Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30,
2010
Commission File Number 001-31539
SM ENERGY COMPANY
(Exact name of registrant as
specified in its charter)
Delaware
(State or other
jurisdiction
of incorporation or
organization)
|
|
41-0518430
(I.R.S. Employer
Identification No.)
|
1775 Sherman
Street, Suite 1200, Denver, Colorado
(Address of principal
executive offices)
|
|
80203
(Zip Code)
|
(303) 861-8140
(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
x
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
x
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.
Large accelerated filer
x
|
|
Accelerated filer
o
|
|
|
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
|
Smaller reporting company
o
|
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).
Yes
o
No
x
Indicate the number of shares
outstanding of each of the issuers classes of common stock, as of the latest
practicable date.
As of October 27, 2010 the
registrant had 63,055,280 shares of common stock, $0.01 par value, outstanding.
Table of Contents
SM ENERGY COMPANY
INDEX
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PAGE
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Part I.
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FINANCIAL INFORMATION
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Item 1.
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Financial Statements (Unaudited)
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Condensed
Consolidated Balance Sheets
September 30, 2010, and December 31, 2009
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3
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Condensed
Consolidated Statements of Operations
Three
and Nine Months Ended September 30, 2010, and 2009
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4
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Condensed Consolidated Statements of Stockholders
Equity and Comprehensive
Income (Loss)
September 30, 2010, and
2009
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5
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Condensed
Consolidated Statements of Cash Flows
Nine
Months Ended September 30, 2010, and 2009
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6
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Notes to
Condensed Consolidated Financial Statements September 30, 2010
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8
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Item 2.
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Managements
Discussion and Analysis of Financial Condition and Results of Operations
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25
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Item 3.
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Quantitative
and Qualitative Disclosures About Market Risk (included within the content of Item 2)
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58
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Item 4.
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Controls and
Procedures
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58
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Part II.
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OTHER INFORMATION
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Item 1A.
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Risk Factors
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58
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Item 2.
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Unregistered Sales of Equity
Securities and Use of Proceeds
|
59
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Item 6.
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Exhibits
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60
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Table
of Contents
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SM ENERGY
COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In
thousands, except share amounts)
|
|
September 30,
|
|
December 31,
|
|
|
|
2010
|
|
2009
|
|
ASSETS
|
|
|
|
|
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|
|
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|
Current assets:
|
|
|
|
|
|
|
|
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|
Cash and cash equivalents
|
|
|
$
|
7,089
|
|
|
|
$
|
10,649
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|
|
Accounts receivable
|
|
|
121,010
|
|
|
|
116,136
|
|
|
Refundable income taxes
|
|
|
1,371
|
|
|
|
32,773
|
|
|
Prepaid expenses and other
|
|
|
12,847
|
|
|
|
14,259
|
|
|
Derivative asset
|
|
|
56,199
|
|
|
|
30,295
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
4,934
|
|
|
Total current assets
|
|
|
198,516
|
|
|
|
209,046
|
|
|
|
|
|
|
|
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Property and equipment (successful
efforts method), at cost:
|
|
|
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Land
|
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1,483
|
|
|
|
1,371
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|
Proved oil and gas properties
|
|
|
3,137,262
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|
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2,797,341
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|
Less - accumulated depletion,
depreciation, and amortization
|
|
|
(1,234,802
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)
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|
|
(1,053,518
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)
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Unproved oil and gas properties,
net of impairment allowance of $62,395 in 2010 and $66,570 in 2009
|
|
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79,466
|
|
|
|
132,370
|
|
|
Wells in progress
|
|
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129,102
|
|
|
|
65,771
|
|
|
Materials inventory, at lower of
cost or market
|
|
|
27,810
|
|
|
|
24,467
|
|
|
Oil and gas properties held for
sale less accumulated depletion, depreciation, and amortization
|
|
|
114,863
|
|
|
|
145,392
|
|
|
Other property and equipment, net
of accumulated depreciation of $17,301 in 2010 and $14,550 in 2009
|
|
|
19,048
|
|
|
|
14,404
|
|
|
|
|
|
2,274,232
|
|
|
|
2,127,598
|
|
|
|
|
|
|
|
|
|
|
|
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Other noncurrent assets:
|
|
|
|
|
|
|
|
|
|
Derivative asset
|
|
|
29,444
|
|
|
|
8,251
|
|
|
Other noncurrent assets
|
|
|
16,805
|
|
|
|
16,041
|
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|
Total other noncurrent assets
|
|
|
46,249
|
|
|
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24,292
|
|
|
|
|
|
|
|
|
|
|
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Total Assets
|
|
|
$
|
2,518,997
|
|
|
|
$
|
2,360,936
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
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|
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Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
|
$
|
316,179
|
|
|
|
$
|
236,242
|
|
|
Derivative liability
|
|
|
53,732
|
|
|
|
53,929
|
|
|
Deposit associated with oil and
gas properties held for sale
|
|
|
|
|
|
|
6,500
|
|
|
Deferred income taxes
|
|
|
1,143
|
|
|
|
|
|
|
Total current liabilities
|
|
|
371,054
|
|
|
|
296,671
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent liabilities:
|
|
|
|
|
|
|
|
|
|
Long-term credit facility
|
|
|
2,000
|
|
|
|
188,000
|
|
|
Senior convertible notes, net of
unamortized discount of $14,096 in 2010, and $20,598 in 2009
|
|
|
273,404
|
|
|
|
266,902
|
|
|
Asset retirement obligation
|
|
|
64,286
|
|
|
|
60,289
|
|
|
Asset retirement obligation
associated with oil and gas properties held for sale
|
|
|
3,076
|
|
|
|
18,126
|
|
|
Net Profits Plan liability
|
|
|
140,506
|
|
|
|
170,291
|
|
|
Deferred income taxes
|
|
|
422,021
|
|
|
|
308,189
|
|
|
Derivative liability
|
|
|
25,450
|
|
|
|
65,499
|
|
|
Other noncurrent liabilities
|
|
|
14,749
|
|
|
|
13,399
|
|
|
Total noncurrent liabilities
|
|
|
945,492
|
|
|
|
1,090,695
|
|
|
|
|
|
|
|
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|
|
|
Commitments and contingencies
(note 6)
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|
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Stockholders equity:
|
|
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|
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|
Common stock, $0.01 par value -
authorized: 200,000,000 shares; issued: 63,147,613 shares in 2010 and
62,899,122 shares in 2009; outstanding, net of treasury shares: 63,044,978
shares in 2010 and 62,772,229 shares in 2009
|
|
|
631
|
|
|
|
629
|
|
|
Additional paid-in capital
|
|
|
183,203
|
|
|
|
160,516
|
|
|
Treasury stock, at cost: 102,635
shares in 2010 and 126,893 shares in 2009
|
|
|
(456
|
)
|
|
|
(1,204
|
)
|
|
Retained earnings
|
|
|
1,004,984
|
|
|
|
851,583
|
|
|
Accumulated other comprehensive
income (loss)
|
|
|
14,089
|
|
|
|
(37,954
|
)
|
|
Total stockholders equity
|
|
|
1,202,451
|
|
|
|
973,570
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
and Stockholders Equity
|
|
|
$
|
2,518,997
|
|
|
|
$
|
2,360,936
|
|
|
The accompanying notes are an integral part of these consolidated
financial statements.
3
Table of
Contents
SM ENERGY
COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(In
thousands, except per share amounts)
|
|
For the Three Months
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
gas production revenue
|
|
|
$
|
197,354
|
|
|
|
$
|
152,651
|
|
|
|
$
|
586,128
|
|
|
|
$
|
428,347
|
|
|
Realized
oil and gas hedge gain
|
|
|
8,847
|
|
|
|
28,331
|
|
|
|
20,771
|
|
|
|
127,230
|
|
|
Gain
(loss) on divestiture activity
|
|
|
4,184
|
|
|
|
(11,277
|
)
|
|
|
132,183
|
|
|
|
(10,632
|
)
|
|
Marketed
gas system and other operating revenue
|
|
|
16,499
|
|
|
|
16,082
|
|
|
|
59,634
|
|
|
|
45,260
|
|
|
Total
operating revenues and other income
|
|
|
226,884
|
|
|
|
185,787
|
|
|
|
798,716
|
|
|
|
590,205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and
gas production expense
|
|
|
44,606
|
|
|
|
48,634
|
|
|
|
138,114
|
|
|
|
153,928
|
|
|
Depletion,
depreciation, amortization, and asset retirement obligation liability
accretion
|
|
|
83,800
|
|
|
|
66,958
|
|
|
|
241,335
|
|
|
|
229,061
|
|
|
Exploration
|
|
|
14,437
|
|
|
|
15,733
|
|
|
|
42,833
|
|
|
|
48,821
|
|
|
Impairment
of proved properties
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
153,183
|
|
|
Abandonment
and impairment of unproved properties
|
|
|
1,719
|
|
|
|
4,761
|
|
|
|
4,998
|
|
|
|
20,294
|
|
|
Impairment
of materials inventory
|
|
|
|
|
|
|
2,114
|
|
|
|
|
|
|
|
13,449
|
|
|
General
and administrative
|
|
|
26,219
|
|
|
|
20,790
|
|
|
|
75,103
|
|
|
|
55,349
|
|
|
Change
in Net Profits Plan liability
|
|
|
4,086
|
|
|
|
6,804
|
|
|
|
(29,785
|
)
|
|
|
(14,038
|
)
|
|
Marketed
gas system expense
|
|
|
14,697
|
|
|
|
14,360
|
|
|
|
52,550
|
|
|
|
41,352
|
|
|
Unrealized
derivative (gain) loss
|
|
|
5,727
|
|
|
|
4,117
|
|
|
|
(4,095
|
)
|
|
|
17,251
|
|
|
Other
expense
|
|
|
541
|
|
|
|
968
|
|
|
|
2,071
|
|
|
|
12,424
|
|
|
Total
operating expenses
|
|
|
195,832
|
|
|
|
185,330
|
|
|
|
523,124
|
|
|
|
731,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from operations
|
|
|
31,052
|
|
|
|
457
|
|
|
|
275,592
|
|
|
|
(140,869
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonoperating
income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
85
|
|
|
|
90
|
|
|
|
268
|
|
|
|
217
|
|
|
Interest
expense
|
|
|
(6,339
|
)
|
|
|
(7,565
|
)
|
|
|
(19,469
|
)
|
|
|
(21,324
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
|
24,798
|
|
|
|
(7,018
|
)
|
|
|
256,391
|
|
|
|
(161,976
|
)
|
|
Income
tax benefit (expense)
|
|
|
(9,346
|
)
|
|
|
2,603
|
|
|
|
(96,693
|
)
|
|
|
61,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
15,452
|
|
|
|
$
|
(4,415
|
)
|
|
|
$
|
159,698
|
|
|
|
$
|
(100,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
weighted-average common shares outstanding
|
|
|
63,031
|
|
|
|
62,505
|
|
|
|
62,914
|
|
|
|
62,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding
|
|
|
64,794
|
|
|
|
62,505
|
|
|
|
64,599
|
|
|
|
62,420
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per common share
|
|
|
$
|
0.25
|
|
|
|
$
|
(0.07
|
)
|
|
|
$
|
2.54
|
|
|
|
$
|
(1.61
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income (loss) per common share
|
|
|
$
|
0.24
|
|
|
|
$
|
(0.07
|
)
|
|
|
$
|
2.47
|
|
|
|
$
|
(1.61
|
)
|
|
The accompanying notes are an integral part of these consolidated
financial statements.
4
Table of
Contents
SM ENERGY
COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY AND COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
(In
thousands, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
Other
|
|
Total
|
|
|
|
Common Stock
|
|
Paid-in
|
|
Treasury Stock
|
|
Retained
|
|
Comprehensive
|
|
Stockholders
|
|
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Shares
|
|
Amount
|
|
Earnings
|
|
Income (Loss)
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
December 31, 2009
|
|
|
62,899,122
|
|
|
|
$
|
629
|
|
|
|
$
|
160,516
|
|
|
|
(126,893
|
)
|
|
|
$
|
(1,204
|
)
|
|
|
$
|
851,583
|
|
|
|
$
|
(37,954
|
)
|
|
|
$
|
973,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
159,698
|
|
|
|
|
|
|
|
159,698
|
|
|
Change in derivative instrument
fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,136
|
|
|
|
50,136
|
|
|
Reclassification to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,903
|
|
|
|
1,903
|
|
|
Minimum pension liability
adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
4
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,741
|
|
|
Cash dividends, $ 0.10 per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,297
|
)
|
|
|
|
|
|
|
(6,297
|
)
|
|
Issuance of common stock under
Employee Stock Purchase Plan
|
|
|
27,456
|
|
|
|
|
|
|
|
799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
799
|
|
|
Issuance of common stock upon
settlement of RSUs following expiration of restriction period, net of shares
used for tax withholdings, including income tax cost of RSUs
|
|
|
57,687
|
|
|
|
1
|
|
|
|
(909
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(908
|
)
|
|
Sale of common stock, including
income tax benefit of stock option exercises
|
|
|
163,348
|
|
|
|
1
|
|
|
|
3,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,693
|
|
|
Stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
19,105
|
|
|
|
24,258
|
|
|
|
748
|
|
|
|
|
|
|
|
|
|
|
|
19,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
September 30, 2010
|
|
|
63,147,613
|
|
|
|
$
|
631
|
|
|
|
$
|
183,203
|
|
|
|
(102,635
|
)
|
|
|
$
|
(456
|
)
|
|
|
$
|
1,004,984
|
|
|
|
$
|
14,089
|
|
|
|
$
|
1,202,451
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31,
2008
|
|
|
62,465,572
|
|
|
|
$
|
625
|
|
|
|
$
|
141,283
|
|
|
|
(176,987
|
)
|
|
|
$
|
(1,892
|
)
|
|
|
$
|
957,200
|
|
|
|
$
|
65,293
|
|
|
|
$
|
1,162,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100,360
|
)
|
|
|
|
|
|
|
(100,360
|
)
|
|
Change in derivative instrument
fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,810
|
)
|
|
|
(12,810
|
)
|
|
Reclassification to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(57,979
|
)
|
|
|
(57,979
|
)
|
|
Minimum pension liability
adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
4
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(171,145
|
)
|
|
Cash dividends, $ 0.10 per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,247
|
)
|
|
|
|
|
|
|
(6,247
|
)
|
|
Issuance of common stock under
Employee Stock Purchase Plan
|
|
|
49,767
|
|
|
|
|
|
|
|
858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
858
|
|
|
Issuance of common stock upon
settlement of RSUs following expiration of restriction period, net of shares
used for tax withholdings, including income tax cost of RSUs
|
|
|
89,236
|
|
|
|
1
|
|
|
|
(3,157
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,156
|
)
|
|
Sale of common stock, including
income tax benefit of stock option exercises
|
|
|
33,014
|
|
|
|
|
|
|
|
320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
320
|
|
|
Stock-based compensation expense
|
|
|
1,250
|
|
|
|
|
|
|
|
12,316
|
|
|
|
50,094
|
|
|
|
662
|
|
|
|
|
|
|
|
|
|
|
|
12,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances,
September 30, 2009
|
|
|
62,638,839
|
|
|
|
$
|
626
|
|
|
|
$
|
151,620
|
|
|
|
(126,893
|
)
|
|
|
$
|
(1,230
|
)
|
|
|
$
|
850,593
|
|
|
|
$
|
(5,492
|
)
|
|
|
$
|
996,117
|
|
|
The accompanying notes are
an integral part of these consolidated financial statements.
5
Table
of Contents
SM ENERGY
COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(In
thousands)
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
|
$
|
159,698
|
|
|
|
$
|
(100,360
|
)
|
|
Adjustments
to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
(Gain)
loss on divestiture activity
|
|
|
(132,183
|
)
|
|
|
10,632
|
|
|
Depletion,
depreciation, amortization, and asset retirement obligation liability
accretion
|
|
|
241,335
|
|
|
|
229,061
|
|
|
Exploratory
dry hole expense
|
|
|
289
|
|
|
|
4,849
|
|
|
Impairment
of proved properties
|
|
|
|
|
|
|
153,183
|
|
|
Abandonment
and impairment of unproved properties
|
|
|
4,998
|
|
|
|
20,294
|
|
|
Impairment
of materials inventory
|
|
|
|
|
|
|
13,449
|
|
|
Stock-based
compensation expense
|
|
|
19,853
|
|
|
|
12,978
|
|
|
Change
in Net Profits Plan liability
|
|
|
(29,785
|
)
|
|
|
(14,038
|
)
|
|
Unrealized
derivative (gain) loss
|
|
|
(4,095
|
)
|
|
|
17,251
|
|
|
Loss
related to hurricanes
|
|
|
|
|
|
|
8,273
|
|
|
Amortization
of debt discount and deferred financing costs
|
|
|
10,022
|
|
|
|
8,922
|
|
|
Deferred
income taxes
|
|
|
85,695
|
|
|
|
(69,082
|
)
|
|
Plugging
and abandonment
|
|
|
(7,106
|
)
|
|
|
(12,110
|
)
|
|
Other
|
|
|
(3,085
|
)
|
|
|
1,432
|
|
|
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(4,937
|
)
|
|
|
58,844
|
|
|
Refundable
income taxes
|
|
|
31,402
|
|
|
|
10,340
|
|
|
Prepaid
expenses and other
|
|
|
512
|
|
|
|
(8,660
|
)
|
|
Accounts
payable and accrued expenses
|
|
|
47,123
|
|
|
|
7,794
|
|
|
Excess
income tax benefit from the exercise of stock options
|
|
|
(1,376
|
)
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
418,360
|
|
|
|
353,052
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
Net
proceeds from sale of oil and gas properties
|
|
|
259,501
|
|
|
|
1,137
|
|
|
Proceeds
from insurance settlement
|
|
|
|
|
|
|
15,336
|
|
|
Capital
expenditures
|
|
|
(488,684
|
)
|
|
|
(292,466
|
)
|
|
Acquisition
of oil and gas properties
|
|
|
(685
|
)
|
|
|
(58
|
)
|
|
Receipts
from restricted cash
|
|
|
|
|
|
|
14,398
|
|
|
Receipts
from short-term investments
|
|
|
|
|
|
|
1,002
|
|
|
Other
|
|
|
(6,492
|
)
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(236,360
|
)
|
|
|
(260,651
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
Proceeds
from credit facility
|
|
|
315,059
|
|
|
|
1,898,500
|
|
|
Repayment
of credit facility
|
|
|
(501,059
|
)
|
|
|
(1,963,500
|
)
|
|
Debt
issuance costs related to credit facility
|
|
|
|
|
|
|
(11,074
|
)
|
|
Proceeds
from sale of common stock
|
|
|
3,116
|
|
|
|
1,179
|
|
|
Dividends
paid
|
|
|
(3,144
|
)
|
|
|
(3,120
|
)
|
|
Excess
income tax benefit from the exercise of stock options
|
|
|
1,376
|
|
|
|
|
|
|
Other
|
|
|
(908
|
)
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(185,560
|
)
|
|
|
(78,015
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in cash and cash equivalents
|
|
|
(3,560
|
)
|
|
|
14,386
|
|
|
Cash and
cash equivalents at beginning of period
|
|
|
10,649
|
|
|
|
6,131
|
|
|
Cash and cash equivalents at end of period
|
|
|
$
|
7,089
|
|
|
|
$
|
20,517
|
|
|
The accompanying notes are an integral part of these consolidated
financial statements.
6
Table of
Contents
SM ENERGY
COMPANY AND SUBSIDIARIES
CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Continued)
Supplemental schedule of additional
cash flow information and noncash investing and financing activities:
|
|
For the Nine Months
|
|
|
|
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Cash
paid for interest
|
|
|
$
|
9,091
|
|
|
|
$
|
11,150
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
refunded for income taxes
|
|
|
$
|
(24,949
|
)
|
|
|
$
|
(10,119
|
)
|
|
As of September 30,
2010, and 2009, $133.3 million, and $59.8 million, respectively, are included
as
additions to oil and gas
properties and accounts payable and accrued expenses in the accompanying
condensed consolidated balance sheets. These oil and gas
additions are reflected as cash used in
investing
activities in the periods that the payables are settled.
Dividends of approximately $3.2
million have been declared by the Companys Board of Directors, but not paid,
as of
September 30, 2010.
The accompanying notes are an integral part of these consolidated
financial statements.
7
Table
of Contents
SM ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
September 30, 2010
Note 1 The Company and Business
SM Energy Company (SM Energy or
the Company), formerly named St. Mary Land & Exploration Company or
referred to as St. Mary, is an independent energy company engaged in the
exploration, exploitation, development, acquisition, and production of natural
gas, natural gas liquids (NGLs), and crude oil. The Companys operations are conducted
entirely in the continental United States.
Note 2 Basis of Presentation
and Significant Accounting Policies
Basis of Presentation
The accompanying unaudited condensed
consolidated financial statements of SM Energy have been prepared in accordance
with accounting principles generally accepted in the United States for interim
financial information and the instructions to Form 10-Q and Regulation
S-X. They do not include all information
and notes required by generally accepted accounting principles (GAAP) for
complete financial statements. However,
except as disclosed herein, there has been no material change in the
information disclosed in the notes to consolidated financial statements
included in SM Energys Annual Report on Form 10-K for the year ended
December 31, 2009, (the 2009 Form 10-K). In the opinion of management, all
adjustments, consisting of normal recurring accruals that are considered
necessary for a fair presentation of the interim financial information, have
been included. Operating results for the
periods presented are not necessarily indicative of expected results for the
full year. In connection with the
preparation of the condensed consolidated financial statements of SM Energy,
the Company evaluated subsequent events after the balance sheet
date of September 30, 2010, through the filing date of this report.
Other
Significant Accounting Policies
The accounting policies followed by
the Company are set forth in Note 1 to the Companys consolidated financial
statements in the 2009 Form 10-K, and are supplemented throughout the
notes to condensed consolidated financial statements in this report. It is suggested that these condensed
consolidated financial statements be read in conjunction with the consolidated
financial statements and notes included in the 2009 Form 10-K.
Note 3 Divestitures and Assets Held for Sale
Southern Rockies
Divestiture
In July 2010 the Company
completed the divestiture related to the non-strategic assets that were
classified as held for sale at June 30, 2010. The gain on sale related to the divestiture
is approximately $2.6 million. The
final sale price is subject to normal post-closing adjustments and is expected
to be finalized in the fourth quarter of 2010.
The estimated gain on sale related to the divestiture may be impacted by
the forthcoming post-closing adjustments mentioned above. The Company determined that the sale did not
qualify for discontinued operations accounting under financial statement
presentation authoritative guidance.
Legacy Divestiture
In
February 2010 the Company completed the divestiture of certain
non-strategic oil properties located in Wyoming to Legacy Reserves Operating
LP, a wholly-owned subsidiary of Legacy Reserves LP
8
Table of Contents
(Legacy). The transaction had an effective date of
November 1, 2009. Total cash
received, before commission costs and Net Profits Interest Bonus Plan (Net
Profits Plan) payments, was $125.3 million, of which $6.5 million was
received as a deposit in December 2009.
The final gain on sale related to the divestiture is approximately
$65.0 million. The Company
determined that the sale did not qualify for discontinued operations accounting
under financial statement presentation authoritative guidance. A portion of the transaction was structured
to qualify as a like-kind exchange under Section 1031 of the Internal
Revenue Code of 1986, as amended (the Internal Revenue Code).
Sequel Divestiture
In
March 2010 the Company completed the divestiture of certain non-strategic
oil properties located in North Dakota to Sequel Energy Partners, LP, Bakken
Energy Partners, LLC, and Three Forks Energy Partners, LLC (collectively
referred to as Sequel). The
transaction had an effective date of November 1, 2009. Total cash received, before commission costs
and Net Profits Plan payments, was $129.1 million. The final sale price is subject to normal
post-closing adjustments and is expected to be finalized during the fourth
quarter of 2010. The estimated gain on
sale related to the divestiture is approximately $52.9 million and may be impacted
by the forthcoming post-closing adjustments mentioned above. The Company determined that the sale did not
qualify for discontinued operations accounting under financial statement
presentation authoritative guidance. A
portion of the transaction was structured to qualify as a like-kind exchange
under Section 1031 of the Internal Revenue Code.
Assets Held for Sale
In
accordance with property, plant, and equipment authoritative guidance, assets
are classified as held for sale when the Company commits to a plan to sell the
assets and there is reasonable certainty that the sale will take place within
one year. Upon classification as
held-for-sale, long-lived assets are no longer depreciated or depleted, and a measurement
for impairment is performed to determine if there is any excess of carrying
value over fair value less costs to sell.
Subsequent changes to estimated fair value less the cost to sell will
impact the measurement of assets held for sale if the fair value is determined
to be less than the carrying value of the assets.
In August 2010 the Company
engaged two outside firms to market for sale certain non-core oil and gas
properties located in the Rocky Mountain, Mid-Continent, and Permian
regions. The Mid-Continent properties
being marketed include all of our Marcellus shale assets in North Central
Pennsylvania. As of
September 30, 2010, the accompanying condensed consolidated balance
sheets (accompanying balance sheets) present $114.9 million in book value of
assets held for sale, net of accumulated depletion, depreciation, and
amortization. Additionally, the
corresponding asset retirement obligation liability of $3.1 million is
separately presented. The Company
determined that these planned asset sales do not qualify for discontinued
operations accounting under financial statement presentation authoritative
guidance.
Note 4 Income Taxes
Income tax (expense) benefit for the
nine-month periods ended September 30, 2010, and 2009, differs from the
amounts that would be provided by applying the statutory U.S. federal income
tax rate to income (loss) before income taxes as a result of the estimated
effect of the domestic production activities deduction, percentage depletion,
the effect of state income taxes, and other permanent differences.
9
Table
of Contents
The provision for income taxes
consists of the following:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September
30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
Current
portion of income tax (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
$
|
(2,194)
|
|
|
|
$
|
(2,881
|
)
|
|
|
$
|
(10,410)
|
|
|
|
$
|
(6,129)
|
|
|
State
|
|
|
(277)
|
|
|
|
(451
|
)
|
|
|
(588)
|
|
|
|
(1,337)
|
|
|
Deferred
portion of income tax (expense) benefit
|
|
|
(6,875)
|
|
|
|
5,935
|
|
|
|
(85,695)
|
|
|
|
69,082
|
|
|
Total
income tax (expense) benefit
|
|
|
$
|
(9,346)
|
|
|
|
$
|
2,603
|
|
|
|
$
|
(96,693)
|
|
|
|
$
|
61,616
|
|
|
Effective
tax rate
|
|
|
37.7%
|
|
|
|
37.1%
|
|
|
|
37.7%
|
|
|
|
38.0%
|
|
|
A change in the Companys effective
tax rate between reported periods will generally reflect differences in its
estimated highest marginal state tax rate due to changes in the composition of
income between state tax jurisdictions resulting from Company activities. Non-core asset sales through
September 30, 2010, and the Companys anticipated drilling budget for
the rest of 2010 applied against the Companys cumulative temporary timing
differences caused an increase in tax rate for the third quarter of 2010 when
compared to the same period of 2009. The
rate is also impacted period to period by estimates for the domestic production
activities deduction, percentage depletion, and for potential permanent state
tax items which affect the presented periods differently due to oil and gas
price variability and the impact of non-core asset sales.
The
Company and its subsidiaries file income tax returns in the U.S. federal
jurisdiction and in various states. With
few exceptions, the Company is no longer subject to U.S. federal or state
income tax examinations by these tax authorities for years before 2007. During the first quarter of 2010, the
Internal Revenue Service initiated an audit of SM Energy for the 2006 tax year
as a result of a net operating loss carryback from the Companys 2008 tax
year. The audit was focused primarily on
compensation related issues. The audit
was successfully concluded in the second quarter of 2010 with no changes to
Company reported amounts. As of September 30,
2010, the Company is awaiting approval from the Joint Committee on Taxation to
receive a $5.5 million refund from its 2006 tax year net operating loss
carryback claim, which is included in refundable income taxes on the
accompanying balance sheets. On July 20, 2010,
the Company received $22.9 million related to an initial claim for net
operating loss carry back from its 2009 tax year to its 2005 tax year. The Companys remaining refundable income tax
balance at September 30, 2010, reflects additional net operating loss carry back from
filing a revised income tax return for the 2009 tax year prior to the extended
return due date. At the end of the third
quarter of 2010, the Company was advised that the Internal Revenue Service will
begin a full audit of the Companys 2009 tax year in the fourth quarter of
2010.
The Companys 2005 federal income tax audit was
concluded in the first quarter of 2009 with a refund to the Company of $278,000
plus interest of $41,000. There was no change to the provision for income tax
expense as a result of the 2005 examination.
Note 5 Earnings per Share
Basic net income or loss per common
share of stock is calculated by dividing net income or loss available to common
stockholders by the basic weighted-average common shares outstanding for the
respective period. The shares
represented by vested restricted stock units (RSUs) are included in the
calculation of the basic weighted-average common shares outstanding. The earnings per share calculations reflect
the impact of any repurchases of shares of common stock made by the Company.
Diluted net income or loss per
common share of stock is calculated by dividing adjusted net income or loss by
the diluted weighted-average common shares outstanding, which includes the
effect of potentially dilutive securities.
Potentially dilutive securities for this calculation consist of unvested
RSUs, in-the-money outstanding options to purchase the Companys common stock,
contingent Performance Share
10
Table of Contents
Awards (PSAs), and shares into
which the 3.50% Senior Convertible Notes due 2027 (the 3.50% Senior
Convertible Notes) are convertible.
The Companys 3.50% Senior
Convertible Notes have a net-share settlement right whereby each $1,000
principal amount of notes may be surrendered for conversion to cash in an
amount equal to the principal amount and, if applicable, shares of common stock
or cash or any combination of common stock and cash for the amount of
conversion value in excess of the principal amount. The treasury stock method is used to measure
the potentially dilutive impact of shares associated with this conversion
feature. The 3.50% Senior Convertible
Notes have not been dilutive for any reporting period that they have been
outstanding and therefore do not impact the diluted earnings per share
calculation for the three-month or nine-month periods ended September 30,
2010, and 2009.
The PSAs represent the right to
receive, upon settlement of the PSAs after the completion of the three-year
performance period, a number of shares of the Companys common stock that may
be from zero to two times the number of PSAs granted on the award date. The number of potentially dilutive shares related
to PSAs is based on the number of shares, if any, which would be issuable at
the end of the respective reporting period, assuming that date was the end of
the contingency period. For additional
discussion on PSAs, please refer to Note 7 Compensation Plans under the
heading
Performance Share Awards Under the Equity Incentive
Compensation Plan
.
The treasury stock method is used to
measure the dilutive impact of stock options, RSUs, 3.50% Senior Convertible
Notes, and PSAs. When there is a loss
from continuing operations, all potentially dilutive shares will be
anti-dilutive. There were no dilutive
shares for the three-month or nine-month periods ended September 30, 2009,
because the Company recorded a loss for each of those periods. Unvested RSUs, contingent PSAs, and
in-the-money options had a dilutive impact for the three-month and nine-month
periods ended September 30, 2010, as calculated in the table below.
The following table sets forth the
calculation of basic and diluted earnings per share:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$
|
15,452
|
|
|
$
|
(4,415
|
)
|
|
$
|
159,698
|
|
|
$
|
(100,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
weighted-average common stock outstanding
|
|
63,031
|
|
|
62,505
|
|
|
62,914
|
|
|
62,420
|
|
|
Add:
dilutive effect of stock options, unvested RSUs, and contingent PSAs
|
|
1,763
|
|
|
|
|
|
1,685
|
|
|
|
|
|
Add:
dilutive effect of 3.50% senior convertible notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
weighted-average common shares outstanding
|
|
64,794
|
|
|
62,505
|
|
|
64,599
|
|
|
62,420
|
|
|
Basic
net income (loss) per common share
|
|
$
|
0.25
|
|
|
$
|
(0.07
|
)
|
|
$
|
2.54
|
|
|
$
|
(1.61
|
)
|
|
Diluted
net income (loss) per common share
|
|
$
|
0.24
|
|
|
$
|
(0.07
|
)
|
|
$
|
2.47
|
|
|
$
|
(1.61
|
)
|
|
11
Table
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Note 6
Commitments and Contingencies
During the first nine months of
2010, the Company entered into two natural gas gathering through-put
commitments that as of September 30, 2010, require a minimum volume
delivery of 574 Bcf by the end of 2021.
The Company will be required to make periodic deficiency payments for
any shortfalls in delivering the minimum volume commitments. If a shortfall in the minimum volume
commitment is projected, the Company has certain rights to arrange for 3
rd
party gas to deliver
into the gathering lines and such volume will be counted towards the minimum
commitment. In the third quarter of 2010
the Company entered into several new long-term drilling rig contracts that
extend through 2014. The table below
shows the undiscounted cash flows associated with the deficiency payments
related to the Companys through-put commitments, as well as commitments
associated with the Companys new drilling rig contracts as of September 30,
2010.
|
|
Undiscounted
|
|
|
|
Cash Outflows
|
|
Years Ending December 31,
|
|
(In thousands)
|
|
2010
|
|
$
|
7,775
|
|
2011
|
|
28,300
|
|
2012
|
|
36,068
|
|
2013
|
|
46,988
|
|
2014
|
|
33,147
|
|
Thereafter
|
|
119,873
|
|
Total
|
|
$
|
272,151
|
|
The
above amounts include commitments under a gas services agreement entered into
by the Company effective as of July 1, 2010, for natural gas production
from the Companys Eagle Ford shale assets.
Under that agreement, the Company has committed Eagle Ford production up
to a maximum level of 200,000 MMBTU per day over a ten-year term beginning in
2011, and in the event that no gas is delivered the aggregate deficiency
payments will total $154.7 million.
Subsequent to September 30,
2010, the Company entered into a fracturing service agreement and an additional
long-term drilling rig contract, which extends through 2013. The total
commitment for both agreements is $79.8 million.
Note 7 Compensation Plans
Cash Bonus Plan
During the first quarters of
2010 and 2009, the Company paid $7.7 million and $6.0 million for cash bonuses
earned in the 2009 and 2008 performance years, respectively. Within the general and administrative expense
and exploration expense line items in the accompanying condensed consolidated
statements of operations (accompanying statements of operations) was $3.1
million and $3.2 million of cash bonus expense related to the specific
performance year for the three-month periods ended September 30, 2010,
and 2009, and $9.2 million and $8.5 million for the nine-month periods ended September 30,
2010, and 2009, respectively.
Performance Share Awards Under the Equity
Incentive Compensation Plan
PSAs represent the right to receive,
upon the completion of a three-year performance period, a number of shares of
the Companys common stock that may be from zero to two times the number of
PSAs granted on the award date, depending on the extent to which the Companys
performance criteria have been achieved and the extent to which the PSAs have
vested. The performance criteria for the
PSAs are based on a combination of the Companys total shareholder return (TSR)
for the performance period and the relative performance of the Companys TSR
compared to an index of certain peer companies TSR for the performance period.
Total stock-based compensation
expense related to PSAs for the three-month periods ended September 30,
2010, and 2009, was $5.6 million and $3.2 million, respectively, and $13.0
million and $5.7
12
Table of Contents
million for the nine-month periods
ended September 30, 2010, and 2009, respectively. As of September 30, 2010, there was
$29.0 million of total unrecognized compensation expense related to unvested
PSAs that is being amortized through 2013.
A summary of the status and activity
of PSAs for the nine-month period ended September 30, 2010, is
presented in the following table:
|
|
PSAs
|
|
Weighted-
Average Grant-
Date Fair Value
|
|
Non-vested,
at January 1, 2010
|
|
1,069,090
|
|
|
$
|
32.52
|
|
Granted
|
|
387,651
|
|
|
$
|
52.35
|
|
Vested
(1)
|
|
(210,801
|
)
|
|
$
|
31.17
|
|
Forfeited
|
|
(102,149
|
)
|
|
$
|
32.48
|
|
Non-vested
and outstanding, at September 30, 2010
|
|
1,143,791
|
|
|
$
|
39.49
|
|
(1)
The numbers of shares vested assume a one
multiplier. The final number of shares vested may vary depending on the ending
three-year multiplier, which ranges from zero to two.
On July 1, 2010, the Company
granted 387,651 PSAs with a performance period ending June 30, 2013,
and a fair value of $20.3 million. This grant was part of the Companys regular
annual compensation process. These PSAs
will vest 1/7
th
on July 1, 2011, 2/7
ths
on
July 1, 2012, and 4/7
ths
on
July 1, 2013.
Restricted Stock Unit Incentive
Program Under the Equity Incentive Compensation Plan
Total RSU compensation expense for both
the three-month periods ended September 30, 2010, and 2009, was $2.1
million, and $5.7 million and $5.9 million for the nine-month periods ended September 30,
2010, and 2009, respectively. As of September 30,
2010, there was $8.2 million of total unrecognized compensation expense
related to unvested RSU awards that is being amortized through 2013.
During the first nine months of
2010, the Company settled 83,008 RSUs that relate to awards granted in 2009,
2008 and 2007 through the issuance of shares of the Companys common stock in
accordance with the terms of the RSU awards.
As a result, the Company issued 57,687 shares of common stock associated
with these grants. The remaining 25,321
shares were withheld to satisfy income and payroll tax withholding obligations
that occurred upon the delivery of the shares underlying those RSUs.
A summary of the status and activity
of RSUs for the nine-month period ended September 30, 2010, is
presented in the following table:
|
|
RSUs
|
|
Weighted-
Average Grant-
Date Fair Value
|
|
Non-vested,
at January 1, 2010
|
|
407,123
|
|
|
$
|
34.67
|
|
Granted
|
|
126,821
|
|
|
$
|
40.17
|
|
Vested
|
|
(81,775
|
)
|
|
$
|
31.45
|
|
Forfeited
|
|
(31,358
|
)
|
|
$
|
36.46
|
|
Non-vested
and outstanding, at September 30, 2010
|
|
420,811
|
|
|
$
|
36.82
|
|
13
Table
of Contents
During the third quarter of 2010 the
Company granted 126,821 RSUs with a fair value of $5.1 million, as part of its
regular annual compensation process.
Each RSU represents a right to receive one share of the Companys common
stock to be delivered upon settlement of the vested RSU. These RSUs will vest 1/7
th
on
July 1, 2011, 2/7
ths
on
July 1, 2012, and 4/7
ths
on
July 1, 2013.
Stock Option Grants Under Prior Stock Option
Plans
The following table summarizes stock
option activity for the nine months ended September 30, 2010:
|
|
Options
|
|
Weighted-
Average
Exercise
Price
|
|
Weighted-
Average
Remaining
Contractual
Term
(In years)
|
|
Aggregate
Intrinsic Value
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding,
beginning of period
|
|
1,274,920
|
|
|
$
|
13.31
|
|
|
|
|
|
Exercised
|
|
(163,348
|
)
|
|
$
|
14.19
|
|
|
|
|
|
Forfeited
|
|
|
|
|
$
|
|
|
|
|
|
|
Outstanding,
end of period
|
|
1,111,572
|
|
|
$
|
13.18
|
|
2.4
|
|
$
|
26,988
|
|
Vested
at end of period
|
|
1,111,572
|
|
|
$
|
13.18
|
|
2.4
|
|
$
|
26,988
|
|
Exercisable,
end of period
|
|
1,111,572
|
|
|
$
|
13.18
|
|
2.4
|
|
$
|
26,988
|
|
As of September 30, 2010, there
was no unrecognized compensation expense related to stock option awards.
Director Shares
In May 2010 and 2009 the
Company issued 24,258 and 50,094 shares, respectively, of the Companys common
stock from treasury to the Companys non-employee directors. The shares were issued pursuant to the
Companys Equity Incentive Compensation Plan. The Company recorded
$33,000 and $26,000 of compensation expense for the three-month periods ended September 30,
2010, and 2009, respectively, and $748,000 and $662,000 for the nine-month
periods ended September 30, 2010, and 2009, respectively.
Employee Stock Purchase Plan
Under the Companys Employee Stock
Purchase Plan (the ESPP), eligible employees may purchase shares of the
Companys common stock through payroll deductions of up to 15 percent of
eligible compensation. The purchase
price of the stock is 85 percent of the lower of the fair market value of
the stock on the first or last day of the purchase period, and shares issued
under the ESPP are restricted for a period of six months from the date
issued. The ESPP is intended to qualify
under Section 423 of the Internal Revenue Code. The Company has set aside 2,000,000 shares of
its common stock to be available for issuance under the ESPP, of which
1,440,819 shares are available for issuance as of
September 30, 2010. The fair
value of ESPP grants is measured at the date of grant using the Black-Scholes
option-pricing model. There were 27,456
and 49,767 shares issued under the ESPP during the first nine months of 2010
and 2009, respectively. The Company
expensed $162,000 and $153,000 for the three-month periods ended September 30,
2010, and 2009, respectively, and $425,000 and $694,000 for the nine-month
periods ended September 30, 2010, and 2009, respectively, based on the
estimated fair values on the respective grant dates.
14
Table
of Contents
Net Profits Plan
Prior
to 2008, all oil and gas wells that were completed or acquired during each year
were assigned to a specific pool for that respective year under the Companys
legacy Net Profits Plan. Key employees
become entitled to payments under the Net Profits Plan after the Company has
received net cash flows returning 100 percent of all costs associated with
a pool. Thereafter, ten percent of
future net cash flows generated by the pool are allocated among the
participants and distributed at least annually.
The portion of net cash flows from the pool to be allocated among the
participants increases to 20 percent after the Company has recovered both
200 percent of the total costs for the pool and 100 percent of pool
payments made under the Net Profits Plan at the ten percent level. The 2007 Net Profits Plan pool was the last
pool established by the Company.
Cash payments made or accrued under
the Net Profits Plan that have been recorded as either general and
administrative expense or exploration expense are detailed in the table below:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative expense
|
|
$
|
3,918
|
|
$
|
5,168
|
|
$
|
16,233
|
|
$
|
12,942
|
|
Exploration
expense
|
|
638
|
|
239
|
|
1,896
|
|
1,116
|
|
Total
|
|
$
|
4,556
|
|
$
|
5,407
|
|
$
|
18,129
|
|
$
|
14,058
|
|
Additionally, the Company made cash
payments under the Net Profits Plan of $686,000 and $20.8 million for the
three-month and nine-month periods ended September 30, 2010,
respectively, as a result of sales proceeds mainly from the Legacy and Sequel
divestitures. The cash payments are
accounted for as a reduction of proceeds, which reduced the gain (loss) on
divestiture activity in the accompanying statements of operations. There were no cash payments made under the
Net Profits Plan as a result of divestitures that occurred during the first
nine months of 2009.
The Company records changes in the
present value of estimated future payments under the Net Profits Plan as a
separate line item in the accompanying statements of operations. The change in the estimated liability is
recorded as a non-cash expense or benefit in the current period. The amount recorded as an expense or benefit
associated with the change in the estimated liability is not allocated to
general and administrative expense or exploration expense because it is
associated with the future net cash flows from oil and gas properties in the
respective pools rather than results being realized through current period
production. The table below presents the
estimated allocation of the change in the liability if the Company did allocate
the adjustment to these specific functional line items based on the current
allocation of actual distributions made by the Company. As time progresses, less of the distributions
relate to prospective exploration efforts as more of the distributions are made
to participants that have terminated employment and do not provide ongoing
exploration support to the Company.
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative expense (benefit)
|
|
$
|
4,062
|
|
$
|
5,807
|
|
$ (26,670
|
)
|
|
$
|
(12,923)
|
|
Exploration
expense (benefit)
|
|
24
|
|
997
|
|
(3,115
|
)
|
|
(1,115)
|
|
Total
|
|
$
|
4,086
|
|
$
|
6,804
|
|
$ (29,785
|
)
|
|
$
|
(14,038)
|
|
15
Table of Contents
Note 8 Pension
Benefits
Pension Plans
The Company has a non-contributory
pension plan covering substantially all employees who meet age and service
requirements (the Qualified Pension Plan).
The Company also has a supplemental non-contributory pension plan
covering certain management employees (the Nonqualified Pension Plan).
Components of Net Periodic Benefit Cost for
Both Plans
The following table presents the
total components of the net periodic cost for both the Qualified Pension Plan
and the Nonqualified Pension Plan:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
Service
cost
|
|
$
|
848
|
|
|
$
|
625
|
|
|
$
|
2,544
|
|
|
$
|
1,875
|
|
|
Interest
cost
|
|
280
|
|
|
234
|
|
|
840
|
|
|
701
|
|
|
Expected
return on plan assets
|
|
(159
|
)
|
|
(108
|
)
|
|
(477
|
)
|
|
(323
|
)
|
|
Amortization
of net actuarial loss
|
|
91
|
|
|
93
|
|
|
273
|
|
|
279
|
|
|
Net
periodic benefit cost
|
|
$
|
1,060
|
|
|
$
|
844
|
|
|
$
|
3,180
|
|
|
$
|
2,532
|
|
|
Prior service costs are amortized on
a straight-line basis over the average remaining service period of active
participants. Gains and losses in excess
of ten percent of the greater of the benefit obligation or the market-related
value of assets are amortized over the average remaining service period of
active participants.
Contributions
Under the Pension Protection Act of
2006, SM Energy is not required to make a minimum contribution to the pension
plans in 2010. However, the Company
contributed $1.7 million in September 2010 based upon the preliminary
funding results analysis completed in April 2010 in order to maintain an
adequate funding level to provide retirement benefits to current and future
plan participants and to maintain an adequate funding level to provide lump sum
payments if elected by participants.
Note 9 Asset Retirement Obligations
The Company recognizes an estimated
liability for future costs associated with the plugging and abandonment of its
oil and gas properties. A liability for
the fair value of an asset retirement obligation and a corresponding increase
to the carrying value of the related long-lived asset are recorded at the time
a well is completed or acquired. The
increase in carrying value is included in proved oil and gas properties in the
accompanying balance sheets. The Company
depletes the amount added to proved oil and gas property costs and recognizes
expense in connection with the accretion of the discounted liability over the remaining
estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement
obligations is included in the operating section of the Companys accompanying
condensed consolidated statements of cash flows.
The Companys estimated asset
retirement obligation liability is based on estimated economic lives,
historical experience in plugging and abandoning wells, estimated cost to plug
and abandon the wells in the future, and federal and state regulatory
requirements. The liability is
discounted using a credit-adjusted risk-free rate estimated at the time the
liability is incurred or revised. The
credit-adjusted risk-free rates
16
Table of Contents
used to discount the Companys
abandonment liabilities range from 6.5 percent to 12.0 percent. Revisions to the liability could occur due to
changes in estimated abandonment costs or well commerciality, or if federal or
state regulators enact new requirements regarding the abandonment of
wells. The asset retirement obligation
is considered settled when the well has been plugged and abandoned or divested.
A reconciliation of the Companys
asset retirement obligation liability is as follows:
|
|
For the Nine Months
Ended September 30,
|
|
|
|
(In thousands)
|
|
|
|
|
|
Beginning
asset retirement obligation
|
|
$
|
102,080
|
|
|
Liabilities
incurred
|
|
3,501
|
|
|
Liabilities
settled
|
|
(26,962
|
)
|
|
Accretion
expense
|
|
4,237
|
|
|
Revision
to estimated cash flow
|
|
(10
|
)
|
|
Ending
asset retirement obligation
|
|
$
|
82,846
|
|
|
As of September 30, 2010, the
Company had $3.1 million of asset retirement obligation associated with the oil
and gas properties held for sale included in a separate line item on the
Companys accompanying balance sheets.
Additionally, as of September 30, 2010, accounts payable and
accrued expenses contained $15.5 million related to the Companys current asset
retirement obligation liability associated with the estimated retirement of
some of the Companys offshore platforms.
Note 10 Derivative Financial Instruments
Oil, Natural Gas, and NGL Commodity Hedges
To mitigate a portion of the
exposure to potentially adverse market changes in oil, gas, and NGL prices and
the associated impact on cash flows, the Company has entered into various
derivative contracts. The Companys
derivative contracts in place include swap and collar arrangements for oil,
natural gas, and NGLs. As of
September 30, 2010, the Company has hedge contracts in place through
the second quarter of 2013 for a total of approximately 5 million Bbls of
anticipated crude oil production, 42 million MMBtu of anticipated natural
gas production, and 2 million Bbls of anticipated NGL production. As of October 27, 2010, the Company
has hedge contracts in place through the third quarter of 2013 for a total of
approximately 7 million Bbls of anticipated crude oil production,
42 million MMBtu of anticipated natural gas production, and 2 million
Bbls of anticipated NGL production.
The Company attempts to qualify its
oil, natural gas, and NGL derivative instruments as cash flow hedges for
accounting purposes under derivative and hedging authoritative guidance. The Company formally documents all
relationships between the derivative instruments and the hedged production, as
well as the Companys risk management objective and strategy for the particular
derivative contracts. This process
includes linking all derivatives that are designated as cash flow hedges to the
specific forecasted sale of oil, natural gas or NGLs. The Company also formally assesses (both at
the derivatives inception and on an ongoing basis) whether the derivatives
being utilized have been highly effective in offsetting changes in the cash
flows of hedged production and whether those derivatives may be expected to
remain highly effective in future periods.
If it is determined that a derivative has ceased to be highly effective
as a hedge, the Company will discontinue hedge accounting for that derivative
prospectively. If hedge accounting is
discontinued and the derivative remains outstanding, the Company will recognize
all subsequent changes in its fair value in the Companys consolidated
statements of operations for the period in which the change occurs. As of September 30, 2010, all oil,
natural gas, and NGL derivative instruments qualified as cash flow hedges for
accounting purposes. The Company
anticipates that all forecasted
17
Table of Contents
transactions will occur by the end
of their originally specified periods.
All contracts are entered into for other-than-trading purposes.
The Companys oil, natural gas, and NGL hedges are measured at fair
value and are included in the accompanying balance sheets as derivative assets
and liabilities. The Company derives
internal valuation estimates taking into consideration the counterparties
credit worthiness, the Companys credit worthiness, and the time value of
money. Those internal valuations are
then compared to the counterparties mark-to-market statements. The consideration of the factors results in
an estimated exit-price for each derivative asset or liability under a market
place participants view. Management
believes that this approach provides a reasonable, non-biased, verifiable, and
consistent methodology for valuing commodity derivative instruments. The derivative instruments utilized by the
Company are not considered by management to be complex, structured, or
illiquid. The oil, natural gas, and NGL
derivative markets are highly active.
The fair value of oil, natural gas, and NGL derivative contracts
designated and qualifying as cash flow hedges was a net asset of $6.5 million
and a net liability of $80.9 million at September 30, 2010, and
December 31, 2009, respectively.
The following table details the fair value of derivatives recorded in
the accompanying balance sheets, by category:
|
|
Location on Consolidated
Balance Sheets
|
|
Fair Value at
September 30, 2010
|
|
Fair Value at
December 31, 2009
|
|
|
|
|
|
(In thousands)
|
|
Derivative assets
designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current assets Derivative asset
|
|
$
|
56,199
|
|
|
$
|
30,295
|
|
|
Commodity
contracts
|
|
Other noncurrent assets
Derivative asset
|
|
29,444
|
|
|
8,251
|
|
|
Total derivative assets
designated as cash flow hedges
|
|
|
|
$
|
85,643
|
|
|
$
|
38,546
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
Current liabilities Derivative
liability
|
|
$
|
(53,732
|
)
|
|
$
|
(53,929
|
)
|
|
Commodity
contracts
|
|
Noncurrent liabilities
Derivative liability
|
|
(25,450
|
)
|
|
(65,499
|
)
|
|
Total derivative
liabilities designated as cash flow hedges
|
|
|
|
$
|
(79,182
|
)
|
|
$
|
(119,428
|
)
|
|
Realized gains or losses from the
settlement of oil, natural gas, and NGL derivative contracts are reported in
the total operating revenues and other income section of the accompanying
statements of operations. The Company
realized a net gain of $8.8 million and $28.3 million from its oil,
natural gas, and NGL derivative contracts for the three months ended
September 30, 2010, and 2009, respectively, and realized a net gain
of $20.8 million and $127.2 million from its oil, natural gas, and NGL derivative
contracts for the nine months ended September 30, 2010, and 2009,
respectively.
After-tax changes in the fair value
of derivative instruments designated as cash flow hedges, to the extent they
are effective in offsetting cash flows attributed to the hedged risk, are
recorded in accumulated other comprehensive income in the accompanying balance
sheets until the hedged item is realized in earnings upon the sale of the
associated hedged production. As of
September 30, 2010, the amount of unrealized gain, net of deferred
income taxes, to be reclassified from accumulated other comprehensive
18
Table of Contents
income to realized oil and gas hedge
gain in the Companys accompanying statements of operations in the next twelve
months is $10.2 million.
The Company seeks to minimize
ineffectiveness by entering into oil derivative contracts indexed to the New
York Mercantile Exchange West Texas Intermediate (NYMEX WTI) index, natural
gas derivative contracts indexed to regional index prices associated with
pipelines in proximity to the Companys areas of production, and NGL derivative
contracts indexed to Oil Price Information Service Mont Belvieu. The Companys derivative contracts utilize
the same respective indices or pricing points as the Companys sales
contracts. As a result, the derivative
contracts used by the Company are highly correlated with prices received upon
the sale of the underlying hedged production.
The following table details the
effect of derivative instruments on other comprehensive income (loss) and the
accompanying balance sheets (net of income tax):
|
|
Derivatives
Qualifying as
Cash Flow
Hedges
|
|
Location on
Consolidated
Balance Sheets
|
|
Balance as of
September 30,
2010
|
|
Balance as of
December 31,
2009
|
|
|
|
|
|
|
|
(In thousands)
|
|
Amount of (gain) loss on derivatives recognized in
OCI during the period (effective portion)
|
|
Commodity contracts
|
|
Accumulated other
comprehensive income (loss)
|
|
$
|
(50,136)
|
|
$
|
35,977
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table details the
effect of derivative instruments on other comprehensive income (loss) and the
accompanying statements of operations (net of income tax):
|
|
Derivatives
Qualifying as
Cash Flow
|
|
Location on
Consolidated
Statements of
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
Hedges
|
|
Operations
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
(In thousands)
|
|
Amount of (gain) loss reclassified from AOCI to
realized oil and gas hedge gain (loss) (effective portion)
|
|
Commodity Contracts
|
|
Realized oil and gas hedge
gain
|
|
$
|
2,685
|
|
|
$(12,485)
|
|
$
|
1,903
|
|
$(57,979)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
Table
of Contents
Any changes in fair value resulting
from hedge ineffectiveness is recognized currently in unrealized derivative
(gain) loss in the accompanying statement of operations. The following table details the effect of
derivative instruments on the accompanying statements of operations:
|
|
Location on
|
|
(Gain) Loss Recognized in Earnings
(Ineffective Portion)
|
|
Derivatives Qualifying
|
|
Consolidated
Statements of
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
as Cash Flow Hedges
|
|
Operations
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
|
|
(In thousands)
|
|
Commodity
contracts
|
|
Unrealized derivative
(gain) loss
|
|
$
|
5,727
|
|
$
|
4,117
|
|
$
|
(4,095)
|
|
$
|
17,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit Related Contingent Features
As of September 30, 2010, only
one of the Companys hedge counterparties was not a member of the Companys
credit facility bank syndicate. Member
banks are secured by the Companys oil and gas assets, and therefore do not
require the Company to post collateral in instances where the Company is in a
liability position. When the Company is
in a liability position with the non-member bank, posting of collateral may be
required if the Companys liability balance exceeds the limit set forth in the
agreement with the non-member bank. With
the one non-member bank, the amount of collateral, if any, that the Company is
required to post depends on a number of financial metrics that are calculated
quarterly. No collateral was posted as
of September 30, 2010, or October 27, 2010.
Convertible Note Derivative Instruments
The contingent interest provision of
the 3.50% Senior Convertible Notes is an embedded derivative instrument. As of September 30, 2010, and
December 31, 2009, the value of this derivative was determined to be
immaterial.
Note 11 Fair Value Measurements
The Company follows fair value
measurement authoritative guidance for all assets and liabilities measured at
fair value. That guidance defines fair
value as the price that would be received to sell an asset or paid to transfer
a liability (an exit price) in an orderly transaction between market
participants at the measurement date.
Market or observable inputs are the preferred sources of values,
followed by assumptions based on hypothetical transactions in the absence of
market inputs. The hierarchy for
grouping these assets and liabilities is based on the significance level of the
following inputs:
·
Level 1 Quoted prices in active markets for identical
assets or liabilities
·
Level 2 Quoted prices in active markets for similar assets
and liabilities, quoted prices for identical or similar instruments in markets
that are not active, and model-derived valuations whose inputs are observable
or whose significant value drivers are observable
·
Level 3
Significant inputs to the valuation model are unobservable
20
Table
of Contents
The following is a listing of the
Companys financial assets and liabilities that are measured at fair value on a
recurring basis and where they are classified within the hierarchy as of September 30,
2010:
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
|
|
$
|
85,643
|
|
$
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Derivatives
|
|
$
|
|
|
$
|
79,182
|
|
$
|
|
|
Net
Profits Plan
|
|
$
|
|
|
$
|
|
|
$
|
140,506
|
|
There were no nonfinancial assets or
liabilities measured at fair value on a nonrecurring basis at September 30,
2010.
The following is a listing of the
Companys assets and liabilities that are measured at fair value and where they
are classified within the hierarchy as of December 31, 2009:
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
(In thousands)
|
|
Assets:
|
|
|
|
|
|
|
|
Derivatives
(a)
|
|
$
|
|
|
$
|
38,546
|
|
$
|
|
|
Proved
oil and gas properties
(b)
|
|
$
|
|
|
$
|
|
|
$
|
11,740
|
|
Materials
inventory
(b)
|
|
$
|
|
|
$
|
13,882
|
|
$
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Derivatives
(a)
|
|
$
|
|
|
$
|
119,428
|
|
$
|
|
|
Net Profits
Plan
(a)
|
|
$
|
|
|
$
|
|
|
$
|
170,291
|
|
(a) This represents a financial asset or
liability that is measured at fair value on a recurring basis.
(b) This represents a nonfinancial asset or
liability that is measured at fair value on a nonrecurring basis.
Both financial and non-financial
assets and liabilities are categorized within the hierarchy based on the lowest
level of input that is significant to the fair value measurement. The following is a description of the valuation
methodologies used by the Company as well as the general classification of such
instruments pursuant to the hierarchy.
Derivatives
The Company uses Level 2 inputs to
measure the fair value of oil, gas, and NGL hedges. Fair values are based upon interpolated
data. The Company derives internal
valuation estimates that take into account nonperformance risk by considering
counterparties credit ratings, the Companys credit rating, and the time value of money. The considered factors result in an estimated
exit-price that management believes provides a reasonable and consistent
methodology for valuing derivative instruments.
Generally, market quotes assume that
all counterparties have near zero, or low, default rates and have equal credit
quality. However, an adjustment may be
necessary to reflect the credit quality and nonperformance risk of a specific
counterparty to determine the fair value of the instrument. In order to mitigate the risk of
nonperformance, the Company monitors the credit ratings of its counterparties
and may ask counterparties to post collateral if their ratings
deteriorate. In some instances the
Company may attempt to novate trades with parties deemed to have more risk on a
relative basis to a more stable and less risky counterparty.
Valuation adjustments are necessary
to reflect the effect of the Companys credit quality on the fair value of any
liability position with a counterparty.
This adjustment takes into account any credit
21
Table of Contents
enhancements, such as collateral
margin that the Company may have posted with a counterparty, as well as any
letters of credit between the parties.
The methodology to determine this adjustment is consistent with how the
Company evaluates counterparty credit risk, taking into account the Companys
credit rating, current credit facility margins, and any change in such margins
since the last measurement date. The
majority of the Companys derivative counterparties are members of SM Energys
credit facility bank syndicate.
The methods described above may
result in a fair value estimate that may not be indicative of net realizable
value or may not be reflective of future fair values and cash flows. While the Company believes that the valuation
methods utilized are appropriate and consistent with GAAP and with other
marketplace participants, the Company recognizes that third parties may use
different methodologies or assumptions to determine the fair value of certain
financial instruments that could result in a different estimate of fair value
at the reporting date.
Net Profits Plan
The Net Profits Plan is a standalone
liability for which there is no available market price, principal market, or market
participants. The inputs available for
this instrument are unobservable, and are therefore classified as Level 3
inputs. The Company employs the income
approach, which converts expected future cash flow amounts to a single present
value amount. This technique uses the
estimate of future cash payments, expectations of possible variations in the
amount and/or timing of cash flows, the risk premium, and nonperformance risk
to calculate the fair value. There is a
direct correlation between realized oil and gas commodity prices and their
impact on net cash flows and the amount of the Net Profits Plan liability. Generally, higher commodity prices result in
a larger Net Profits Plan liability and vice versa.
The Company records the estimated
fair value of the long-term liability for estimated future payments under the
Net Profits Plan based on the discounted value of estimated future payments
associated with each individual pool.
The calculation of this liability is a significant management
estimate. For a predominate number of
the pools, a discount rate of 12 percent is used to calculate this
liability. This rate is intended to
represent the best estimate of the present value of expected future payments
under the Net Profits Plan.
The Companys estimate of its
liability is highly dependent on commodity prices, cost assumptions, and the
discount rates used in the calculations.
The Company continually evaluates the assumptions used in this
calculation in order to consider the current market environment for oil and gas
prices, costs, discount rates, and overall market conditions. The Net Profits Plan liability was determined
using price assumptions of five one-year strip prices with the fifth years
pricing then carried out indefinitely.
The average price was adjusted to include the effects of hedging for the
percentage of forecasted production hedged in the relevant periods. The non-cash expense associated with this
significant management estimate is highly volatile from period to period due to
fluctuations that occur in the crude oil, natural gas, and NGL commodity
markets.
If the commodity prices used in the
calculation changed by five percent, the liability recorded at September 30,
2010, would differ by approximately $11 million. A one percentage point increase in the
discount rate would decrease the liability by approximately $6 million whereas
a one percentage point decrease in the discount rate would increase the
liability by $7 million. Actual cash
payments to be made to participants in future periods are dependent on realized
actual production, realized commodity prices, and costs associated with the
properties in each individual pool of the Net Profits Plan. Consequently, actual cash payments are inherently
different from the amounts estimated. No
published market quotes exist on which to base the Companys estimate of fair
value of the Net Profits Plan liability.
As such, the recorded fair value is based entirely on management
estimates that are described within this footnote. While some inputs to the Companys
calculation of fair value on the Net Profits Plans future payments are from
published sources, others, such as the discount rate and the expected future
cash flows, are derived from the Companys own calculations and estimates.
22
Table of Contents
The following table reflects the
activity for the Net Profits Plan liability measured at fair value using Level 3
inputs:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Beginning
balance
|
|
$
|
136,420
|
|
|
$
|
156,524
|
|
|
$
|
170,291
|
|
|
$
|
177,366
|
|
|
Net
increase (decrease) in liability
(a)
|
|
9,328
|
|
|
12,211
|
|
|
9,110
|
|
|
20
|
|
|
Net
settlements
(a)(b)
|
|
(5,242
|
)
|
|
(5,407
|
)
|
|
(38,895
|
)
|
|
(14,058
|
)
|
|
Transfers
in (out) of Level 3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance
|
|
$
|
140,506
|
|
|
$
|
163,328
|
|
|
$
|
140,506
|
|
|
$
|
163,328
|
|
|
(a) Net changes in the Net Profits Plan liability
are shown in the Change in Net Profits Plan liability line item of the
accompanying statements of operations.
(b) Settlements represent cash payments made or
accrued under the Net Profits Plan.
Settlements for the three months and nine months ended September 30,
2010, include $686,000 and $20.8 million, respectively, of cash payments made
related primarily to the Legacy and Sequel divestitures. There were no cash payments made under the
Net Profits Plan as a result of divestitures for the three months or nine
months ended September 30, 2009.
3.50% Senior Convertible Notes Due 2027
Based on the market price of the
3.50% Senior Convertible Notes, the estimated fair value of the notes was
approximately $301 million and $290 million as of September 30, 2010, and
December 31, 2009, respectively.
Proved Oil and Gas Properties
Proved oil and gas property costs
are evaluated for impairment against undiscounted future cash flows and reduced
to fair value (discounted future cash flows) if the sum of the expected
undiscounted future cash flows is less than net book value. The Company uses Level 3 inputs and the
income valuation technique, which converts future amounts to a single present
value amount, to measure the fair value of proved properties through an
application of discount rates and price forecasts selected by the Companys
management. The discount rate is a rate
that management believes is representative of current market conditions and
includes the following factors: estimates of future cash payments, expectations
of possible variations in the amount and/or timing of cash flows, the risk
premium, and nonperformance risk. The
price forecast is based on NYMEX strip pricing, adjusted for basis differentials,
for the first five years. Future
operating costs are also adjusted as deemed appropriate for these estimates.
Of the $2.1 billion of long-lived
assets, excluding materials inventory, $11.7 million were measured at fair
value at December 31, 2009. There
were no long-lived assets measured at fair value within the accompanying
balance sheets at September 30, 2010.
Materials Inventory
Materials inventory is valued at the
lower of cost or market. The Company
uses Level 2 inputs to measure the fair value of materials inventory, which is
primarily comprised of tubular goods.
The Company uses third party market quotes and compares the quotes to
the book value of the materials inventory.
If the book value exceeds the quoted market price, the Company reduces
the book value to the market price. The
considered factors result in an estimated exit-price that management believes
provides a reasonable and consistent methodology for valuing materials
inventory.
Of the $24.5 million of materials
inventory, $13.9 million was measured at fair value at
December 31, 2009. There was
no materials inventory measured at fair value within the accompanying balance
sheets at September 30, 2010.
23
Table of
Contents
Asset Retirement Obligations
The Company estimates asset
retirement obligations pursuant to asset retirement and environmental
obligations authoritative guidance. The
Company uses the income valuation technique to determine the fair value of the
asset retirement obligation liability at the point of inception by applying a
credit-adjusted risk-free rate, which takes into account the Companys credit
risk, the time value of money, and the current economic state, to the undiscounted
expected abandonment cash flows. Given
the unobservable nature of the inputs, the initial measurement of the asset
retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations
measured at fair value within the accompanying consolidated balance sheets at September 30,
2010, or December 31, 2009.
Refer to Note 10 Derivative
Financial Instruments and Note 9 Asset Retirement Obligations for more
information regarding the Companys hedging instruments and asset retirement
obligations.
Note 12 Recent Accounting
Pronouncements
The Company partially adopted new
fair value measurement authoritative guidance that requires additional
disclosures surrounding transfers between Levels 1 and 2, inputs and valuation
techniques used to value Level 2 and 3 measurements, and push down of
previously prescribed fair value disclosures to each class of asset and
liability for Levels 1, 2, and 3. These
disclosures were effective for the Company for the quarter ended March 31, 2010. The partial adoption did not have a material
impact on the Companys consolidated financial statements. Please refer to Note 11 Fair Value
Measurements.
The Company will apply new fair
value measurement authoritative guidance requiring that purchases, sales,
issuances, and settlements for Level 3 measurements be disclosed. These disclosures are effective for interim
and annual reporting periods beginning after December 15, 2010. The Company will apply this new guidance in
the Companys Quarterly Report on Form 10-Q for the period ended
March 31, 2011. The adoption
of this guidance is not expected to have a material impact on the Companys
financial statements.
The
Company adopted new subsequent events authoritative guidance that removes the
requirement for SEC filers to disclose the date through which an entity has
evaluated subsequent events. However,
the date-disclosure exemption does not relieve management of an SEC filer from
its responsibility to evaluate subsequent events through the date on which
financial statements are issued. This
authoritative guidance was effective upon issuance on
February 24, 2010. The
adoption of this pronouncement did not have a material impact on the Companys
consolidated financial statements.
Note 13 Carry and Earning
Agreement
On April 29, 2010, the
Company entered into a Carry and Earning Agreement (the CEA), which
effectively provides for a third party to earn 95 percent of SM Energys
interest in approximately 8,400 net acres in a portion of the Companys East
Texas Haynesville shale acreage, as well as an interest in several wells and
five percent of SM Energys interest in approximately 23,400 net acres in a
separate portion of the Companys Haynesville acreage in East Texas. In exchange for these interests, the third
party has agreed to invest $91.3 million to fund the drilling and completion
costs of horizontal wells in the portion of the leases where the Company is
retaining 95 percent of its interest. Of
this, $86.7 million represents SM Energys carried drilling and completion
costs, which is 95 percent of the total well costs to be invested by the third
party. The Company received an initial
payment of $45.6 million on April 29, 2010, and the CEA provides that
the Company will receive the balance of the committed funds less any
adjustments allowed under the CEA for title defects within 30 days of the
completion of the fourth commitment well.
Once SM Energy has completed the expenditure of the total carry amount,
the parties will share all costs of operations within the area of joint
ownership in accordance with their respective ownership interests.
24
Table of Contents
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion and analysis
contains forward-looking statements. Refer to Cautionary Information about
Forward-Looking Statements at the end of this item for an explanation of these
types of statements.
Overview of the Company,
Highlights, and Outlook
General Overview
We are an independent energy company
focused on the development, exploration, exploitation, acquisition, and
production of natural gas, NGLs, and crude oil in the continental United
States. Generally, we generate nearly
all our revenues and cash flows from the sale of produced natural gas and crude
oil. In the first nine months of 2010 we
have generated significant gains and cash proceeds from the sale of
non-strategic oil and gas properties.
Our oil and gas reserves and operations are concentrated primarily in
the Eagle Ford shale in South Texas; the Williston Basin in North Dakota and
Montana; the Mid-Continent Anadarko and Arkoma basins; the Permian Basin; North
Central Pennsylvania; and the productive formations of East Texas and North
Louisiana. We have developed a balanced
and diverse portfolio of proved reserves, development drilling opportunities,
and unconventional resource prospects.
Please refer
to
Marketing of non-core properties
for
additional discussion related to our Marcellus assets in North Central
Pennsylvania.
Our mission is to deliver
outstanding net asset value per share growth to our investors via attractive
oil and gas investments. Our strategy is
to focus on early entrance into existing and emerging resource plays in North
America. By entering these plays
earlier, we believe that we can capture larger resource potential at lower
cost. We believe this organic-centered
model allows for more stable and predictable production and proved reserves
growth.
Financial Standing and Liquidity
In the third quarter of 2010, the
borrowing base on our credit facility was redetermined and was increased from
$900.0 million to $1.1 billion. The
commitment amount of the bank group remained unchanged at $678.0 million. At the end of the third quarter 2010, we had
$2.0 million outstanding under the revolving credit facility. As of October 27, 2010, the outstanding
balance was $38.0 million. We have no
debt maturities until 2012, at which time our credit facility matures and our
outstanding convertible notes can be put to us.
Given our debt and asset levels, credit standing, and relationships with
the participants in our bank group, we believe we will be able to extend our
existing facility or obtain a replacement credit facility before our current
credit facility matures in 2012. We also
believe our convertible notes could be put to us in 2012, at which time we have
the option of settling with some combination of cash and/or common stock. The condition of the capital markets has
improved significantly since last year, and therefore we believe we could
access capital through the public markets, if necessary, to redeem these notes.
We expect our cash flows from
operations in 2010 plus proceeds from our divestitures of non-core assets to
fund the majority of our capital budget for 2010. We plan to use our credit facility to fund
the remaining portion of our capital program.
Accordingly, we do not anticipate accessing the equity or public debt
markets for the remainder of 2010. Given
the size of our commitments associated with our existing inventory of potential
drilling projects, our requirements for funding could increase significantly in
2011 and beyond. As a result, we may
consider accessing the capital markets, and other alternatives, as we determine
how to best fund our capital program. We
continue to believe we have adequate liquidity available as discussed under the
caption Overview of Liquidity and Capital Resources.
25
Table of
Contents
Oil and Gas Prices
Our
financial condition and the results of our operations are significantly
affected by the prices we receive for oil, natural gas, and NGLs, which can
fluctuate dramatically. Please refer to
Comparison of Financial Results and Trends between the three months
ended September 30, 2010, and 2009
and
Comparison
of Financial Results and Trends between the nine months ended September 30,
2010, and 2009
for the realized price tables for the respective
periods. We sell a majority of our
natural gas under contracts that use first of the month index pricing, which
means that gas produced in a given month is sold at the first of the month
price regardless of the spot price on the day the gas is produced. We account for the majority of our natural
gas sales as they occur at the wellhead and accordingly do not present a
separate production stream for the NGLs processed from our natural gas
production. We receive value for the NGL
content in our natural gas stream, which can result in us realizing a higher
per unit price for our reported gas production.
Sales of processed NGLs are immaterial and are included with our natural
gas production and sales. Our crude oil
is sold using contracts that pay us either the average of the NYMEX WTI daily
settlement price or the average of alternative posted prices for the periods in
which the crude oil is produced, adjusted for quality, transportation, and
location differentials.
The
following table is a summary of commodity price data for the third quarters of
2010 and 2009 and the second quarter of 2010:
|
|
For the Three Months Ended
|
|
|
|
September 30, 2010
|
|
June 30, 2010
|
|
September 30, 2009
|
|
Crude
Oil (per Bbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
NYMEX price
|
|
|
$
|
76.09
|
|
|
|
$
|
77.88
|
|
|
|
$
|
68.30
|
|
|
Realized
price, before the effects of hedging
|
|
|
$
|
68.56
|
|
|
|
$
|
70.92
|
|
|
|
$
|
61.93
|
|
|
Net
realized price, including the effects of hedging
|
|
|
$
|
64.28
|
|
|
|
$
|
65.17
|
|
|
|
$
|
62.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas (per Mcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
NYMEX price
|
|
|
$
|
4.28
|
|
|
|
$
|
4.33
|
|
|
|
$
|
3.41
|
|
|
Realized
price, before the effects of hedging
|
|
|
$
|
4.93
|
|
|
|
$
|
4.54
|
|
|
|
$
|
3.37
|
|
|
Net
realized price, including the effects of hedging
|
|
|
$
|
5.81
|
|
|
|
$
|
5.59
|
|
|
|
$
|
4.95
|
|
|
We expect future prices for oil,
NGLs, and natural gas to be volatile. In
addition to supply and demand fundamentals, the relative strength of the U.S.
Dollar will likely continue to impact crude oil prices. Historically, NGL prices have trended and
correlated with the price for crude oil.
The supply of NGLs is expected to grow in the near term as a result of a
number of industry participants targeting projects that produce these products,
which could increase supplies and negatively impact future pricing. Future natural gas prices are facing downward
pressure as a result of a supply overhang resulting from high levels of
drilling activity across the country, as well as tepid demand recovery due to
the economic recession in the United States.
The 12-month strip prices for NYMEX WTI crude oil and NYMEX Henry Hub
natural gas as of September 30, 2010, were $83.42 per Bbl and $4.29 per
MMBTU, respectively. Comparable prices
as of October 27, 2010, were $84.52 per Bbl and $4.02 per MMBTU,
respectively.
While changes in quoted NYMEX oil
and natural gas prices are generally used as a basis for comparison within our
industry, the price we receive for oil and natural gas is affected by quality,
energy content, location, and transportation differentials for these
products. We refer to this price as our
realized price, which excludes the effects of hedging. Our realized price is further impacted by the
results of our hedging arrangements that are settled in the respective
periods. We refer to this price as our
net realized price. For the three months
ended September 30, 2010, our net natural gas price realization was
positively
26
Table of Contents
impacted by $15.6 million of
realized hedge settlements and our net oil price realization was negatively
impacted by $6.8 million of realized hedge settlements.
Hedging Activities
On
July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection
Act was enacted into law. This financial
reform legislation includes provisions that require over-the-counter derivative
transactions to be executed through an exchange or centrally cleared. The Dodd-Frank Act requires the Commodities
Futures Trading Commission (the CFTC) and the Securities and Exchange Commission
(the SEC) to promulgate rules and regulations implementing the new
legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced
its first series of proposed rules coming out of the Dodd-Frank
Act. The effect of the proposed rules and any additional
regulations on our business is currently uncertain. Of particular concern, the Dodd-Frank Act
does not explicitly exempt end users (such as us) from the requirements to post
margin in connection with hedging activities. While several senators
have indicated that it was not the intent of the Dodd-Frank Act to require
margin from end users, the exemption is not explicit in the Dodd-Frank
Act. Final rules on major
provisions in the legislation, such as new margin requirements, will be
established through rulemakings and will not take effect until 12 months after
the date of enactment. Although we
cannot predict the ultimate outcome of these rulemakings, new regulations in
this area may result in increased costs and cash collateral requirements for
the types of derivative instruments we use to hedge and otherwise manage our
financial risks related to volatility in oil, gas, and NGL commodity prices.
Hedging is an important part of our
financial risk management program. We
have a Board-approved financial risk management policy governing our hedging
practices. The amount of production we
hedge is driven by the amount of debt on our consolidated balance sheet and the
level of capital commitments and long-term obligations we have in place. In the case of a significant acquisition of
producing properties, we will consider hedging a portion of the acquired
production in order to protect the economics assumed in the acquisition. With the hedges we have in place, we believe
we have established a base cash flow stream for our future operations. Our use of collars for a portion of the
hedges allows us to participate in upward movements in oil and gas prices while
also setting a price floor for a portion of our production. Please see Note 10 Derivative Financial
Instruments of Part I, Item 1 of this report for additional
information regarding our oil and gas hedges, and see the caption,
Summary of Oil and Gas Production Hedges in Place,
later in
this section.
We attempt to qualify our oil and
gas derivative instruments as cash flow hedges for accounting purposes.
Changes in the value of our hedge positions are primarily reflected in our
consolidated balance sheets. A portion of the change in the value of our
hedge positions is recognized in our consolidated statements of operations when
hedges are partially ineffective at offsetting the fluctuations in cash flow
due to changes in the spot price for oil, natural gas, and NGLs. We
recognized $5.7 million in non-cash unrealized derivative loss in the
third quarter of 2010. The value of our hedge portfolio stayed relatively
static from June 30, 2010, through September 30, 2010. Our hedge position was $13.7 million net
asset at the end of the second quarter of 2010 compare with a $6.5 million net
asset at the end of the third quarter of 2010.
Corresponding changes are reflected in accumulated other comprehensive
income on the consolidated balance sheets and unrealized derivative (gain) loss
on the statement of operations.
Third Quarter 2010 Highlights
Operational activities.
During
the third quarter, we had between ten and twelve operated drilling rigs running
company-wide. The thrust of our operated
drilling activities this year has been focused on oil and NGL-rich gas programs
and selected projects of potential strategic importance to us. Additionally, our operating partners have
increased their levels of activity in oil and NGL-rich gas plays.
In the Eagle Ford shale in South
Texas, we continued to operate two drilling rigs on our acreage during the
third quarter. Our focus was on drilling
in areas with higher BTU gas content and higher
27
Table of Contents
condensate yields. We have continued to test different ways to
complete these wells with the objective of optimizing our future development
potential. We have been encouraged with
the results in the operated portion of the play and has been working to
increase the pace of development on our acreage. Securing infrastructure to
transport and process production from the Eagle Ford has been an issue we have
worked to address over the last year, particularly in recent months. During the third quarter we entered into a
gas services agreement whereby we committed a significant amount of production
from the Eagle Ford to a ten-year transportation and processing arrangement
beginning in 2011. This agreement has
shortfall penalties in the event we are unable to deliver the committed volumes
of gas. We have also recently committed
to two new-build drilling rigs and have extended the contracts on two
additional rigs to support our activity levels for the next several years. We continue to explore other arrangements to
address the required drilling, completion, and infrastructure necessary to
accelerate this program. Please refer to
Note 6 Commitments and Contingencies under Part I, Item 1 of this
report for additional discussion concerning our new agreements. On our outside-operated acreage in the Eagle
Ford, our operating partner had six rigs running at quarter-end, which was
consistent with the rig count at the end of the second quarter. This outside-operated acreage has limited
infrastructure to support the development of the play. As a result we plan to participate in the
construction of infrastructure with our partner. The increase in partner-operated rigs and the
infrastructure build-out have resulted in higher capital expenditures in this
program than we initially planned for at the beginning of the year.
We operated an average of two
drilling rigs in the Williston Basin during the third quarter of the year, both
of which were focused on Bakken and Three Forks drilling. Our results in this program continue to meet
or exceed our expectations. Elsewhere in
the Rocky Mountain region, we began drilling our second operated horizontal
well targeting the Niobrara formation in southeastern Wyoming. Interest in the Niobrara formation increased
significantly during the first nine months of 2010 based on positive field
reports coming out of the play. Our
early results from this exploratory program have been encouraging.
In our Mid-Continent region, we
operated an average of two drilling rigs in our Granite Wash program in western
Oklahoma. Our acreage position is held
by production and we believe the potential from this emerging program could be
significant. We also operated a rig in
the Woodford shale in the Arkoma Basin during the third quarter, which focused
primarily on drilling sections of our acreage with richer natural gas.
The Permian region ran two operated
rigs in the third quarter, focusing on Wolfberry tight oil targets. In our operated Haynesville shale program, we
had two drilling rigs operating in the play for most of the quarter and we are
currently awaiting the completion of several wells.
Marketing of non-core
properties.
In the third quarter of 2010, we began marketing two divestiture
packages that include non-core properties in our Rocky Mountain, Mid-Continent,
and Permian regions. The non-core
properties being marketed also include all of our Marcellus shale assets in North
Central Pennsylvania. Please refer to
Note 3 Divestitures and Assets Held for Sale, in Part I, Item 1 of
this report for additional information.
Equity Compensation.
On
July 1, 2010, we granted awards of performance shares and restricted stock
units pursuant to our long term incentive program to our various employees
eligible to participate in the LTIP. The
fair value associated with this grant was $25.4 million. Please refer to Note 7 Compensation Plans
within Part I, Item 1 of this report for additional discussion.
Financial and production
results.
We
recorded net income for the quarter ended September 30, 2010, of
$15.5 million or $0.24 per diluted share compared to third quarter 2009 results
of a net loss of $4.4 million or $(0.07) per diluted share.
28
Table of Contents
The table below details the regional
breakdown of our third quarter 2010 production:
|
|
Mid-
Continent
|
|
ArkLaTex
|
|
South
Texas &
Gulf
Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
|
Third
Quarter 2010 Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl)
|
|
56.1
|
|
|
16.3
|
|
|
281.3
|
|
|
417.2
|
|
|
818.0
|
|
|
1,588.9
|
|
|
Gas
(MMcf)
|
|
8,177.3
|
|
|
3,131.5
|
|
|
4,282.2
|
|
|
1,099.5
|
|
|
1,230.7
|
|
|
17,921.2
|
|
|
Equivalent
(MMCFE)
|
|
8,514.2
|
|
|
3,229.0
|
|
|
5,970.0
|
|
|
3,602.7
|
|
|
6,138.9
|
|
|
27,454.8
|
|
|
Avg.
Daily Equivalents (MMCFE/d)
|
|
92.5
|
|
|
35.1
|
|
|
64.9
|
|
|
39.2
|
|
|
66.7
|
|
|
298.4
|
|
|
Relative
percentage
|
|
31%
|
|
|
12%
|
|
|
22%
|
|
|
13%
|
|
|
22%
|
|
|
100%
|
|
|
(1) Totals may not add due to rounding
For the third quarter of
2010 our production growth was led by our Eagle Ford shale program. Both our operated and partner-operated
programs targeting the Eagle Ford have contributed more production than originally
budgeted. Please refer to
Comparison of Financial
Results and Trends between the three months ended September 30, 2010, and
2009,
for additional discussion on production.
First Nine Months 2010 Highlights
Legacy
Divestiture.
On February 17, 2010, we closed on a divestiture of
non-core properties in Wyoming to Legacy Reserves Operating LP. Total cash received, before commission costs
and Net Profits Plan payments, was $125.3 million. The final gain on divestiture activity
related to the divestiture is approximately $65.0 million.
Sequel
Divestiture.
On March 12, 2010, we completed the divestiture of
certain non-strategic properties located in North Dakota to Sequel Energy
Partners, LP, Bakken Energy Partners, LLC, and Three Forks Energy Partners,
LLC. Total cash received, before
commission costs and Net Profits Plan payments, was $129.1 million. The final sale price is subject to normal
post-closing adjustments and is expected to be finalized during the fourth
quarter of 2010. The estimated gain on
divestiture activity related to the divestiture is approximately
$52.9 million and may be impacted by the forthcoming post-closing
adjustments mentioned above.
Production results.
The
table below details the regional breakdown of our first nine months of 2010
production.
|
|
Mid-
Continent
|
|
ArkLaTex
|
|
South
Texas &
Gulf
Coast
|
|
Permian
|
|
Rocky
Mountain
|
|
Total
(1)
|
|
First
nine months of 2010 Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(MBbl)
|
|
163.3
|
|
|
56.4
|
|
|
599.1
|
|
|
1,301.2
|
|
|
2,406.6
|
|
|
4,526.6
|
|
|
Gas
(MMcf)
|
|
24,424.4
|
|
|
9,406.7
|
|
|
10,077.6
|
|
|
3,122.9
|
|
|
4,133.5
|
|
|
51,165.1
|
|
|
Equivalent
(MMCFE)
|
|
25,404.3
|
|
|
9,745.1
|
|
|
13,672.2
|
|
|
10,930.4
|
|
|
18,572.9
|
|
|
78,324.9
|
|
|
Avg.
Daily Equivalents (MMCFE/d)
|
|
93.1
|
|
|
35.7
|
|
|
50.1
|
|
|
40.0
|
|
|
68.0
|
|
|
286.9
|
|
|
Relative
percentage
|
|
32%
|
|
|
12%
|
|
|
18%
|
|
|
14%
|
|
|
24%
|
|
|
100%
|
|
|
(1)
Totals may not add due to rounding
29
Table of Contents
For the
first nine months of 2010 our production has outperformed our expectations due
to stronger than anticipated production results from our South Texas &
Gulf Coast region. Please refer to the
three months discussion under
Financial and production
results
above and
A three-month and
nine-month overview of selected production and financial information, including
trends
and
Comparison of Financial
Results and Trends between the nine months ended September 30, 2010, and
2009,
for additional discussion on production.
Net Profits Plan.
In
2008, the Net Profits Plan was replaced with grants of performance shares and
subsequently in 2009 grants of both performance shares and RSUs. Therefore, the 2007 Net Profits Plan pool was
the last pool established by us. We will
continue to make payments from the existing Net Profits Plan pools and will
continue to make prospective adjustments to the long-term liability as
necessary.
For
the nine months ended September 30, 2010, the change in the value of this
liability resulted in a non-cash benefit of $29.8 million compared with a $14.0
million benefit for the same period in 2009.
Current year payments made or accrued as part of allocating the proceeds
received from divestitures during the first nine months of 2010 have decreased
the estimated liability for the future amounts to be paid to plan
participants. This liability is a
significant management estimate.
Adjustments to the liability are subject to estimation and may change
dramatically from period to period based on assumptions used for production
rates, reserve quantities, commodity pricing, discount rates, tax rates, and
production costs.
Payments made from the Net Profits
Plan have been expensed as compensation costs in the amounts of $18.1 million
and $14.1 million for the nine months ended September 30, 2010, and 2009,
respectively. Additionally, the sales of
oil and gas properties described above contained a number of properties
included in profit pools and resulted in payments under the Net Profits Plan of
$20.8 million during the first nine months of 2010. These cash payments are accounted for as a
reduction of net sale proceeds and impact the gain on divestiture activity in
the accompanying consolidated statements of operations. There were no significant cash payments made
or accrued under the Net Profits Plan as a result of divestitures during the
first nine months of 2009.
The recurring Net Profits Plan cash
payments we make are dependent on actual production, realized prices, and
operating and capital costs associated with the properties in each individual
pool. Actual cash payments will be
inherently different from the estimated liability amounts. More detailed discussion is included in Note
11 Fair Value Measurements in Part I, Item 1 of this report. An increasing percentage of the costs
associated with the payments under the Net Profits Plan are now being allocated
to general and administrative expense rather than exploration expense. This is a function of the normal departure of
employees who previously contributed to our exploration efforts.
The calculation of the estimated
liability for the Net Profits Plan is highly sensitive to our price estimates
and discount rate assumptions. For
example, if we changed the commodity prices in our calculation by five percent,
the liability recorded on the balance sheet at September 30, 2010, would
differ by approximately $11 million.
A one percentage point increase in the discount rate would decrease the
liability by approximately $6 million whereas a one percentage point decrease
in the discount rate would increase the liability by $7 million. We frequently re-evaluate the assumptions
used in our calculations and consider the possible impacts stemming from the
current market environment including current and future oil and gas prices,
discount rates, and overall market conditions for oil and gas properties.
Outlook for the Remainder of 2010 and for
2011
Our development program entering
2010 was focused on the drilling of oil and rich-gas projects. This decision has been reinforced as natural
gas prices have been under downward pressure most of this year. We continue to shift capital away from
natural gas drilling wherever possible, except for activities necessary to
satisfy leasehold commitments or to test emerging resource plays. We continue to expect that our 2010 capital
investment will be near $871 million, which is up from the $725 million capital
investment budget that was set at the beginning of the year. We increased
our forecast for capital expenditures due to
30
Table of Contents
our decision to accelerate activity
in plays where we have been successful this year. Additionally, inflation
in the cost to drill and complete wells has put upward pressure on our capital
budget. We currently anticipate
increasing our level of capital investment to roughly $1.0 billion in 2011 with
the majority targeted toward rich-gas projects in the Eagle Ford as well as oil
projects in the Williston Basin.
We will continue to operate two rigs
on our Eagle Ford acreage during the fourth quarter of 2010. To support
our anticipated increase in operated activity in the Eagle Ford we have
committed, or are in the process of committing, to additional drilling rigs,
completion services, and infrastructure.
We recently have extended the drilling contracts of two rigs operating
for us in the Eagle Ford and have contracted for an additional two drilling
rigs, which are scheduled to be available in mid-2011. Subsequent to quarter end, we entered into an
agreement which secures a portion of the completion services needed to support
the aforementioned drilling fleet. We continue to negotiate with other
completion providers to secure additional services. In the Williston
Basin we recently
successfully
completed the simultaneous fracturing of three wells in the Williston Basin
that we believe will help us understand how to optimize the development of our
Williston assets. We are also completing
our second Niobrara well and monitoring the performance of our first well in
this program. We will continue to
operate two rigs in our horizontal Granite Wash program with four wells planned
in the fourth quarter. We expect to operate two drilling rigs in the East
Texas portion of our Haynesville shale position for the remainder of
2010. Our activity level in the Haynesville has not changed significantly
from what we planned at the beginning of the year, although our amount of
capital investment in this play was substantially reduced as a result of the
Carry and Earning Agreement we entered into in the second quarter of 2010.
We
have begun to market for sale several of our non-core oil and gas properties,
including all of our Marcellus shale assets.
We expect that proceeds from these divestitures will help fund a portion
of our anticipated 2011 capital budget.
Please refer to
Sources of Cash
and
Current Credit Facility
under the
Overview of Liquidity and Capital Resources
section for
additional discussion regarding how we anticipate to generate cash flows to
fund our 2011 capital program.
31
Table of Contents
Financial Results of Operations and
Additional Comparative Data
The table below provides information
regarding selected production and financial information for the quarter ended September 30,
2010, and the immediately preceding three quarters. Additional details of per MCFE costs are
presented later in this section.
|
|
For the Three Months Ended
|
|
|
|
September 30,
2010
|
|
June 30,
2010
|
|
March 31,
2010
|
|
December 31,
2009
|
|
|
|
(In millions, except production sales data)
|
|
Production
(BCFE)
|
|
|
27.5
|
|
|
|
25.2
|
|
|
|
25.7
|
|
|
|
26.1
|
|
|
Oil and
gas production revenue, excluding the effects of hedging
|
|
|
$
|
197.4
|
|
|
|
$
|
175.9
|
|
|
|
$
|
212.9
|
|
|
|
$
|
187.6
|
|
|
Realized
oil and gas hedge gain
|
|
|
$
|
8.8
|
|
|
|
$
|
9.3
|
|
|
|
$
|
2.6
|
|
|
|
$
|
13.4
|
|
|
Gain on
divestiture activity
|
|
|
$
|
4.2
|
|
|
|
$
|
7.0
|
|
|
|
$
|
121.0
|
|
|
|
$
|
22.1
|
|
|
Lease
operating expense
|
|
|
$
|
29.0
|
|
|
|
$
|
29.0
|
|
|
|
$
|
30.0
|
|
|
|
$
|
34.3
|
|
|
Transportation
costs
|
|
|
$
|
4.9
|
|
|
|
$
|
5.1
|
|
|
|
$
|
4.1
|
|
|
|
$
|
5.2
|
|
|
Production
taxes
|
|
|
$
|
10.7
|
|
|
|
$
|
11.1
|
|
|
|
$
|
14.2
|
|
|
|
$
|
13.3
|
|
|
DD&A
|
|
|
$
|
83.8
|
|
|
|
$
|
79.8
|
|
|
|
$
|
77.8
|
|
|
|
$
|
75.1
|
|
|
Exploration
|
|
|
$
|
14.4
|
|
|
|
$
|
14.5
|
|
|
|
$
|
13.9
|
|
|
|
$
|
13.4
|
|
|
Impairment
of proved properties
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
$
|
21.6
|
|
|
Abandonment
and impairment of unproved properties
|
|
|
$
|
1.7
|
|
|
|
$
|
2.4
|
|
|
|
$
|
0.9
|
|
|
|
$
|
25.2
|
|
|
General
and administrative
|
|
|
$
|
26.2
|
|
|
|
$
|
25.4
|
|
|
|
$
|
23.5
|
|
|
|
$
|
20.7
|
|
|
Change
in Net Profits Plan liability
|
|
|
$
|
4.1
|
|
|
|
$
|
(6.6
|
)
|
|
|
$
|
(27.3
|
)
|
|
|
$
|
7.0
|
|
|
Unrealized
derivative (gain) loss
|
|
|
$
|
5.7
|
|
|
|
$
|
(2.1
|
)
|
|
|
$
|
(7.7
|
)
|
|
|
$
|
3.2
|
|
|
Net
income
|
|
|
$
|
15.5
|
|
|
|
$
|
18.1
|
|
|
|
$
|
126.2
|
|
|
|
$
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
change from previous quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
(BCFE)
|
|
|
9%
|
|
|
|
(2)%
|
|
|
|
(2)%
|
|
|
|
(1)%
|
|
|
Oil and
gas production revenue, excluding the effects of hedging
|
|
|
12%
|
|
|
|
(17)%
|
|
|
|
13%
|
|
|
|
23%
|
|
|
Realized
oil and gas hedge gain
|
|
|
(5)%
|
|
|
|
258%
|
|
|
|
(81)%
|
|
|
|
(53)%
|
|
|
Gain on
divestiture activity
|
|
|
(40)%
|
|
|
|
(94)%
|
|
|
|
448%
|
|
|
|
(296)%
|
|
|
Lease
operating expense
|
|
|
%
|
|
|
|
(3)%
|
|
|
|
(13)%
|
|
|
|
%
|
|
|
Transportation
costs
|
|
|
(4)%
|
|
|
|
24%
|
|
|
|
(21)%
|
|
|
|
(2)%
|
|
|
Production
taxes
|
|
|
(4)%
|
|
|
|
(22)%
|
|
|
|
7%
|
|
|
|
48%
|
|
|
DD&A
|
|
|
5%
|
|
|
|
3%
|
|
|
|
4%
|
|
|
|
12%
|
|
|
Exploration
|
|
|
(1)%
|
|
|
|
4%
|
|
|
|
4%
|
|
|
|
(15)%
|
|
|
Impairment
of proved properties
|
|
|
%
|
|
|
|
%
|
|
|
|
(100)%
|
|
|
|
N/M
|
|
|
Abandonment
and impairment of unproved properties
|
|
|
(29)%
|
|
|
|
167%
|
|
|
|
(96)%
|
|
|
|
425%
|
|
|
General
and administrative
|
|
|
3%
|
|
|
|
8%
|
|
|
|
14%
|
|
|
|
%
|
|
|
Change
in Net Profits Plan liability
|
|
|
(162)%
|
|
|
|
(76)%
|
|
|
|
(490)%
|
|
|
|
3%
|
|
|
Unrealized
derivative (gain) loss
|
|
|
(371)%
|
|
|
|
(73)%
|
|
|
|
(341)%
|
|
|
|
(22)%
|
|
|
Net income
|
|
|
(14)%
|
|
|
|
(86)%
|
|
|
|
12,520%
|
|
|
|
(123)%
|
|
|
32
Table
of Contents
A three-month and nine-month overview of
selected production and financial information, including trends:
Selected Operations Data (In thousands, except sales price, volume, and
per MCFE amounts):
|
|
For the Three Months
Ended September 30,
|
|
Percent
Change
Between
|
|
For the Nine Months
Ended September 30,
|
|
Percent
Change
Between
|
|
|
2010
|
|
2009
|
|
Periods
|
|
2010
|
|
2009
|
|
Periods
|
Net production volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
1,589
|
|
|
|
1,528
|
|
|
|
4
%
|
|
|
4,527
|
|
|
|
4,816
|
|
|
|
(6
)
%
|
Natural gas (MMcf)
|
|
|
17,921
|
|
|
|
17,211
|
|
|
|
4
%
|
|
|
51,165
|
|
|
|
54,055
|
|
|
|
(5
)
%
|
MMCFE (6:1)
|
|
|
27,455
|
|
|
|
26,377
|
|
|
|
4
%
|
|
|
78,325
|
|
|
|
82,951
|
|
|
|
(6
)
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average daily production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl per day)
|
|
|
17,271
|
|
|
|
16,606
|
|
|
|
4
%
|
|
|
16,581
|
|
|
|
17,640
|
|
|
|
(6
)
%
|
Natural gas (Mcf per day)
|
|
|
194,796
|
|
|
|
187,076
|
|
|
|
4
%
|
|
|
187,418
|
|
|
|
198,005
|
|
|
|
(5
)
%
|
MCFE per day (6:1)
|
|
|
298,422
|
|
|
|
286,711
|
|
|
|
4
%
|
|
|
286,904
|
|
|
|
303,848
|
|
|
|
(6
)
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas production
revenue
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil production revenue
|
|
|
$
|
102,130
|
|
|
|
$
|
95,715
|
|
|
|
7
%
|
|
|
$
|
296,313
|
|
|
|
$
|
261,614
|
|
|
|
13
%
|
Gas production revenue
|
|
|
104,071
|
|
|
|
85,267
|
|
|
|
22
%
|
|
|
310,586
|
|
|
|
293,963
|
|
|
|
6
%
|
Total
|
|
|
$
|
206,201
|
|
|
|
$
|
180,982
|
|
|
|
14
%
|
|
|
$
|
606,899
|
|
|
|
$
|
555,577
|
|
|
|
9
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & gas production
expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
$
|
29,046
|
|
|
|
$
|
34,266
|
|
|
|
(15
)%
|
|
|
$
|
88,031
|
|
|
|
$
|
111,117
|
|
|
|
(21
)%
|
Transportation costs
|
|
|
4,877
|
|
|
|
5,393
|
|
|
|
(10
)
%
|
|
|
14,069
|
|
|
|
15,420
|
|
|
|
(9
)
%
|
Production taxes
|
|
|
10,683
|
|
|
|
8,975
|
|
|
|
19
%
|
|
|
36,014
|
|
|
|
27,391
|
|
|
|
31
%
|
Total
|
|
|
$
|
44,606
|
|
|
|
$
|
48,634
|
|
|
|
(8
)%
|
|
|
$
|
138,114
|
|
|
|
$
|
153,928
|
|
|
|
(10
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net realized sales price
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
|
$
|
64.28
|
|
|
|
$
|
62.65
|
|
|
|
3
%
|
|
|
$
|
65.46
|
|
|
|
$
|
54.32
|
|
|
|
21
%
|
Natural gas (per Mcf)
|
|
|
$
|
5.81
|
|
|
|
$
|
4.95
|
|
|
|
17
%
|
|
|
$
|
6.07
|
|
|
|
$
|
5.44
|
|
|
|
12
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per MCFE Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average net realized price
(1)
|
|
|
$
|
7.51
|
|
|
|
$
|
6.86
|
|
|
|
9
%
|
|
|
$
|
7.75
|
|
|
|
$
|
6.70
|
|
|
|
16
%
|
Lease operating expenses
|
|
|
(1.06
|
)
|
|
|
(1.30
|
)
|
|
|
(18
)
%
|
|
|
(1.12
|
)
|
|
|
(1.34
|
)
|
|
|
(16
)
%
|
Transportation costs
|
|
|
(0.18
|
)
|
|
|
(0.20
|
)
|
|
|
(10
)
%
|
|
|
(0.18
|
)
|
|
|
(0.19
|
)
|
|
|
(5
)
%
|
Production taxes
|
|
|
(0.39
|
)
|
|
|
(0.34
|
)
|
|
|
15
%
|
|
|
(0.46
|
)
|
|
|
(0.33
|
)
|
|
|
39
%
|
General and administrative
|
|
|
(0.96
|
)
|
|
|
(0.79
|
)
|
|
|
22
%
|
|
|
(0.96
|
)
|
|
|
(0.67
|
)
|
|
|
43
%
|
Operating profit
|
|
|
$
|
4.92
|
|
|
|
$
|
4.23
|
|
|
|
16
%
|
|
|
$
|
5.03
|
|
|
|
$
|
4.17
|
|
|
|
21
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation,
amortization, and
asset
retirement obligation liability
accretion
|
|
|
$
|
3.05
|
|
|
|
$
|
2.54
|
|
|
|
20
%
|
|
|
$
|
3.08
|
|
|
|
$
|
2.76
|
|
|
|
12
%
|
(1) Includes the effects of hedging activities
We present per MCFE information
because we use this information to evaluate our performance relative to our
peers and to identify and measure trends we believe require analysis. Average daily production for the first nine
months of 2010 decreased six percent to 286.9 MMCFE compared with 303.8 MMCFE
for the same period in 2009, driven by reduced capital spending in 2009 and
recent divestitures. Adjusting for
divestitures, our average daily production from retained properties for the
first nine months of 2010 increased five percent to 283.0 MMCFE compared with
270.2 MMCFE for the same period in 2009.
Changes in production volumes, oil
and gas production revenues, and costs reflect the cyclical and highly volatile
nature of our industry. Our average net
realized price for the three months and nine months
33
Table of Contents
ended September 30, 2010, was
$7.51 per MCFE and $7.75 per MCFE, respectively, compared with $6.86 per MCFE
and $6.70 per MCFE for the respective periods of 2009. The increase in our equivalent realized price
for production corresponds with stronger commodity prices in the first nine
months of 2010 when compared with the same period of 2009.
Our LOE for the three months and
nine months ended September 30, 2010, decreased $0.24 per MCFE to $1.06
per MCFE and decreased $0.22 per MCFE to $1.12 per MCFE, respectively, compared
to the respective periods in 2009. The
divestiture of non-strategic properties with meaningfully higher operating
costs is the primary reason for the decline in LOE in the comparisons
above. We believe that the steady
increase in industry activity that we have experienced will put upward pressure
on lease operating costs that we have not experienced the last few
quarters. Production taxes for the three
months and nine months ended September 30, 2010, increased $0.05 per MCFE
to $0.39 and increased $0.13 per MCFE to $0.46 per MCFE, respectively, compared
to the respective periods in 2009.
Production taxes are highly correlated to pre-hedge oil and gas
revenues, and stronger commodity prices have impacted results for this expense
item. Transportation costs for the three
months and nine months ended September 30, 2010, decreased $0.02 per
MCFE to $0.18 per MCFE and decreased $0.01 per MCFE to $0.18 per MCFE, from the
corresponding periods in 2009. In late
2009 we divested of non-strategic properties within our Rocky Mountain region
that had higher transportation costs. Our
general and administrative expense for both the three months and nine months
ended September 30, 2010, was $0.96 per MCFE, compared with $0.79 per
MCFE and $0.67 per MCFE for the comparable respective periods of 2009. A portion of our general and administrative
expense is linked to our profitability and cash flow, which are driven in large
part by the realized commodity prices we receive for our production. The Net Profits Plan and a portion of our
current short-term incentive compensation are tied to net revenues and
therefore are subject to variability.
Our operating profit for the three months and nine months ended September 30,
2010, was $4.92 per MCFE and $5.03 per MCFE, respectively, compared with $4.23
per MCFE and $4.17 per MCFE for the comparable periods of 2009, which was an
increase of $0.69, or 16 percent, and $0.86, or 21 percent, respectively.
Our depletion, depreciation, and
amortization, including asset retirement obligation accretion expense, for the
three months and nine months ended September 30, 2010, was $3.05 per MCFE
and $3.08 per MCFE, respectively, compared with $2.54 per MCFE and $2.76 per
MCFE for the comparable respective periods of 2009. Depreciation, depletion, and amortization was
impacted by our divestiture of lower cost basis properties in the first quarter
of 2010. Additionally, we have been
impacted by higher DD&A rates in the Eagle Ford and Haynesville
shales. We are incurring capital for
research wells and infrastructure that will benefit future development in these
plays but are currently limited in the amount of reserves that we can record to
carry the costs, which results in higher per unit DD&A costs early in the
lives of these plays. Our DD&A rate
can also fluctuate as a result of impairments, divestitures, and changes in the
mix of our production and the underlying proved reserve volumes. Additionally, the accounting treatment for
assets that are classified as assets held for sale can also impact our DD&A
rate since properties held for sale are no longer depleted.
Please refer to
Comparison of Financial Results and Trends between the three months
ended September 30, 2010, and 2009,
and
Comparison
of Financial Results and Trends between the nine months ended September 30,
2010 and 2009
for additional discussion on oil and gas production
expense, DD&A, and general and administrative expense.
34
Table
of Contents
We present the following table as a
summary of information relating to key indicators of financial condition and
operating performance that we believe are important.
Financial Information (In thousands, except
per share amounts):
|
|
September 30, 2010
|
|
December 31, 2009
|
|
Percent
Change
Between
Periods
|
|
Working
capital deficit
|
|
$
|
172,538
|
|
$
|
87,625
|
|
97
%
|
|
Long-term
debt
|
|
$
|
275,404
|
|
$
|
454,902
|
|
(39)%
|
|
Stockholders
equity
|
|
$
|
1,202,451
|
|
$
|
973,570
|
|
24
%
|
|
|
|
For the Three Months
Ended September 30,
|
|
Percent
Change
Between
|
|
For the Nine Months
Ended September 30,
|
|
Percent
Change
Between
|
|
|
|
2010
|
|
2009
|
|
Periods
|
|
2010
|
|
2009
|
|
Periods
|
|
Basic
net income (loss) per common share
|
|
$
|
0.25
|
|
$
|
(0.07
|
)
|
|
(457
|
)%
|
|
$
|
2.54
|
|
$
|
(1.61
|
)
|
|
(258
|
)%
|
|
Diluted
net income (loss) per common share
|
|
$
|
0.24
|
|
$
|
(0.07
|
)
|
|
(443
|
)%
|
|
$
|
2.47
|
|
$
|
(1.61
|
)
|
|
(253
|
)%
|
|
Basic
weighted-average shares outstanding
|
|
63,031
|
|
62,505
|
|
|
1
|
%
|
|
62,914
|
|
62,420
|
|
|
1
|
%
|
|
Diluted
weighted-average shares outstanding
|
|
64,794
|
|
62,505
|
|
|
4
|
%
|
|
64,599
|
|
62,420
|
|
|
3
|
%
|
|
We account for our 3.50% Senior
Convertible Notes under the treasury stock method. There is no impact on the diluted share
calculation for the periods presented since our average stock price for the
relevant reporting periods has not exceeded the conversion price. The 3.50% Senior Convertible Notes were
issued April 4, 2007, and have not been dilutive for any reporting period
since their issuance. We have in-the-money
stock options, unvested RSUs, and contingent PSAs that are potentially dilutive
securities. Both basic and diluted
earnings per share are presented in the table above. A detailed explanation is presented in Note 5
Earnings per Share in Part I, Item 1 of this report.
Basic and diluted weighted-average
common shares outstanding used in our September 30, 2010, and 2009,
earnings per share calculations reflect increases in outstanding shares related
to stock option exercises, ESPP shares issued, and the settlement of vested
RSUs. We issued 163,348 and 33,014
shares of common stock during the nine-month periods ended September 30,
2010, and 2009, respectively, as a result of stock option exercises. The number of RSUs that vested and settled
during the first nine months of 2010 and 2009 were 57,687 and 90,486,
respectively.
35
Table of Contents
Additional Comparative Data in Tabular
Form:
|
|
Change Between the
Three Months Ended
September 30, 2010,
and 2009
|
|
Change Between the
Nine Months Ended
September 30, 2010,
and 2009
|
|
Increase
in oil and gas production revenues, net of hedging (In thousands)
|
|
$
|
25,219
|
|
|
$
|
51,322
|
|
|
|
|
|
|
|
|
|
|
Components of revenue increases (decreases):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
Realized
price change per Bbl, including the effects of hedging
|
|
$
|
1.63
|
|
|
$
|
11.14
|
|
|
Realized
price percentage change
|
|
3%
|
|
|
21%
|
|
|
Production
change (MBbl)
|
|
61
|
|
|
(289)
|
|
|
Production
percentage change
|
|
4%
|
|
|
(6)%
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
|
|
|
|
|
Realized
price change per Mcf, including the effects of hedging
|
|
$
|
0.86
|
|
|
$
|
0.63
|
|
|
Realized
price percentage change
|
|
17%
|
|
|
12%
|
|
|
Production
change (MMcf)
|
|
710
|
|
|
(2,890)
|
|
|
Production
percentage change
|
|
4%
|
|
|
(5)%
|
|
|
Production mix as a percentage of total oil
and gas revenue, including impact of hedging, and production:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months Ended
September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
Oil
|
|
50%
|
|
53%
|
|
49%
|
|
47%
|
|
Natural
gas
|
|
50%
|
|
47%
|
|
51%
|
|
53%
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
Oil
|
|
35%
|
|
35%
|
|
35%
|
|
35%
|
|
Natural
gas
|
|
65%
|
|
65%
|
|
65%
|
|
65%
|
|
36
Table of Contents
Information regarding the effects of oil,
natural gas, and NGL hedging activity:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
Oil
Hedging
|
|
|
|
|
|
|
|
|
|
Percentage
of oil production hedged
|
|
46%
|
|
|
59%
|
|
|
51%
|
|
|
51%
|
|
|
Oil
volumes hedged (MBbl)
|
|
738
|
|
|
894
|
|
|
2,310
|
|
|
2,463
|
|
|
Increase
(decrease) in oil revenue
|
|
$
|
(6.8) million
|
|
|
$
|
1.1 million
|
|
|
$
|
(23.7) million
|
|
|
$
|
21.6 million
|
|
|
Average
realized oil price per Bbl before hedging
|
|
$
|
68.56
|
|
|
$
|
61.93
|
|
|
$
|
70.70
|
|
|
$
|
49.82
|
|
|
Average
realized oil price per Bbl after hedging
|
|
$
|
64.28
|
|
|
$
|
62.65
|
|
|
$
|
65.46
|
|
|
$
|
54.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Hedging
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
of gas production hedged (includes NGLs)
|
|
41%
|
|
|
43%
|
|
|
46%
|
|
|
47%
|
|
|
Natural
gas volumes hedged (in MMBtu, includes NGLs)
|
|
8.3 million
|
|
|
7.8 million
|
|
|
26.5 million
|
|
|
26.8 million
|
|
|
Increase
in gas revenue (includes effects of NGL hedges)
|
|
$
|
15.6 million
|
|
|
$
|
27.2 million
|
|
|
$
|
44.5 million
|
|
|
$
|
105.6 million
|
|
|
Average
realized gas price per Mcf before hedging (includes NGLs)
|
|
$
|
4.93
|
|
|
$
|
3.37
|
|
|
$
|
5.20
|
|
|
$
|
3.49
|
|
|
Average
realized gas price per Mcf after hedging (includes NGLs)
|
|
$
|
5.81
|
|
|
$
|
4.95
|
|
|
$
|
6.07
|
|
|
$
|
5.44
|
|
|
37
Table of Contents
Information regarding the components of
exploration expense:
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In millions)
|
|
Summary
of Exploration Expense
|
|
|
|
|
|
|
|
|
|
Geological
and geophysical expenses
|
|
$
|
4.9
|
|
|
$
|
6.2
|
|
|
$
|
13.7
|
|
|
$
|
16.9
|
|
Exploratory
dry hole expense
|
|
|
|
|
0.1
|
|
|
0.3
|
|
|
4.8
|
|
Overhead
and other expenses
|
|
9.5
|
|
|
9.4
|
|
|
28.8
|
|
|
27.1
|
|
Total
|
|
$
|
14.4
|
|
|
$
|
15.7
|
|
|
$
|
42.8
|
|
|
$
|
48.8
|
|
Comparison of Financial
Results and Trends between the three months ended September 30, 2010, and
2009
Oil and gas production
revenue.
Average
daily production increased four percent to 298.4 MMCFE for the quarter ended September 30,
2010, compared with 286.7 MMCFE for the quarter ended
September 30, 2009. The
following table presents the regional changes in our production and oil and gas
revenues and costs between the two quarters.
|
|
Average Net Daily
Production
Added (Decreased)
|
|
Pre-Hedge
Oil and Gas
Revenue Added
(Decreased)
|
|
Production Costs
Increase
(Decrease)
|
|
|
|
(MMCFE/d)
|
|
(In millions)
|
|
(In millions)
|
|
Mid-Continent
|
|
(4.0
|
)
|
|
8.6
|
|
1.0
|
|
ArkLaTex
|
|
(4.0
|
)
|
|
1.4
|
|
(1.9)
|
|
South
Texas & Gulf Coast
|
|
42.7
|
|
|
33.1
|
|
3.5
|
|
Permian
|
|
1.1
|
|
|
5.0
|
|
2.5
|
|
Rocky
Mountain
|
|
(24.1
|
)
|
|
(3.4)
|
|
(9.1)
|
|
Total
|
|
11.7
|
|
|
44.7
|
|
(4.0)
|
|
The largest regional production
decrease occurred in the Rocky Mountain region as a result of our divestitures
of non-strategic oil and gas assets that occurred in the fourth quarter of 2009
and first quarter of 2010. The largest
production growth occurred in the South Texas & Gulf Coast region as a
result of production from drilling activity in our Eagle Ford shale
program. We anticipate sequential
increases in production for the remainder of 2010.
The following table summarizes the
average realized prices we received in the third quarters of 2010 and 2009,
before the effects of hedging. Prices
for oil and gas increased between the two periods.
|
|
For the Three Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Realized
oil price ($/Bbl)
|
|
$
|
68.56
|
|
|
$
|
61.93
|
|
|
Realized
gas price ($/Mcf)
|
|
$
|
4.93
|
|
|
$
|
3.37
|
|
|
Realized
equivalent price ($/MCFE)
|
|
$
|
7.19
|
|
|
$
|
5.79
|
|
|
The 24 percent increase in average
realized prices per MCFE coupled with a four percent increase in production
volumes between periods resulted in higher oil and gas revenue. We expect our realized price to trend with
commodity prices.
38
Table of
Contents
Realized oil and gas hedge
gain.
We
recorded a net realized hedge gain of $8.8 million for the three-month period
ended September 30, 2010, related to settlements on oil and gas hedges,
compared with $28.3 million gain for the same period in 2009, as a result of an
increase in commodity prices on a quarter-to-quarter basis. Our realized oil and gas hedge gains and losses
are a function of commodity prices and the price at which production was
hedged.
Gain (loss) on divestiture
activity.
We had a $4.2 million net gain on divestiture activity for
the quarter ended September 30, 2010, related to a divestiture of non-core
oil and gas properties located in our Rocky Mountain region. We recorded an $11.3 million net loss on
divestiture activity for the comparable period of 2009, resulting primarily
from the accounting treatment of certain assets that were classified as held
for sale and were then subsequently reclassified as held and used. We are currently marketing other
non-strategic oil & gas property packages, and we expect to continue
to evaluate potential divestitures of non-strategic properties in future
periods.
Marketed gas system revenue and
expense.
Marketed
gas system revenue increased $1.9 million to $15.8 million for the
quarter ended September 30, 2010, compared with $13.9 million for the
comparable period of 2009. Concurrent
with the increase in marketed gas system revenue, marketed gas system expense
increased $300,000 to $14.7 million for the quarter ended September 30,
2010, compared with $14.4 million for the comparable period of 2009. The net margin has stayed relatively
consistent with historical performance.
We expect that marketed gas system revenue and expense will continue to
coincide with increases and decreases in production and our net realized price
for natural gas.
Oil and gas production
expense.
Total
production costs for the third quarter of 2010 decreased $4.0 million, or eight
percent, to $44.6 million compared with $48.6 million for the same period of
2009. Total oil and gas production costs
per MCFE decreased $0.21 to $1.63 for the third quarter of 2010, compared with
$1.84 for the same period in 2009. This
decrease is comprised of the following:
·
A $0.15 decrease in recurring LOE on a per MCFE basis
reflects the sale of non-core properties in late 2009 and early 2010 of higher
per unit LOE costs that resulted in lower LOE on a per unit basis quarter over
quarter. We expect the various resources
required to service our industry will become more sought after and harder to
secure as a result of an increase in activity.
We expect to see upward pressure on LOE throughout the remainder of the
year.
·
A $0.09 overall decrease in workover LOE on a per MCFE basis
relating primarily to a decrease in workover activity in our Rocky Mountain
region
·
A $0.02 decrease in overall transportation cost on a per
MCFE basis as a result of the divestiture of non-core properties in the Rocky
Mountain region in the fourth quarter of 2009 and first quarter of 2010 that
had higher transportation costs associated with them
·
A $0.05 per MCFE increase in production taxes is due to the
increase in pre-hedge oil and gas revenues between periods, particularly in the
South Texas & Gulf Coast region.
Depletion, depreciation,
amortization, and asset retirement obligation liability accretion.
DD&A
increased $16.8 million, or 25 percent, to $83.8 million for the three-month
period ended September 30, 2010, compared with $67.0 million for
the same period in 2009. The current
years DD&A per MCFE was higher when compared with the same period in 2009
due to the impact of our divestiture of lower cost basis properties in the
first quarter of 2010 and production related to properties developed in a
higher cost environment becoming a larger percentage of our production
mix. Additionally, we have been impacted
by higher DD&A rates in the Eagle Ford and Haynesville shales. We are incurring capital for research wells
and infrastructure that will benefit future development in these plays but are
currently limited during the early stages of these plays in the amount of
reserves that we can book to carry the costs, which results in higher per unit
DD&A costs early in the lives of these plays. Any future proved property
39
Table of Contents
impairments, divestitures, and
changes in underlying proved reserve volumes will impact our DD&A expense.
Exploration.
Exploration
expense decreased $1.3 million, or eight percent, to $14.4 million for the
three-month period ended September 30, 2010, compared with $15.7 million
for the same period in 2009. Geological
and geophysical expense decreased $1.3 million due to a decrease in the amount
spent on seismic related to our current and emerging resource play
projects. We continue to test our
current resource plays and expect to maintain a modest exploratory program for
new assets in future periods. Any
exploratory well incapable of producing oil or natural gas in commercial
quantities will be deemed an exploratory dry hole, which will impact the amount
of exploration expense we record.
Abandonment and impairment of
unproved properties.
Abandonment and impairment of unproved properties decreased
64 percent to $1.7 million for the three months ended
September 30, 2010, compared with $4.8 million for the comparable
period in 2009. Fewer dollars were
available in 2009 to extend lease or drill test wells as a result of the
economic conditions early in the year.
We generally expect abandonments and impairments of unproved properties
to be more likely to occur in periods of low commodity prices, since fewer
dollars will be available for exploratory and development efforts.
General and administrative.
General
and administrative expense increased $5.4 million or 26 percent to $26.2
million for the three months ended September 30, 2010, compared with $20.8
million for the comparable period of 2009.
On a per unit basis, G&A expense increased $0.17 to $0.96 per MCFE
for the third quarter of 2010 compared to $0.79 per MCFE for the same
three-month period in 2009.
General and administrative expense
increased due to a $3.4 million increase in base compensation, cash bonus, and
long-term incentive compensation expense for the three months ended September 30,
2010, compared with the same period in 2009.
The increase in cash bonus and long-term incentive compensation expense
reflects compensation expense associated with the PSAs granted in the third
quarter of 2010, as well as the improvement in our performance and the
anticipated achievement of various performance criteria, established by our
Compensation Committee.
Additionally, G&A expense
increased as a result of a $2.9 million decrease in COPAS overhead
reimbursements, caused by a decrease in our operated well count resulting from
our recent divestiture efforts, and a $1.3 million decrease in cash payments
accrued under the Net Profits Plan. Net
Profits Plan payments to plan participants were lower in the third quarter as a
result of properties that were in payout in 2009 being divested of during the
first quarter of 2010. We expect
payments made under the Net Profits Plan to trend with commodity prices.
Change in Net Profits Plan
liability.
For the quarter ended September 30, 2010, this non-cash
item was an expense of $4.1 million compared to an expense of $6.8 million for
the same period in 2009. This non-cash
charge is directly related to the change in the estimated value of the
liability over the reporting period. We
broadly expect the change in this liability to trend with commodity prices.
Unrealized derivative (gain)
loss.
We
recognized a loss of $5.7 million in the third quarter of 2010 compared to a
loss of $4.1 million for the same period in 2009. This non-cash item is driven by the change in
the value of our hedge position, as well as the portion of that position that
is considered ineffective for accounting purposes. Please refer to our discussion under the
heading
Hedging Activities
under Overview of the
Company, Highlights, and Outlook
.
Income tax
expense.
We
recorded income tax expense of $9.3 million for the third quarter of 2010
compared to income tax benefit of $2.6 million for the third quarter of 2009
resulting in effective tax rates of 37.7 percent and 37.1 percent,
respectively. The change in income tax expense is primarily the result of
the differences in components of net income discussed above. The 2010 increase
in effective tax rate from 2009 primarily reflects changes in the mix of the
highest marginal state tax rates and the resulting effect on year-to-date net
income as a result of divestiture and drilling activity in 2010, and to a
lesser extent, changes
40
Table of Contents
in the effects of other permanent
differences including the domestic production activities deduction. The
current portion of our income tax expense is lower compared with the same
period of 2009, as this item is being impacted by the 2010 drilling program and
utilization of proceeds from 2010 non-core asset divestitures compared with a
decreased drilling program in 2009 caused by lower commodity prices.
These trends are expected to continue throughout the remainder of 2010 based
upon our current projected capital expenditures program and commodity price
outlook.
Comparison of Financial Results and Trends between the nine months
ended September 30, 2010, and 2009
Oil and gas production
revenue.
Average
daily production decreased six percent to 286.9 MMCFE for the nine months
ended September 30, 2010, compared with 303.8 MMCFE for the same period in
2009. The following table presents the
regional changes in our production and oil and gas revenues and costs between
the two nine-month periods.
|
|
Average Net Daily
Production
Added (Decreased)
|
|
Pre-Hedge
Oil and Gas
Revenue Added
|
|
Production Costs
Increase
(Decrease)
|
|
|
|
(MMCFE/d)
|
|
(In millions)
|
|
(In millions)
|
|
Mid-Continent
|
|
(7.7
|
)
|
|
30.5
|
|
3.0
|
|
ArkLaTex
|
|
(7.7
|
)
|
|
4.1
|
|
(6.3)
|
|
South
Texas & Gulf Coast
|
|
24.9
|
|
|
69.8
|
|
9.5
|
|
Permian
|
|
(2.5
|
)
|
|
32.1
|
|
1.8
|
|
Rocky
Mountain
|
|
(23.9
|
)
|
|
21.3
|
|
(23.8)
|
|
Total
|
|
(16.9
|
)
|
|
157.8
|
|
(15.8)
|
|
The largest regional production
decrease occurred in the Rocky Mountain region and was completely offset by the
regional increase in the South Texas & Gulf Coast region which is
described in more detail above under
Comparison of Financial
Results and Trends between the three months ended September 30, 2010, and
2009
.
The following table summarizes the
average realized prices we received for the first nine months of 2010 compared
to the same period in 2009, before the effects of hedging. Prices for oil and gas increased between the
two periods.
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
Realized
oil price ($/Bbl)
|
|
$
|
70.70
|
|
|
$
|
49.82
|
|
|
Realized
gas price ($/Mcf)
|
|
$
|
5.20
|
|
|
$
|
3.49
|
|
|
Realized
equivalent price ($/MCFE)
|
|
$
|
7.48
|
|
|
$
|
5.16
|
|
|
The combination of a 45 percent
increase in average realized prices offset by a six percent decrease in
production volumes between periods resulted in higher oil and gas revenue. Please refer to additional discussion under
Comparison of Financial Results and Trends between the three months
ended September 30, 2010, and 2009.
Realized oil and gas hedge
gain.
We
recorded a net realized hedge gain of $20.8 million for the nine-month period
ended September 30, 2010, related to settlements on oil and gas hedges,
compared with $127.2 million gain for the same period in 2009. Our realized oil and gas hedge gains and
losses are a function of commodity prices and the price at which production was
hedged.
41
Table of Contents
Gain (loss) on divestiture
activity.
We had a $132.2 million net gain on divestiture activity for
the nine-month period ended September 30, 2010, compared with a $10.6
million net loss on sale for the comparable period of 2009, due primarily to
the divestitures of non-core oil and gas properties located in our Rocky
Mountain region that occurred in the first quarter of 2010. The final gain on divestiture activity
related to the Sequel divestiture will be adjusted for normal post-closing
adjustments and is expected to be finalized during the fourth quarter of
2010. Please refer to additional
discussion under
Comparison of Financial Results and Trends
between the three months ended September 30, 2010, and 2009.
Marketed gas system revenue and
expense.
Marketed
gas system revenue increased $12.5 million to $54.0 million for the
nine-month period ended September 30, 2010, compared with
$41.5 million for the comparable period of 2009. Concurrent with the increase in marketed gas
system revenue, marketed gas system expense increased $11.2 million to
$52.6 million for the nine-month period ended September 30, 2010,
compared with $41.4 million for the comparable period in 2009.
Oil and gas production
expense.
Total
production costs decreased $15.8 million, or ten percent, to $138.1 million for
the first nine months of 2010 from $153.9 million in the comparable period of
2009. Total oil and gas production costs
per MCFE decreased $0.10 to $1.76 for the first nine months of 2010, compared
with $1.86 for the same period in 2009.
This decrease is comprised of the following:
·
A $0.21 decrease in recurring LOE on a per MCFE basis
reflects the divestiture of higher cost non-core properties in 2010. Please refer to additional discussion under
Comparison of Financial Results and Trends between the three months
ended September 30, 2010, and 2009.
·
A $0.01 decrease in overall transportation cost on a per
MCFE basis was as a result of the divestiture of non-core properties in the
Rocky Mountain region in late 2009 that had higher transportation costs
associated with them
·
A $0.01 overall decrease in workover LOE on a per MCFE basis
relating to a decrease in workover activity in our Rocky Mountain region
·
A $0.13 per MCFE increase in production taxes is due to the
increase in pre-hedge oil and gas revenues between periods.
Depletion, depreciation,
amortization, and asset retirement obligation liability accretion.
DD&A
increased five percent, to $241.3 million for the nine-month period ended
September 30, 2010, compared with $229.1 million for the same period
in 2009. DD&A expense per MCFE
increased 12 percent to $3.08 for the nine-month period ended September 30,
2010, compared to $2.76 for the same period in 2009. Please refer to additional discussion under
Comparison of Financial Results and Trends between the three months
ended September 30, 2010, and 2009.
Exploration.
Exploration
expense decreased $6.0 million, or 12 percent, to $42.8 million for the
nine-month period ended September 30, 2010, compared with $48.8 million
for the same period in 2009. Exploratory
dry hole expense was $4.8 million for the nine months ended
September 30, 2009, compared with $289,000 for the same period in
2010. In 2009 several wells in the
ArkLaTex were deemed to be dry. Please
refer to additional discussion under
Comparison of Financial
Results and Trends between the three months ended September 30, 2010, and
2009.
Impairment of proved
properties.
There were no proved property impairments recorded for the
nine-month period ended September 30, 2010. We recorded a $153.2 million impairment of
proved oil and gas properties for the comparable period in 2009, which was
driven by a significant decrease in realized gas prices in the first quarter of
2009, particularly in the Mid-Continent region, and for our coalbed methane
project at Hanging Woman Basin, which was divested in late 2009. In the near-term, we expect that a continued
decline in natural gas commodity prices would result in proved property
impairments.
42
Table of Contents
Abandonment and impairment of
unproved properties.
Abandonment and impairment of unproved properties decreased
$15.3 million or 75 percent to $5.0 million for the nine months ended
September 30, 2010, compared with $20.3 million for the comparable
period in 2009. We experienced larger
abandonments and impairments in 2009 as a result of our lower capital budget.
Impairment of materials
inventory.
There were no materials inventory impairments recorded for
the nine-month period ended September 30, 2010. We recorded a $13.4 million impairment of
materials inventory for the nine-month period ended September 30, 2009,
which was caused by a decrease in the value of tubular goods and other raw
materials. Impairment of materials
inventory are impacted by fluctuations in materials costs environment and
increases and decreases in development and exploration activity, which
generally trend with commodity prices.
General and administrative.
General
and administrative expense increased $19.8 million or 36 percent to $75.1
million for the nine months ended September 30, 2010, compared with $55.3
million for the comparable period of 2009.
On a per unit basis, G&A expense increased $0.29 to $0.96 per MCFE
for the first nine months of 2010 compared to $0.67 per MCFE for the same
nine-month period in 2009.
General and administrative expense
increased due a $10.2 million increase in cash bonus, long-term incentive
compensation, and base compensation, and a $4.1 million decrease in COPAS
overhead reimbursements. Please refer to
additional discussion under
Comparison of Financial
Results and Trends between the three months ended September 30, 2010, and
2009.
The $3.3 million
increase in Net Profits Plan payments to plan participants was the result of
pools entering the higher 20 percent payout level as described further in Note
7 of Part 1, Item 1of this report, and the 2005 pool entering payout
for the first time. As of the end of the
third quarter of 2010, 18 of our 21 pools are in payout status. No additional pools are expected to reach
payout in 2010.
Change in Net Profits Plan
liability.
Please refer to discussion under the heading
Net Profits Plan
under Overview of the Company, Highlights,
and Outlook
.
Unrealized derivative (gain)
loss.
We
recognized a gain of $4.1 million for the nine months ended September 30,
2010, compared to a loss of $17.3 million for the same period in 2009. This non-cash item is driven by the change in
the value of our hedge position, as well as the portion of that position that
is considered ineffective for accounting purposes. Please refer to our discussion under the
heading
Hedging Activities
under Overview of the
Company, Highlights, and Outlook
.
Other expense.
Other
expense decreased $10.3 million to $2.1 million for the nine months ended September 30,
2010, compared with $12.4 million for the same period in 2009. During the first nine months of 2009, we
incurred $1.5 million of expense related to the assignment of a drilling rig
contract in our Rocky Mountain region.
We also incurred an additional loss related to hurricanes of $8.3
million for the nine months ended September 30, 2009, which related to an
increase in our estimate of the remediation cost for the Vermilion 281 platform
that was lost in Hurricane Ike.
Income tax expense.
Income
tax expense totaled $96.7 million for the nine-month period of 2010 compared to
an income tax benefit of $61.6 million for the same period of 2009 resulting in
effective tax rates of 37.7 percent and 38.0 percent,
respectively. The change in income tax expense is the result of the
gains from 2010 divestitures and our 2009 loss before income
taxes. The 2010 decrease in effective tax rate from 2009 reflects
changes in the impact of other permanent differences including the domestic
production activities deduction partially offset by an increase related to the
mix of the highest marginal state tax rates resulting from divestiture and
drilling activity in 2010. The current portion of our tax expense is
greater in 2010 compared to 2009 due to the impact of our non-core asset
divestitures in 2010 and the estimated impact of our projected capital
expenditures drilling program at September 30, 2010.
43
Table of Contents
Overview of Liquidity and Capital Resources
We believe that we have sufficient
liquidity and capital resources to execute our business plans for the
foreseeable future.
Sources of Cash
Based on our current outlook, we
expect our generated cash flow from operations in 2010, including the net cash
proceeds from the Rocky Mountain oil and other non-core asset divestiture
packages, to fund the majority of our exploration and development budget for
2010. We will rely on our credit facility
to fund any remaining balance of our capital program for the year. Accordingly, we do not expect to access the
capital markets in 2010. Given the size
of our commitments associated with our existing inventory of potential drilling
projects, our requirements for funding could increase significantly in 2011 and
beyond. As a result, we may consider
accessing the capital markets, and other alternatives, as we determine how to
best fund our capital program. As noted
we are continuing to evaluate our property base to identify and divest of
properties we consider non-core to our strategic goals.
Our primary sources of liquidity are
the cash flows provided by our operating activities, use of our credit
facility, sales of non-core properties, and accessing the capital and debt
markets. From time to time, we may be
able to enter into carrying cost funding and sharing arrangements with third
parties for particular exploration and development programs. All of these
sources can be impacted by the general condition of the broad economy and by
significant fluctuations in oil and gas prices, operating costs, and volumes
produced, all of which affect us and our industry. We have no control over the market prices for
oil, natural gas, and NGLs although we are able to influence the amount of our
net realized revenues related to our oil and gas sales through the use of
derivative contracts. The borrowing base
on our credit facility could be reduced as a result of lower commodity prices
or sales of non-core producing properties.
Historically, decreases in commodity prices have limited our industrys
access to the capital markets. We
believe the public debt markets are currently accessible. Equity and convertible debt issuances are
also available to us as alternative financing sources. We do not anticipate the need to raise public
debt or equity financing in the near term, however these are options we would
consider under the appropriate circumstances.
Current Credit Facility
On April 14, 2009, we
entered into an amended $1.0 billion senior secured revolving credit facility
with twelve participating banks. The
initial borrowing base was set at $900 million.
In September 2010 the lending group redetermined our reserve-backed
borrowing base under the credit facility at $1.1 billion. We have been provided a $678 million
commitment amount by the bank group. Our
credit facility agreement has a maturity date of July 31, 2012. Management believes that the current
commitment is sufficient for our current liquidity needs. To date, we have experienced no issues
drawing upon our credit facility. No
individual bank participating in the credit facility represents more than 17
percent of the lending commitments under the credit facility. We monitor the credit environment closely and
have frequent discussions with the lending group.
As of
October 27, 2010, we had $639.5 million of available borrowing
capacity under this facility. We have a single letter of credit outstanding
under our credit facility, in the amount of $483,000 as of October 27, 2010,
which reduces the amount available under the commitment amount on a
dollar-for-dollar basis. Borrowings
under the facility are secured by mortgages on the majority of our oil and gas
properties. Please refer to Note 5 Long-term Debt in Part IV, Item 15 of our Annual
Report on Form 10-K for the year ended December 31, 2009, for
our borrowing base utilization grid.
The following table sets
forth our weighted-average credit facility debt balance and weighted-average
interest rates:
44
Table of
Contents
|
|
For the Three Months
Ended September 30,
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(In millions)
|
|
Weighted-average
credit facility debt balance
|
|
$
|
6.8
|
|
|
$
|
257.7
|
|
|
$
|
43.9
|
|
|
$
|
289.0
|
|
Weighted-average
interest rate
*
|
|
9.2%
|
|
|
5.9%
|
|
|
8.4%
|
|
|
5.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Includes
the impact of our 3.50% Senior Convertible Notes.
Our weighted-average interest rates
in the current and prior year include cash interest payments, cash fees paid on
the unused portion of the credit facilitys aggregate commitment amount, letter
of credit fees, amortization of the convertible notes debt discount, and
amortization of deferred financing costs. The increase in our weighted-average
interest rate from the comparative quarter in 2009 is the result of commitment
fees and non-cash charges being spread across a much lower average outstanding
debt balance.
We are subject to customary
financial and non-financial covenants under our credit facility, including
limitations on dividend payments and requirements to maintain certain financial
ratios, which include debt to earnings before interest, taxes, depreciation,
and amortization of not more than 3.5 to 1.0 and a current ratio, as
defined by our credit agreement, of not less than 1.0 to 1.0. The unused portion of our credit facility is
factored in when calculating our current ratio.
As of September 30, 2010, our debt to EBITDA ratio and current
ratio as defined by our credit agreement were 0.61 and 2.58, respectively. We are in compliance with all financial and
non-financial covenants under our credit facility.
Uses of Cash
We use cash for the acquisition,
exploration, and development of oil and gas properties, and for the payment of
debt obligations, trade payables, income taxes, common stock repurchases, and
stockholder dividends. In the first nine
months of 2010 we spent $488.7 million for exploration and development capital
expenditures. These amounts differ from
our costs incurred amounts based on the timing of cash payments associated with
these activities as compared to the accrual based activity upon which costs
incurred amounts are presented. These
cash outflows were funded using cash inflows from operations, proceeds from the
sale of assets, and available borrowing capacity under our revolving credit
facility.
Expenditures for exploration and
development of oil and gas properties and acquisitions are the primary use of
our capital resources. We expect our
capital and exploration expenditures in 2010 will exceed our operating cash
flow, and we plan to fund this shortfall with the proceeds received from our
non-core asset divestitures, and borrowings under our credit facility. The amount and allocation of future capital
expenditures will depend upon a number of factors including the number and size
of available economic acquisitions and drilling opportunities, our cash flows
from operating, investing, and financing activities, and our ability to
assimilate acquisitions. Also, the
impact of oil and gas prices on investment opportunities, the availability of
capital and borrowing facilities, and the success of our development and
exploratory activities could lead to changes in funding requirements for future
development. We regularly review our capital expenditure budget to assess
changes in current and projected cash flows, acquisition and divestiture
opportunities, debt requirements, and other factors.
As of the filing date of this
report, we have Board authorization to repurchase up to 3,072,184 shares of our
common stock under our stock repurchase program. Shares may be repurchased from time to time
in open market transactions or privately negotiated transactions subject to
market conditions and other factors including certain provisions of our
existing bank credit facility agreement, compliance with securities laws, and
the terms and provisions of our stock repurchase program. There have been no share repurchases to date
in 2010, and we do not plan to repurchase shares for the remainder of 2010.
45
Table
of Contents
Current proposals to fund the
federal government budget include eliminating or reducing current tax
deductions for intangible drilling costs, the domestic production activities
deduction, and percentage depletion.
Legislation modifying or eliminating these deductions would have the immediate
effect of reducing operating cash flows thereby reducing funding available for
our exploration and development capital programs and those of our peers in the
industry. These potential funding
reductions could have a significant adverse effect on drilling in the United
States for a number of years.
The following table presents amount
and percentage changes in cash flows between the nine-month periods ended September 30,
2010, and 2009. The analysis following
the table should be read in conjunction with our condensed consolidated statements
of cash flows in Part I, Item 1 of this report.
|
|
For the Nine Months
Ended September 30,
|
|
|
|
Percent
|
|
|
|
2010
|
|
2009
|
|
Change
|
|
Change
|
|
|
|
(In thousands)
|
|
|
|
Net cash
provided by operating activities
|
|
$
|
418,360
|
|
|
$
|
353,052
|
|
|
$
|
65,308
|
|
|
18 %
|
|
Net cash
used in investing activities
|
|
$
|
236,360
|
|
|
$
|
260,651
|
|
|
$
|
(24,291)
|
|
|
(9)%
|
|
Net cash
used in financing activities
|
|
$
|
185,560
|
|
|
$
|
78,015
|
|
|
$
|
107,545
|
|
|
138 %
|
|
Analysis of Cash Flow Changes Between the
Nine Months Ended September 30, 2010, and September 30, 2009
Operating activities.
Cash
received from oil and gas production revenue, net of the realized effects of
hedging, increased $30.9 million to $602.9 million for the first nine
months of 2010, compared with $572.0 million for the first nine months of
2009. Additionally, cash paid for lease
operating expenses decreased $33.1 million to $88.9 million for the first
nine months of 2010, compared with $122.0 million for the first nine months of
2009.
Investing activities.
Cash
used in investing activities for the nine months ended
September 30, 2010, was $236.4 million compared with $260.7 million
for the same period of 2009. We received
proceeds of $259.5 million from the sale of non-core properties located
primarily in the Rocky Mountain region for the nine months ended September 30,
2010. There were no major divestitures
for the same period in 2009. Cash
outflows for capital expenditures increased by $196.2 million for the nine
months ended September 30, 2010, compared with the same period in 2009.
This is due to increased drilling activity as a result of more favorable
commodity prices and an improved overall macro-economic environment.
Financing activities.
Net
repayments on our credit facility increased by $121.0 million for the nine
months ended September 30, 2010, compared with the same period in
2009. We have significantly reduced our
credit facility balance throughout the first nine months of 2010, but we expect
borrowings to increase during the rest of 2010.
46
Table
of Contents
Capital Expenditures
The following table sets forth
certain historical information regarding the costs incurred by us in our oil
and gas activities.
|
|
For the Nine Months
Ended September 30,
|
|
|
|
2010
|
|
2009
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
Development
costs
(1)
|
|
$
|
196,768
|
|
|
$
|
154,978
|
|
|
Exploration
costs
|
|
329,909
|
|
|
91,549
|
|
|
Acquisitions
|
|
|
|
|
|
|
|
Proved
properties
|
|
663
|
|
|
55
|
|
|
Unproved
properties - other
|
|
35,131
|
|
|
20,642
|
|
|
Total,
including asset retirement obligations
(2)
|
|
$
|
562,471
|
|
|
$
|
267,224
|
|
|
(1)
Includes capitalized interest of $1.6 million in 2010 and
$1.4 million in 2009.
(2)
Includes amounts relating to estimated asset retirement
obligations of $3.3 million in 2010 and $672,000 in 2009.
Costs incurred for development and
exploration activities during the first nine months of 2010 increased $280.2
million or 114 percent compared to the same period in 2009. This increase in capital and exploration
activities reflects a stable and improving economic environment and higher cash
flows available for investment provided by operating activities and divestiture
proceeds.
We believe our operating cash flows
together with the full availability of our credit facility and proceeds from
divestitures will be sufficient to fund our planned operating, drilling, and
acquisition expenditures for the foreseeable future. The amount and allocation of future capital
and exploration expenditures will depend upon a number of factors, including
the number and size of available economic acquisition and drilling
opportunities, our cash flows from operating and financing activities, and our
ability to assimilate leasehold and producing property acquisitions. In addition, the impact of oil and natural
gas prices on investment opportunities, the availability of capital and
borrowing facilities, and the success of our development and exploratory
activities may lead to changes in funding requirements for future development.
Commodity Price Risk and Interest
Rate Risk
We are exposed to market risk,
including the effects of changes in oil and gas commodity prices and changes in
interest rates as discussed below under the caption
Summary of
Interest Rate Risk.
Changes
in interest rates can affect the amount of interest we earn on our cash, cash
equivalents, and the amount of interest we pay on borrowings under our
revolving credit facility. Changes in
interest rates do not affect the amount of interest we pay on our fixed-rate
3.50% Senior Convertible Notes, but do affect their fair market value.
There has been no material change to
the natural gas and crude oil price sensitivity analysis previously
disclosed. Refer to the corresponding
section under Part II, Item 7 of our Form 10-K for the year
ended December 31, 2009.
Summary of Oil, Gas, and NGL Production
Hedges in Place
Our oil, natural gas, and NGL
derivative contracts include costless swaps and costless collar
arrangements. All contracts are entered
into for other-than-trading purposes.
Please refer to Note 10 Derivative Financial Instruments in Part I, Item
1 of this report for additional information regarding accounting for our
derivative transactions.
47
Table
of Contents
Our net realized oil and gas prices
are impacted by hedges we have placed on forecasted production. Hedging is an important part of our financial
risk management program. The amount of
production we hedge is driven by the amount of debt on our consolidated balance
sheet and the level of capital and long-term commitments we have made. In the case of a significant acquisition of
producing properties, we will consider hedging a portion of the anticipated
production in order to protect the economics assumed at the time of the
acquisition. As of September 30,
2010, our hedged positions of anticipated production through the second quarter
of 2013 totaled approximately 5 million Bbls of oil, 42 million MMBtu of
natural gas, and 2 million Bbls of NGLs.
As of October 27, 2010, we have hedge contracts in place
through the third quarter of 2013 for a total of approximately 7 million
Bbls of anticipated crude oil production, 42 million MMBtu of anticipated
natural gas production, and 2 million Bbls of anticipated NGL production.
In a typical commodity swap
agreement, if the agreed upon published third-party index price is lower than
the swap fixed price, we receive the difference between the index price and the
agreed upon swap fixed price. If the
index price is higher than the swap fixed price, we pay the difference. For collar agreements, we receive the
difference between an agreed upon index and the floor price if the index price
is below the floor price. We pay the
difference between the agreed upon contracted ceiling price and the index price
if the index price is above the contracted ceiling price. No amounts are paid or received if the index
price is between the contracted floor and ceiling prices.
The following tables describe the
volumes, average contract prices, and fair values of contracts we have in place
as of September 30, 2010, and October 27, 2010. We seek to minimize ineffectiveness by
entering into oil derivative contracts indexed to NYMEX WTI, natural gas
derivative contracts indexed to regional index prices associated with pipelines
in proximity to our areas of production, and NGL derivative contracts indexed
to Oil Price Information Service Mont Belvieu.
As our derivative contracts contain the same index as our sales
contracts, our derivative contracts are highly correlated with the underlying
hedged item.
48
Table
of Contents
Oil Contracts
Oil Swaps
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
September 30, 2010
(Liability)
|
|
|
|
(Bbls)
|
|
(per Bbl)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2010
|
|
309,000
|
|
$
|
66.06
|
|
$
|
(4,666
|
)
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
1,164,000
|
|
$
|
67.06
|
|
(20,325
|
)
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
1,514,200
|
|
$
|
82.62
|
|
(6,808
|
)
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
294,600
|
|
$
|
84.30
|
|
(1,079
|
)
|
|
All oil
swaps
|
|
3,281,800
|
|
|
|
|
$
|
(32,878
|
)
|
|
Oil Collars
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|
Fair Value at
September 30, 2010
Asset (Liability)
|
|
|
|
(Bbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2010
|
|
344,500
|
|
$
|
50.00
|
|
$
|
64.91
|
|
$
|
(5,669)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
1,236,000
|
|
$
|
50.00
|
|
$
|
63.70
|
|
|
(27,813)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
163,700
|
|
$
|
80.00
|
|
$
|
100.85
|
|
|
316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
282,600
|
|
$
|
80.00
|
|
$
|
100.85
|
|
|
296
|
|
|
All oil
collars
|
|
2,026,800
|
|
|
|
|
|
|
$
|
(32,870)
|
|
|
49
Table
of Contents
Gas Contracts
Gas Swaps
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
September 30, 2010
Asset
|
|
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2010
|
|
|
|
|
|
|
|
IF ANR
OK
|
|
140,000
|
|
$
|
5.97
|
|
$
|
321
|
|
IF CIG
|
|
270,000
|
|
$
|
5.87
|
|
620
|
|
IF El
Paso
|
|
370,000
|
|
$
|
6.43
|
|
1,006
|
|
IF HSC
|
|
590,000
|
|
$
|
8.61
|
|
2,785
|
|
IF NGPL
|
|
430,000
|
|
$
|
5.61
|
|
821
|
|
IF NNG
Ventura
|
|
360,000
|
|
$
|
6.34
|
|
855
|
|
IF PEPL
|
|
520,000
|
|
$
|
5.92
|
|
1,175
|
|
IF
Reliant
|
|
1,350,000
|
|
$
|
5.71
|
|
2,693
|
|
IF TETCO
STX
|
|
180,000
|
|
$
|
6.23
|
|
444
|
|
NYMEX
Henry Hub
|
|
840,000
|
|
$
|
7.52
|
|
3,001
|
|
|
|
|
|
|
|
|
|
|
|
50
Table
of Contents
Gas Swaps (continued)
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
September 30, 2010
Asset
|
|
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
IF ANR
OK
|
|
500,000
|
|
$
|
6.10
|
|
957
|
|
IF CIG
|
|
1,030,000
|
|
$
|
5.96
|
|
1,992
|
|
IF El
Paso
|
|
1,780,000
|
|
$
|
6.35
|
|
3,963
|
|
IF HSC
|
|
360,000
|
|
$
|
9.01
|
|
1,732
|
|
IF NGPL
|
|
1,040,000
|
|
$
|
6.09
|
|
1,992
|
|
IF NNG
Ventura
|
|
1,200,000
|
|
$
|
6.36
|
|
2,409
|
|
IF PEPL
|
|
1,830,000
|
|
$
|
6.04
|
|
3,539
|
|
IF
Reliant
|
|
4,510,000
|
|
$
|
6.13
|
|
8,795
|
|
IF TETCO
STX
|
|
1,420,000
|
|
$
|
6.51
|
|
3,202
|
|
NYMEX
Henry Hub
|
|
2,130,000
|
|
$
|
6.72
|
|
4,903
|
|
2012
|
|
|
|
|
|
|
|
IF ANR
OK
|
|
360,000
|
|
$
|
6.18
|
|
524
|
|
IF CIG
|
|
1,020,000
|
|
$
|
5.77
|
|
1,110
|
|
IF El
Paso
|
|
850,000
|
|
$
|
6.04
|
|
1,049
|
|
IF NGPL
|
|
660,000
|
|
$
|
6.34
|
|
1,047
|
|
IF NNG
Ventura
|
|
620,000
|
|
$
|
6.51
|
|
910
|
|
IF PEPL
|
|
2,730,000
|
|
$
|
6.25
|
|
4,205
|
|
IF
Reliant
|
|
3,540,000
|
|
$
|
5.97
|
|
3,950
|
|
IF TETCO
STX
|
|
660,000
|
|
$
|
6.30
|
|
896
|
|
2013
|
|
|
|
|
|
|
|
IF PEPL
|
|
1,250,000
|
|
$
|
5.65
|
|
479
|
|
IF
Reliant
|
|
1,290,000
|
|
$
|
5.64
|
|
452
|
|
|
|
|
|
|
|
|
|
All gas
swap contracts
|
|
33,830,000
|
|
|
|
$
|
61,827
|
|
|
|
|
|
|
|
|
|
|
|
51
Table
of Contents
Gas Collars
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|
Fair Value at
September 30, 2010
Asset
|
|
|
|
(MMBtu)
|
|
(per MMBtu)
|
|
(per MMBtu)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2010
|
|
|
|
|
|
|
|
|
|
IF CIG
|
|
510,000
|
|
$
|
4.85
|
|
$
|
7.08
|
|
$
|
664
|
|
IF HSC
|
|
150,000
|
|
$
|
5.57
|
|
$
|
7.88
|
|
253
|
|
IF PEPL
|
|
1,240,000
|
|
$
|
5.31
|
|
$
|
7.61
|
|
2,032
|
|
NYMEX
Henry
|
|
60,000
|
|
$
|
6.00
|
|
$
|
8.38
|
|
124
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
IF CIG
|
|
1,800,000
|
|
$
|
5.00
|
|
$
|
6.32
|
|
2,031
|
|
IF HSC
|
|
480,000
|
|
$
|
5.57
|
|
$
|
6.77
|
|
634
|
|
IF PEPL
|
|
4,225,000
|
|
$
|
5.31
|
|
$
|
6.51
|
|
5,418
|
|
NYMEX
Henry
|
|
120,000
|
|
$
|
6.00
|
|
$
|
7.25
|
|
195
|
|
|
|
|
|
|
|
|
|
|
|
All gas
collars
|
|
8,585,000
|
|
|
|
|
|
$
|
11,351
|
|
Natural Gas Liquid Contracts
Natural Gas Liquid Swaps
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
Fair Value at
September 30, 2010
Asset (Liability)
|
|
|
|
(approx. Bbls)
|
|
(per Bbl)
|
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
Fourth
quarter 2010
|
|
285,000
|
|
$
|
42.67
|
|
$
|
(545)
|
|
|
2011
|
|
907,000
|
|
$
|
40.32
|
|
(617)
|
|
|
2012
|
|
492,000
|
|
$
|
43.92
|
|
166
|
|
|
2013
|
|
84,000
|
|
$
|
44.63
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
All
natural gas liquid swaps*
|
|
1,768,000
|
|
|
|
$
|
(969)
|
|
|
*Natural gas liquid swaps are
comprised of OPIS Mont. Belvieu LDH Propane (31%), OPIS Mont. Belvieu Purity
Ethane (41%), OPIS Mont. Belvieu NON-LDH Isobutane (4%), OPIS Mont. Belvieu
NON-LDH Natural Gasoline (13%), and OPIS Mont. Belvieu NON-LDH Normal Butane (11%).
52
Table
of Contents
Hedge Contracts Entered into After September 30,
2010
The following table includes all
hedges entered into subsequent to September 30, 2010 through
October 27, 2010.
Oil Swaps
Contract Period
|
|
NYMEX WTI
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
|
|
(Bbl)
|
|
(Per Bbl)
|
|
Fourth
quarter 2010
|
|
35,100
|
|
$
|
82.70
|
|
2011
|
|
275,000
|
|
$
|
84.82
|
|
All oil
swaps
|
|
310,100
|
|
|
|
Oil Collars
Contract Period
|
|
NYMEX
WTI
Volumes
|
|
Weighted-
Average
Floor
Price
|
|
Weighted-
Average
Ceiling
Price
|
|
|
|
(Bbls)
|
|
(per Bbl)
|
|
(per Bbl)
|
|
|
|
|
|
|
|
|
|
2012
|
|
503,800
|
|
$
|
70.00
|
|
$
|
104.25
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
893,700
|
|
$
|
70.00
|
|
$
|
104.64
|
|
All oil
collars
|
|
1,397,500
|
|
|
|
|
|
Natural Gas Liquid Swaps
Contract Period
|
|
Volumes
|
|
Weighted-
Average
Contract
Price
|
|
|
|
(Bbls)
|
|
(per Bbl)
|
|
|
|
|
|
|
|
Fourth
Quarter 2010
|
|
27,000
|
|
$
|
40.28
|
|
2011
|
|
265,000
|
|
$
|
40.10
|
|
2012
|
|
150,000
|
|
$
|
19.53
|
|
All
natual gas liquid swaps*
|
|
442,000
|
|
|
|
*Natural gas liquid swaps are
comprised of OPIS Mont. Belvieu LDH Propane (19%), OPIS Mont. Belvieu Purity
Ethane (65%), OPIS Mont. Belvieu NON-LDH Isobutane (2%), OPIS Mont. Belvieu
NON-LDH Natural Gasoline (8%), and OPIS Mont. Belvieu NON-LDH Normal Butane
(6%).
Refer to Note 10 Derivative Financial
Instruments in Part I, Item 1 of this report for additional
information regarding our oil and gas hedges.
Summary of Interest Rate Risk
Market risk is estimated as the
potential change in fair value resulting from an immediate hypothetical one percentage
point parallel shift in the yield curve.
For fixed-rate debt, interest changes affect the fair market value but
do not impact results of operations or cash flows. Conversely, interest rate
53
Table of Contents
changes for floating-rate debt
generally do not affect the fair market value but do impact future results of
operations and cash flows, assuming other factors are held constant. The carrying amount of our floating-rate debt
typically approximates its fair value.
We had $2.0 million of floating-rate debt outstanding as of September 30,
2010. Our fixed-rate debt outstanding,
net of debt discount, at this same date was $273.4 million.
Contractual Obligations
Please see
Note 6 Commitments and Contingencies under Part I, Item 1 of this
report for information pertaining to new operating lease obligations and
through-put commitments.
Off-Balance Sheet Arrangements
As part of our ongoing business, we
have not participated in transactions that generate relationships with
unconsolidated entities or financial partnerships, such as entities often
referred to as structured finance entities or special purpose entities, which
would have been established for the purpose of facilitating off-balance sheet
arrangements or other contractually narrow or limited purposes. As of September 30, 2010, we have not
been involved in any unconsolidated SPE transactions.
We evaluate our transactions to
determine if any variable interest entities exist. If it is determined that we are the primary
beneficiary of a variable interest entity, that entity is consolidated into our
consolidated financial statements.
Critical Accounting Policies and Estimates
We refer you to the corresponding
section in Part II, Item 7 of our Annual Report on Form 10-K for
the year ended December 31, 2009, and to the footnote disclosures included
in Part I, Item 1 of this report.
New Accounting Pronouncements
Please see Note 12 Recent
Accounting Pronouncements under Part I, Item 1 of this report for new
accounting matters.
Environmental
SM Energys compliance with
applicable environmental regulations has to date not resulted in significant
capital expenditures or material adverse effects on our liquidity or results of
operations. We believe we are in
substantial compliance with environmental regulations and do not currently
anticipate that material future expenditures will be required under the
existing regulatory framework. However,
we are unable to predict the impact that compliance with future laws or
regulations, such as those currently being considered as discussed below, may
have on future capital expenditures, liquidity, and results of operations.
The U.S. Congress is currently
considering legislation that would amend the Safe Drinking Water Act to
eliminate an existing exemption from federal regulation of hydraulic fracturing
activities. Hydraulic fracturing is a
common and reliable process in our industry of creating artificial cracks, or
fractures, in deep underground rock formations through the pressurized
injection of water, sand and other additives to enable oil or natural gas to
move more easily through the rock pores to a production well. This process is often necessary to produce
commercial quantities of oil and natural gas from many reservoirs, especially
shale rock formations. We routinely
utilize hydraulic fracturing in many of our reservoirs, and our Eagle Ford,
Bakken/Three Forks, Haynesville, Marcellus, Woodford, and other shale programs
utilize or contemplate the utilization of hydraulic fracturing. Currently, regulation of hydraulic fracturing
is primarily conducted at the state level through permitting and other
compliance requirements. If adopted, the
proposed amendment to the Safe Drinking Water Act could result in additional
regulations and permitting
54
Table of Contents
requirements at the federal
level. On March 18, 2010, the
Environmental Protection Agency (EPA) announced that it has allocated $1.9
million in 2010 and has requested funding in fiscal year 2011 for conducting a
comprehensive research study on the potential adverse impacts that hydraulic
fracturing may have on water quality and public health. In addition, various state and local
governments are considering increased regulatory oversight of hydraulic
fracturing through additional permit requirements, operational restrictions,
and temporary or permanent bans on hydraulic fracturing in certain
environmentally sensitive areas, such as watersheds. Additional regulations and permitting
requirements could lead to significant operational delays and increased
operating costs, could make it more difficult to perform hydraulic fracturing,
and could impair our ability to produce commercial quantities of oil and
natural gas from certain reservoirs.
In December 2009, the EPA
published its findings that emissions of carbon dioxide, which is a byproduct
of the burning of refined oil products and natural gas, methane, which is a
primary component of natural gas, and other greenhouse gases present an
endangerment to human health and the environment because emissions of such
gases are, according to the EPA, contributing to warming of the Earths
atmosphere and other climatic changes. These findings by the EPA
allow the agency to proceed with the adoption and implementation of regulations
that would restrict emissions of greenhouse gases under existing provisions of
the federal Clean Air Act. Accordingly, the EPA had proposed
regulations that would require a reduction in emissions of greenhouse gases
from motor vehicles and that could also lead to the imposition of greenhouse
gas emission limitations in Clean Air Act permits for certain stationary
sources. In addition, on October 30, 2009, the EPA
published a final rule requiring the reporting of greenhouse gas emissions
from specified large greenhouse gas emission sources in the United States
beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA
announced a proposed rulemaking that would expand its final rule on
reporting of greenhouse gas emissions to include owners and operators of
onshore oil and natural gas production.
If the proposed rule is finalized in its current form, monitoring
of those newly covered sources would commence on
January 1, 2011. On May 13, 2010, the EPA issued rules to
regulate greenhouse gas emissions from large stationary sources such as power
plants and oil refineries. The adoption
and implementation of any regulations imposing reporting obligations on, or
limiting emissions of greenhouse gases from, our equipment and operations could
require us to incur increased costs to reduce emissions of greenhouse gases
associated with our operations and could adversely affect demand for the oil
and natural gas that we produce.
In addition, in June 2009, the
U.S. House of Representatives passed the American Clean Energy and Security Act
of 2009 (ACESA), which would establish an economy-wide cap-and-trade program
to reduce U.S. emissions of greenhouse gases, including carbon dioxide and
methane. ACESA would require a 17 percent reduction in greenhouse
gas emissions from 2005 levels by 2020, and just over an 80 percent reduction
of such emissions by 2050. Under this legislation, the EPA would
issue a capped and steadily declining number of tradable emissions allowances
to certain major sources of greenhouse gas emissions so that such sources could
continue to emit greenhouse gases into the atmosphere. The cost of
these allowances would be expected to escalate significantly over
time. The net effect of ACESA would be to impose increasing costs on
the combustion of carbon-based fuels such as oil, refined petroleum products,
and natural gas. The U.S. Senate has begun work on its own
legislation for restricting domestic greenhouse gas emissions, and the Obama
administration has indicated its support of legislation to reduce greenhouse
gas emissions through an emission allowance system. In addition,
several states have considered initiatives to regulate emissions of greenhouse
gases, primarily through the planned development of greenhouse gas emissions
inventories and/or regional greenhouse gas cap and trade programs. Although it
is not possible at this time to predict when the U.S. Senate may act on climate
change legislation or how any bill passed by the Senate would be reconciled
with ACESA, any future federal or state laws or regulations that may be adopted
to address greenhouse gas emissions could require us to incur increased
operating costs and could adversely affect the demand for the oil and natural
gas that we produce. Additional
information about the potential effect of climate change issues on our business
is presented under the Climate Change caption in the Managements Discussion
and Analysis of Financial Condition and Results of Operations section of our
Annual Report on Form 10-K for the year ended December 31, 2009.
55
Table
of Contents
In
response to the widely reported recent oil spill in the Gulf of Mexico
resulting from a deepwater drilling rig explosion in April 2010, the U.S.
Congress is considering a number of legislative proposals relating to the
upstream oil and gas industry both onshore and offshore that could result in
significant additional laws, regulations or taxes affecting our operations,
including a proposal to raise or eliminate the cap on liability for oil spill
cleanups under the Oil Pollution Act of 1990.
Although
it is not possible at this time to predict whether proposed legislation or
regulations will be adopted as initially written, if at all, or how legislation
or new regulations that may be adopted would impact our business, any such
future laws and regulations could result in increased compliance costs or
additional operating restrictions. Additional costs or operating
restrictions associated with legislation or regulations could have a material
adverse effect on our operating results and cash flows, in addition to the
demand for the crude oil, natural gas, and other hydrocarbon products that we
produce.
Cautionary Information
about Forward-Looking Statements
This Quarterly Report on Form 10-Q
contains forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. All statements, other than
statements of historical facts, included in this Form 10-Q that address
activities, events, or developments with respect to our financial condition,
results of operations, or economic performance that we expect, believe, or
anticipate will or may occur in the future, or that address plans and
objectives of management for future operations, are forward-looking
statements. The words anticipate, assume,
believe, budget, estimate, expect, forecast, intend, plan, project,
will, and similar expressions are intended to identify forward-looking
statements. Forward-looking statements
appear in a number of places in this Form 10-Q, and include statements
about such matters as:
·
The amount and nature of future capital expenditures
and the availability of liquidity and capital resources to fund capital
expenditures
·
The drilling of wells and other exploration
and development activities and plans, as well as possible future acquisitions
·
Proved reserve estimates and the estimates
of both future net revenues and the present value of future net revenues that
are included in their calculation
·
Future oil and natural gas production
estimates
·
Our outlook on future oil and natural gas
prices and service costs
·
Cash flows, anticipated liquidity, and the
future repayment of debt
·
Business strategies and other plans and
objectives for future operations, including plans for expansion and growth of
operations or to defer capital investment, and our outlook on our future financial
condition or results of operations
·
Other similar matters such as those
discussed in the Managements Discussion and Analysis of Financial Condition
and Results of Operations section of this Form 10-Q.
Our forward-looking statements
are based on assumptions and analyses made by us in light of our experience and
our perception of historical trends, current conditions, expected future
developments, and other factors that we believe are appropriate under the
circumstances. These statements are subject
to a number of known and unknown risks and uncertainties which may cause our
actual results and performance to be materially different from any future
results or performance expressed or implied by the forward-looking statements. These risks are described in the Risk
Factors section of our 2009 Annual Report on Form 10-K and include such
factors as:
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·
The volatility and level of realized oil and
natural gas prices
·
A contraction in demand for oil and natural
gas as a result of adverse general economic conditions or climate change
initiatives
·
The availability of economically attractive
exploration, development, and property acquisition opportunities and any
necessary financing, including constraints on the availability of opportunities
and financing due to distressed capital and credit market conditions
·
Our ability to replace reserves and sustain
production
·
Unexpected drilling conditions and results
·
Unsuccessful exploration and development
drilling
·
The risks of hedging strategies, including
the possibility of realizing lower prices on oil and natural gas sales as a
result of commodity price risk management activities
·
The pending nature of reported divestiture
plans for certain non-core oil and gas properties as well as the ability to
complete divestiture transactions
·
The uncertain nature of the expected
benefits from acquisitions and divestitures of oil and natural gas properties,
including uncertainties in evaluating oil and natural gas reserves of acquired
properties and associated potential liabilities, and uncertainties with respect
to the amount of proceeds that may be received from divestitures
·
The imprecise nature of oil and natural gas
reserve estimates
·
Uncertainties inherent in projecting future
rates of production from drilling activities and acquisitions
·
Declines in the values of our oil and
natural gas properties resulting in impairment charges and write-downs
·
The ability of purchasers of production to
pay for amounts purchased
·
Drilling and operating service availability
·
Uncertainties in cash flow
·
The financial strength of hedge contract
counterparties and credit facility participants, and the risk that one or more
of these parties may not satisfy their contractual commitments
·
The negative impact that lower oil and
natural gas prices could have on our ability to borrow and fund capital
expenditures
·
The potential effects of increased levels of
debt financing
·
Our ability to compete effectively against
other independent and major oil and natural gas companies and
·
Litigation, environmental matters, the
potential impact of government regulations, and the use of management
estimates.
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We caution you that
forward-looking statements are not guarantees of future performance and that
actual results or performance may be materially different from those expressed
or implied in the forward-looking statements.
Although we may from time to time voluntarily update our prior
forward-looking statements, we disclaim any commitment to do so except as
required by securities laws.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
The information required by this
item is provided under the captions
Commodity Price Risk and
Interest Rate Risk
,
Summary of Oil and Gas
Production Hedges in Place
, and
Summary of Interest Rate
Risk
in Item 2 above and is incorporated herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
We maintain a system of disclosure
controls and procedures that is designed to ensure that information required to
be disclosed in our SEC reports is recorded, processed, summarized, and
reported within the time periods specified in the SECs rules and forms,
and to ensure that such information is accumulated and communicated to our
management, including the Chief Executive Officer and the Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure.
We carried out an evaluation, under
the supervision and with the participation of our management, including the
Chief Executive Officer and the Chief Financial Officer, of the effectiveness
of the design and operation of our disclosure controls and procedures as of the
end of the period covered by the Quarterly Report on Form 10-Q. Based upon that evaluation, the Chief
Executive Officer and the Chief Financial Officer, concluded that our
disclosure controls and procedures are effective for the purposes discussed
above as of the end of the period covered by this Quarterly Report on Form 10-Q. There was no change in our internal control
over financial reporting that occurred during our most recent fiscal quarter
that has materially affected, or is reasonably likely to materially affect, the
effectiveness of our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1A. RISK FACTORS
There have been no material changes
from the risk factors as previously disclosed in our Form 10-K for the
year ended December 31, 2009, in response to Item 1A of Part I of
such Form 10-K.
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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
PROCEEDS
(c)
The following table provides information about purchases by
the Company or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under
the Exchange Act) during the fiscal quarter ended September 30, 2010, of
shares of the Companys common stock, which is the sole class of equity
securities registered by the Company pursuant to Section 12 of the
Exchange Act.
PURCHASES OF EQUITY SECURITIES BY
ISSUER
AND AFFILIATED PURCHASERS
Period
|
|
(a)
Total Number
of Shares
Purchased
(1)
|
|
(b)
Average Price
Paid per Share
|
|
(c)
Total Number of
Shares Purchased
as Part of Publicly
Announced
Program
|
|
(d)
Maximum Number of
Shares that May Yet
Be Purchased Under
the Program
(2)
|
|
07/01/10 07/31/10
|
|
86
|
|
$
|
41.14
|
|
|
|
3,072,184
|
|
08/01/10 08/31/10
|
|
8,708
|
|
$
|
41.42
|
|
|
|
3,072,184
|
|
09/01/10 09/30/10
|
|
|
|
$
|
|
|
|
|
3,072,184
|
|
Total:
|
|
8,794
|
|
$
|
41.42
|
|
|
|
3,072,184
|
|
(1)
Includes 8,794 shares withheld (under the terms of grants
under the Equity Incentive Compensation Plan) to offset tax withholding
obligations that occur upon the delivery of outstanding shares underlying
restricted stock units.
(2)
In July 2006 the Companys Board of Directors approved
an increase in the number of shares that may be repurchased under the original August 1998
authorization to 6,000,000 as of the effective date of the resolution. Accordingly, as of the date of this filing, the
Company has Board authorization to repurchase 3,072,184 shares of common stock
on a prospective basis. The shares may
be repurchased from time to time in open market transactions or privately
negotiated transactions, subject to market conditions and other factors,
including certain provisions of SM Energys existing bank credit facility
agreement and compliance with securities laws.
Stock repurchases may be funded with existing cash balances, internal
cash flow, and borrowings under SM Energys bank credit facility. The stock
repurchase program may be suspended or discontinued at any time.
The payment of dividends and stock
repurchases are subject to covenants in our bank credit facility, including the
requirement that we maintain certain levels of stockholders equity and the
limitation that does not allow our annual dividend rate to exceed $0.25 per
share.
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ITEM 6. EXHIBITS
The following exhibits are filed or
furnished with or incorporated by reference into this report:
Exhibit
|
|
Description
|
10.1
|
|
SM Energy Company Form of
Performance Share and Restricted Stock Unit Award Agreement as of
July 1, 2010 (filed as Exhibit 10.3 to the registrants Quarterly
Report on Form 10-Q for the quarter ended June 30, 2010, and
incorporated herein by reference)
|
10.2
|
|
SM Energy Company Form of
Performance Share and Restricted Stock Unit Award Notice as of July 1,
2010 (filed as Exhibit 10.4 to the registrants Quarterly Report on
Form 10-Q for the quarter ended June 30, 2010, and
incorporated herein by reference)
|
10.3****
|
|
Gas Services Agreement effective
as of July 1, 2010 between SM Energy Company and Eagle Ford Gathering
LLC
|
10.4*
|
|
SM Energy Company Employee Stock
Purchase Plan, As Amended and Restated as of July 30, 2010
|
10.5*
|
|
SM Energy Company Cash Bonus Plan,
As Amended on July 30, 2010
|
10.6*
|
|
Net Profits Interest Bonus Plan,
As Amended by the Board of Directors on July 30, 2010
|
10.7*
|
|
SM Energy Company Equity Incentive
Compensation Plan, As Amended as of July 30, 2010
|
10.8*
|
|
SM Energy Company Non-Qualified
Unfunded Supplemental Retirement Plan, As Amended as of
July 30, 2010
|
31.1*
|
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
|
31.2*
|
|
Certification of Chief Financial
Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
|
32.1**
|
|
Certification pursuant to 18
U.S.C. Section 1350 as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002
|
99.1*
|
|
Audit Committee Pre-Approval of
Non-Audit Services
|
101.INS***
|
|
XBRL Instance Document
|
101.SCH***
|
|
XBRL Schema Document
|
101.CAL***
|
|
XBRL Calculation Linkbase Document
|
101.LAB***
|
|
XBRL Label Linkbase Document
|
101.PRE***
|
|
XBRL Presentation Linkbase
Document
|
*
Filed with this report.
**
Furnished with this report.
***
Furnished, not filed. Users of this data submitted
electronically herewith are advised pursuant to Rule 406T of Regulation
S-T that this interactive data file is deemed not filed or part of a
registration statement or prospectus for purposes of sections 11 or 12 of the
Securities Act of 1933, is deemed not filed for purposes of section 18 of the
Securities Exchange Act of 1934, and otherwise is not subject to liability
under these sections.
****
Filed with this report. Certain portions of this
exhibit have been redacted and are subject to a confidential treatment request
filed with the Securities and Exchange Commission pursuant to Rule 24b-2
under the Securities Exchange Act of 1934.
Exhibit constitutes a management contract or
compensatory plan or agreement. This
document was amended on July 30, 2010 primarily to reflect the recent
change in the name of the registrant from St. Mary Land & Exploration
Company to SM Energy Company. There no
material changes to the substantive terms and conditions in this document.
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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 hereunto duly authorized.
|
SM ENERGY COMPANY
|
|
|
|
November 3, 2010
|
By:
|
/s/ ANTHONY J. BEST
|
|
|
Anthony J. Best
|
|
|
President and Chief Executive
Officer
|
|
|
|
November 3, 2010
|
By:
|
/s/ A. WADE PURSELL
|
|
|
A. Wade Pursell
|
|
|
Executive Vice President and Chief
Financial
|
|
|
Officer
|
|
|
|
November 3, 2010
|
By:
|
/s/ MARK T. SOLOMON
|
|
|
Mark T. Solomon
|
|
|
Controller
|
61
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