
|
101.DEF (a)
|
|
XBRL Definition Linkbase Document. |
|
|
|
101.LAB (a)
|
|
XBRL Labels Linkbase Document. |
|
|
|
101.PRE (a)
|
|
XBRL Presentation Linkbase Document. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
* |
|
The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of
Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange
Commission upon request. |
64
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
|
|
|
CONCHO RESOURCES INC. |
|
|
|
|
|
|
|
|
|
Date: November 4, 2010
|
|
By
|
|
/s/ Timothy A. Leach
Timothy A. Leach
|
|
|
|
|
|
|
Director, Chairman of the Board of Directors, Chief Executive |
|
|
|
|
|
|
Officer and President (Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
|
|
By
|
|
/s/ Darin G. Holderness
Darin G. Holderness
|
|
|
|
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer |
|
|
|
|
|
|
(Principal Financial Officer) |
|
|
|
|
|
|
|
|
|
|
|
By
|
|
/s/ Don O. McCormack |
|
|
|
|
|
|
|
|
|
|
|
|
|
Don O. McCormack |
|
|
|
|
|
|
Vice President and Chief Accounting Officer |
|
|
|
|
|
|
(Principal Accounting Officer) |
|
|
65
EXHIBIT INDEX
|
|
|
Exhibit |
|
|
Number |
|
Exhibit |
2.1 *
|
|
Asset Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc., Marbob
Energy Corporation, Pitch Energy Corporation, Costaplenty Energy Corporation and John R. Gray,
LLC (filed as Exhibit 2.1 to the Companys Current Report on Form 8-K on July 20, 2010, and
incorporated herein by reference). |
|
|
|
3.1
|
|
Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Companys Current Report
on Form 8-K on August 8, 2007, and incorporated herein by reference). |
|
|
|
3.2
|
|
Amended and Restated Bylaws of Concho Resources Inc., as amended March 25, 2008 (filed as
Exhibit 3.1 to the Companys Current Report on Form 8-K on March 26, 2008, and incorporated
herein by reference). |
|
|
|
4.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Companys Current Report on
Form S-1/A on July 5, 2007, and incorporated herein by reference). |
|
|
|
10.1
|
|
Common Stock Purchase Agreement, dated July 19, 2010, by and among Concho Resources Inc. and
the purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K
on July 20, 2010, and incorporated herein by reference). |
|
|
|
10.2
|
|
Indemnification Agreement, dated September 24, 2010, between Concho Resources Inc. and Don
McCormack (filed as Exhibit 10.1 to the Companys Current Report on Form 8-K on September 29,
2010, and incorporated herein by reference). |
|
|
|
10.3
|
|
Registration Rights Agreement, dated October 7, 2010, by and between Concho Resources Inc.
and the purchasers named therein (filed as Exhibit 10.1 to the Companys Current Report on Form
8-K on October 13, 2010, and incorporated herein by reference). |
|
|
|
10.4
|
|
Fourth Amendment to Amended and Restated Credit Agreement, dated October 7, 2010, among
Concho Resources Inc. and the lenders party thereto and JPMorgan Chase Bank, N.A., as
administrative agent (filed as Exhibit 10.2 to the Companys Current Report on Form 8-K on
October 13, 2010, and incorporated herein by reference). |
|
|
|
10.5
(a)
|
|
Promissory Note in the principal amount of $150,000,000 between Concho Resources Inc. and
Pitch Energy Corporation, dated October 7, 2010. |
|
|
|
31.1 (a)
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2 (a)
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1 (b)
|
|
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2 (b)
|
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS (a)
|
|
XBRL Instance Document. |
|
|
|
101.SCH (a)
|
|
XBRL Schema Document. |
|
|
|
101.CAL (a)
|
|
XBRL Calculation Linkbase Document. |
|
|
|
101.DEF (a)
|
|
XBRL Definition Linkbase Document. |
|
|
|
101.LAB (a)
|
|
XBRL Labels Linkbase Document. |
|
|
|
101.PRE (a)
|
|
XBRL Presentation Linkbase Document. |
|
|
|
(a) |
|
Filed herewith. |
|
(b) |
|
Furnished herewith. |
|
* |
|
The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of
Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange
Commission upon request. |