e10vq
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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(Mark One)
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the
quarterly period ended June 30,
2009
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission File Number:
001-33784
SANDRIDGE ENERGY,
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
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20-8084793
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
(Address of principal
executive offices)
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73102
(Zip Code)
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Registrants telephone number, including area code:
(405) 429-5500
Former name, former address and former fiscal year, if
changed since last report: Not applicable
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or
15 (d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the
past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate website, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such
files). Yes þ No o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
|
(Do not check if a smaller
reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The number of shares outstanding of the registrants common
stock, par value $0.001 per share, as of the close of business
on July 31, 2009, was 183,546,780.
SANDRIDGE
ENERGY, INC.
FORM 10-Q
Quarter Ended June 30, 2009
INDEX
2
DISCLOSURES
REGARDING FORWARD-LOOKING STATEMENTS
This quarterly report on
Form 10-Q
(Quarterly Report) includes forward-looking
statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended (Exchange
Act). Various statements contained in this Quarterly
Report, including those that express a belief, expectation, or
intention, as well as those that are not statements of
historical fact, are
forward-looking
statements. The forward-looking statements include projections
and estimates concerning, among other things, 2009 capital
expenditures, our liquidity and capital resources, the timing
and success of specific projects, outcomes and effects of
litigation, claims and disputes, and elements of our business
strategy. Our forward-looking statements are generally
accompanied by words such as estimate,
project, predict, believe,
expect, anticipate,
potential, could, may,
foresee, plan, goal or other
words that convey the uncertainty of future events or outcomes.
We have based these forward-looking statements on our current
expectations and assumptions about future events. These
statements are based on certain assumptions and analyses made by
us in light of our experience and our perception of historical
trends, current conditions and expected future developments as
well as other factors we believe are appropriate under the
circumstances. However, whether actual results and developments
will conform with our expectations and predictions is subject to
a number of risks and uncertainties, including the risk factors
discussed in Item 1A of our Annual Report on
Form 10-K
for the year ended December 31, 2008 (the 2008
Form 10-K),
the opportunities that may be pursued by us, competitive actions
by other companies, changes in laws or regulations and other
factors, many of which are beyond our control. The actual
results or developments anticipated may not be realized or, even
if substantially realized, they may not have the expected
consequences to or effects on our company or our business or
operations. The forward-looking statements contained herein are
not guarantees of future performance and actual results or
developments may differ materially from those projected in the
forward-looking statements. We undertake no obligation to
publicly update or revise any forward-looking statements.
3
PART I.
Financial Information
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ITEM 1.
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Financial
Statements
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June 30,
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December 31,
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2009
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2008
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(Unaudited)
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ASSETS
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Current assets:
|
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Cash and cash equivalents
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$
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621
|
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$
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636
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Accounts receivable, net:
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|
|
|
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Trade
|
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73,125
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102,746
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Related parties
|
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|
201
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6,327
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Derivative contracts
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207,342
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201,111
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Inventories
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3,556
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3,686
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Costs in excess of billings
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16,449
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Other current assets
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20,164
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41,407
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Total current assets
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321,458
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355,913
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Natural gas and crude oil properties, using full cost method of
accounting
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Proved
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4,996,188
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4,676,072
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Unproved
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225,369
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215,698
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Less: accumulated depreciation, depletion and impairment
|
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(3,765,118
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)
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|
|
(2,369,840
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)
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|
|
|
|
|
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|
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1,456,439
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2,521,930
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|
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Other property, plant and equipment, net
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464,463
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653,629
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Derivative contracts
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35,709
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45,537
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Investments
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7,588
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6,088
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Restricted deposits
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32,860
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32,843
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Other assets
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45,799
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39,118
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Total assets
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$
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2,364,316
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$
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3,655,058
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LIABILITIES AND EQUITY
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Current liabilities:
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Current maturities of long-term debt
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$
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15,380
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$
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16,532
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Accounts payable and accrued expenses:
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Trade
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185,452
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366,337
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Related parties
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176
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230
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Derivative contracts
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6,238
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5,106
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Asset retirement obligation
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128
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275
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Billings in excess of costs incurred
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14,144
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|
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Total current liabilities
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207,374
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402,624
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Long-term debt
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2,146,615
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2,358,784
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Other long-term obligations
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11,967
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11,963
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Derivative contracts
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|
733
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3,639
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Asset retirement obligation
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89,421
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84,497
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|
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Total liabilities
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2,456,110
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2,861,507
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Commitments and contingencies (Note 13)
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Equity:
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SandRidge Energy, Inc. stockholders equity:
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Preferred stock, $0.001 par value, 50,000 shares
authorized:
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8.5% Convertible perpetual preferred stock;
2,650 shares issued and outstanding at June 30, 2009
and no shares issued and outstanding in 2008; aggregate
liquidation preference of $265,000 at June 30, 2009
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3
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Common stock, $0.001 par value, 400,000 shares
authorized; 183,254 issued and 181,856 outstanding at
June 30, 2009 and 167,372 issued and 166,046 outstanding at
December 31, 2008
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178
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|
163
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Additional paid-in capital
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2,532,180
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2,170,986
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Treasury stock, at cost
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(19,854
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)
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|
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(19,332
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)
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Accumulated deficit
|
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|
(2,604,327
|
)
|
|
|
(1,358,296
|
)
|
|
|
|
|
|
|
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|
Total SandRidge Energy, Inc. stockholders (deficit) equity
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|
(91,820
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)
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793,521
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Noncontrolling interest
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26
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|
|
|
30
|
|
|
|
|
|
|
|
|
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Total (deficit) equity
|
|
|
(91,794
|
)
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|
793,551
|
|
|
|
|
|
|
|
|
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|
Total liabilities and equity
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$
|
2,364,316
|
|
|
$
|
3,655,058
|
|
|
|
|
|
|
|
|
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|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
4
|
|
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|
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|
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|
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Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
103,039
|
|
|
$
|
292,134
|
|
|
$
|
224,280
|
|
|
$
|
497,621
|
|
Drilling and services
|
|
|
5,176
|
|
|
|
11,957
|
|
|
|
11,571
|
|
|
|
24,291
|
|
Midstream and marketing
|
|
|
19,642
|
|
|
|
69,488
|
|
|
|
45,598
|
|
|
|
115,897
|
|
Other
|
|
|
6,242
|
|
|
|
4,471
|
|
|
|
11,663
|
|
|
|
9,327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
134,099
|
|
|
|
378,050
|
|
|
|
293,112
|
|
|
|
647,136
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
41,450
|
|
|
|
40,254
|
|
|
|
87,029
|
|
|
|
74,442
|
|
Production taxes
|
|
|
593
|
|
|
|
13,519
|
|
|
|
2,084
|
|
|
|
22,739
|
|
Drilling and services
|
|
|
6,415
|
|
|
|
5,066
|
|
|
|
12,021
|
|
|
|
12,235
|
|
Midstream and marketing
|
|
|
18,450
|
|
|
|
64,733
|
|
|
|
41,812
|
|
|
|
105,151
|
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
34,350
|
|
|
|
72,256
|
|
|
|
94,443
|
|
|
|
137,332
|
|
Depreciation, depletion and amortization other
|
|
|
14,034
|
|
|
|
15,780
|
|
|
|
26,760
|
|
|
|
33,745
|
|
Impairment
|
|
|
|
|
|
|
|
|
|
|
1,304,418
|
|
|
|
|
|
General and administrative
|
|
|
23,632
|
|
|
|
26,203
|
|
|
|
52,117
|
|
|
|
47,197
|
|
Loss (gain) on derivative contracts
|
|
|
18,992
|
|
|
|
159,768
|
|
|
|
(187,655
|
)
|
|
|
296,612
|
|
Loss (gain) on sale of assets
|
|
|
26,170
|
|
|
|
(7,734
|
)
|
|
|
26,350
|
|
|
|
(7,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
184,086
|
|
|
|
389,845
|
|
|
|
1,459,379
|
|
|
|
721,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(49,987
|
)
|
|
|
(11,795
|
)
|
|
|
(1,166,267
|
)
|
|
|
(74,606
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
188
|
|
|
|
1,333
|
|
|
|
199
|
|
|
|
2,145
|
|
Interest expense
|
|
|
(42,419
|
)
|
|
|
(22,223
|
)
|
|
|
(83,167
|
)
|
|
|
(47,395
|
)
|
Income from equity investments
|
|
|
200
|
|
|
|
556
|
|
|
|
434
|
|
|
|
1,415
|
|
Other income, net
|
|
|
483
|
|
|
|
955
|
|
|
|
1,243
|
|
|
|
939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(41,548
|
)
|
|
|
(19,379
|
)
|
|
|
(81,291
|
)
|
|
|
(42,896
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income tax benefit
|
|
|
(91,535
|
)
|
|
|
(31,174
|
)
|
|
|
(1,247,558
|
)
|
|
|
(117,502
|
)
|
Income tax benefit
|
|
|
(365
|
)
|
|
|
(10,847
|
)
|
|
|
(1,534
|
)
|
|
|
(41,385
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(91,170
|
)
|
|
|
(20,327
|
)
|
|
|
(1,246,024
|
)
|
|
|
(76,117
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
4
|
|
|
|
16
|
|
|
|
7
|
|
|
|
851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to SandRidge Energy, Inc. common
stockholders
|
|
|
(91,174
|
)
|
|
|
(20,343
|
)
|
|
|
(1,246,031
|
)
|
|
|
(76,968
|
)
|
Preferred stock dividends and accretion
|
|
|
|
|
|
|
6,650
|
|
|
|
|
|
|
|
16,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss applicable to SandRidge Energy, Inc. common stockholders
|
|
$
|
(91,174
|
)
|
|
$
|
(26,993
|
)
|
|
$
|
(1,246,031
|
)
|
|
$
|
(93,200
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share applicable to SandRidge Energy,
Inc. common stockholders
|
|
$
|
(0.52
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
(7.38
|
)
|
|
$
|
(0.63
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of SandRidge Energy, Inc. common shares
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
174,154
|
|
|
|
155,204
|
|
|
|
168,767
|
|
|
|
148,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
174,154
|
|
|
|
155,204
|
|
|
|
168,767
|
|
|
|
148,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
5
(IN THOUSANDS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SandRidge Energy, Inc. Stockholders
|
|
|
|
|
|
|
|
|
|
8.5% Convertible
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Perpetual Preferred
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
|
|
|
Common Stock
|
|
|
Paid-In
|
|
|
Treasury
|
|
|
Accumulated
|
|
|
Noncontrolling
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Stock
|
|
|
Deficit
|
|
|
Interest
|
|
|
Total
|
|
|
|
(Unaudited)
|
|
|
Six months ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
|
|
|
$
|
|
|
|
|
166,046
|
|
|
$
|
163
|
|
|
$
|
2,170,986
|
|
|
$
|
(19,332
|
)
|
|
$
|
(1,358,296
|
)
|
|
$
|
30
|
|
|
$
|
793,551
|
|
Distributions to noncontrolling interest owners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11
|
)
|
|
|
(11
|
)
|
Issuance of 8.5% convertible perpetual preferred stock
|
|
|
2,650
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
243,286
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
243,289
|
|
Issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
14,480
|
|
|
|
15
|
|
|
|
107,684
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107,699
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(522
|
)
|
|
|
|
|
|
|
|
|
|
|
(522
|
)
|
Stock-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,389
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,389
|
|
Stock-based compensation excess tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,165
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,165
|
)
|
Issuance of restricted stock awards, net of cancellations
|
|
|
|
|
|
|
|
|
|
|
1,330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,246,031
|
)
|
|
|
7
|
|
|
|
(1,246,024
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2009
|
|
|
2,650
|
|
|
$
|
3
|
|
|
|
181,856
|
|
|
$
|
178
|
|
|
$
|
2,532,180
|
|
|
$
|
(19,854
|
)
|
|
$
|
(2,604,327
|
)
|
|
$
|
26
|
|
|
$
|
(91,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
6
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(1,246,024
|
)
|
|
$
|
(76,117
|
)
|
Adjustments to reconcile net loss to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
|
|
62
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
121,203
|
|
|
|
171,077
|
|
Impairment
|
|
|
1,304,418
|
|
|
|
|
|
Debt costs amortization
|
|
|
3,677
|
|
|
|
2,445
|
|
Deferred income taxes
|
|
|
4
|
|
|
|
(42,338
|
)
|
Unrealized loss on derivative contracts
|
|
|
1,823
|
|
|
|
235,489
|
|
Loss (gain) on sale of assets
|
|
|
26,350
|
|
|
|
(7,711
|
)
|
Investment income restricted deposits
|
|
|
(17
|
)
|
|
|
(243
|
)
|
Income from equity investments
|
|
|
(434
|
)
|
|
|
(1,415
|
)
|
Stock-based compensation
|
|
|
10,368
|
|
|
|
7,260
|
|
Stock-based compensation excess tax benefit
|
|
|
(2,165
|
)
|
|
|
|
|
Changes in operating assets and liabilities
|
|
|
(77,283
|
)
|
|
|
8,387
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
141,982
|
|
|
|
296,834
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Capital expenditures for property, plant and equipment
|
|
|
(524,266
|
)
|
|
|
(934,301
|
)
|
Proceeds from sale of assets
|
|
|
253,968
|
|
|
|
153,191
|
|
Loans to unconsolidated investees
|
|
|
|
|
|
|
(4,000
|
)
|
Fundings of restricted deposits
|
|
|
|
|
|
|
(781
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(270,298
|
)
|
|
|
(785,891
|
)
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
1,431,765
|
|
|
|
1,408,000
|
|
Repayments of borrowings
|
|
|
(1,645,278
|
)
|
|
|
(665,615
|
)
|
Dividends paid preferred
|
|
|
|
|
|
|
(17,552
|
)
|
Noncontrolling interest distributions
|
|
|
(11
|
)
|
|
|
(4,059
|
)
|
Proceeds from issuance of 8.5% convertible perpetual preferred
stock
|
|
|
243,289
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
107,699
|
|
|
|
|
|
Purchase of treasury stock
|
|
|
(522
|
)
|
|
|
(1,908
|
)
|
Debt issuance costs
|
|
|
(8,641
|
)
|
|
|
(17,056
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
128,301
|
|
|
|
701,810
|
|
|
|
|
|
|
|
|
|
|
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
|
|
|
(15
|
)
|
|
|
212,753
|
|
CASH AND CASH EQUIVALENTS, beginning of period
|
|
|
636
|
|
|
|
63,135
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of period
|
|
$
|
621
|
|
|
$
|
275,888
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Noncash Investing and Financing
Activities:
|
|
|
|
|
|
|
|
|
Change in accrued capital expenditures
|
|
$
|
(79,782
|
)
|
|
$
|
|
|
Accretion on redeemable convertible preferred stock
|
|
$
|
|
|
|
$
|
7,636
|
|
The accompanying notes are an integral part of these condensed
consolidated financial statements.
7
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
(Unaudited)
Nature of Business. SandRidge Energy, Inc. and
its subsidiaries (collectively, the Company or
SandRidge) is an independent natural gas and crude
oil company concentrating on exploration, development and
production activities. The Company also owns and operates
natural gas gathering and treating facilities and
CO2
treating and transportation facilities and has marketing and
tertiary oil recovery operations. In addition, Lariat Services,
Inc. (Lariat), a wholly owned subsidiary, owns and
operates drilling rigs and a related oil field services
business. The Companys primary exploration, development
and production areas are concentrated in West Texas. The Company
also operates interests in the Mid-Continent, the Cotton Valley
Trend in East Texas, the Gulf Coast and the Gulf of Mexico.
Interim Financial Statements. The accompanying
condensed consolidated financial statements as of
December 31, 2008 have been derived from the audited
financial statements contained in the 2008
Form 10-K.
The unaudited interim condensed consolidated financial
statements have been prepared by the Company in accordance with
the accounting policies stated in the audited consolidated
financial statements contained in the 2008
Form 10-K.
Certain information and footnote disclosures normally included
in financial statements prepared in accordance with accounting
principles generally accepted in the United States of America
(GAAP) have been condensed or omitted, although the
Company believes that the disclosures contained herein are
adequate to make the information presented not misleading. In
the opinion of management, all adjustments, consisting only of
normal recurring adjustments, necessary to state fairly the
information in the Companys unaudited condensed
consolidated financial statements have been included. These
condensed consolidated financial statements should be read in
conjunction with the financial statements and notes thereto
included in the 2008
Form 10-K.
|
|
2.
|
Significant
Accounting Policies
|
For a description of the Companys significant accounting
policies, refer to Note 1 of the consolidated financial
statements included in the 2008
Form 10-K.
Reclassifications. Certain reclassifications
have been made to prior period financial statements to conform
to the current period presentation.
Recent Accounting Pronouncements. Effective
January 1, 2009, the Company implemented Statement of
Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements, for certain of its
nonfinancial liabilities, in accordance with Staff Position
FAS 157-2,
Effective Date of FASB Statement No. 157
(FSP 157-2),
which delayed the effective date of SFAS No. 157 to
fiscal years beginning after November 15, 2008 for all
nonfinancial assets and liabilities except those recognized or
disclosed at fair value in the financial statements on a
recurring basis, at least annually. This implementation did not
have a material impact on the Companys financial position
or results of operations.
Effective January 1, 2009, the Company implemented
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an Amendment of
Accounting Research Bulletin No. 51, which
established accounting and reporting standards for ownership
interests in subsidiaries held by parties other than the parent,
the amount of consolidated net income attributable to the parent
and to the noncontrolling interest, changes in a parents
ownership interest and the valuation of retained noncontrolling
equity investments when a subsidiary is deconsolidated.
SFAS No. 160 also establishes disclosure requirements
to clearly identify and distinguish between the interests of the
parent and the interests of the noncontrolling owners. The
implementation of SFAS No. 160 resulted in changes to
the presentation for noncontrolling interests and did not have a
material impact on the Companys results of operations and
financial condition. All historical periods presented in the
condensed consolidated financial statements reflect these
changes to the presentation for noncontrolling interests. See
Note 15.
Effective January 1, 2009, the Company implemented
SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities, which changed
disclosure requirements for derivative instruments and
8
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
hedging activities. SFAS No. 161 requires enhanced
disclosure, including qualitative disclosures about objectives
and strategies for using derivatives, quantitative disclosures
about fair value amounts of gains and losses on derivative
instruments and disclosures about credit-risk-related contingent
features in derivative agreements. The implementation of
SFAS No. 161 did not have a material impact on the
Companys financial position or results of operations. See
Note 10.
Effective for the period ended June 30, 2009, the Company
implemented Financial Accounting Standards Board
(FASB) Staff Position
FAS 107-1
and APB
28-1,
Interim Disclosures about Fair Value of Financial
Instruments (FSP
FAS 107-1
and APB
28-1),
which amends SFAS No. 107, Disclosures about
Fair Value of Financial Instruments, and Accounting
Principles Board Opinion 28, Interim Financial
Reporting, to require disclosures about fair value of
financial instruments for interim reporting periods of publicly
traded companies as well as in annual financial statements. The
implementation of FSP
FAS 107-1
and APB 28-1
resulted in additional disclosure about the fair value of the
Companys financial instruments and did not have an impact
on the Companys financial position or results of
operations. See Note 3.
Effective for the period ended June 30, 2009, the Company
implemented SFAS No. 165, Subsequent
Events, which establishes general standards of accounting
for and disclosure of events that occur after the balance sheet
date but before the financial statements are issued or available
to be issued. See Note 17.
On December 31, 2008, the Securities and Exchange
Commission (SEC) issued Release
No. 33-8995,
Modernization of Oil and Gas Reporting, which
revises disclosure requirements for oil and gas companies. In
addition to changing the definition and disclosure requirements
for natural gas and crude oil reserves, the new rules change the
requirements for determining natural gas and crude oil reserve
quantities to permit the use of new technologies to determine
proved reserves under certain criteria and allow companies to
disclose their probable and possible reserves. The new rules
also require companies to report the independence and
qualifications of their reserves preparer or auditor and file
reports when a third party is relied upon to prepare reserves
estimates or when a third party conducts a reserves audit. The
new rules also require natural gas and crude oil reserves to be
reported and the full cost ceiling limitation to be calculated
using a twelve-month average price rather than period-end
prices. The use of a twelve-month average price could have had
an effect on the Companys 2008 and 2009 depletion rates
for its natural gas and crude oil properties. The new rules are
effective for annual reports on
Form 10-K
for fiscal years ending on or after December 31, 2009,
pending the contemplated alignment of certain accounting
standards by the FASB with the new rules. The Company plans to
implement the new requirements beginning in its Annual Report on
Form 10-K
for the year ended December 31, 2009. The Company is
currently evaluating the impact of the new requirements on its
consolidated financial statements.
In June 2009, the FASB issued SFAS No. 168, The
FASB Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principles.
SFAS No. 168 replaces SFAS No. 162,
The Hierarchy of Generally Accepted Accounting
Principles, and establishes the FASB Accounting Standards
Codification as the source of authoritative accounting
principles recognized by the FASB to be applied by
non-governmental entities in the preparation of financial
statements in conformity with GAAP. SFAS No. 168 is
effective for interim and annual periods ending after
September 15, 2009. The Company plans to implement this
standard in its September 30, 2009 financial statements.
The implementation of SFAS No. 168 is not expected to
have a material impact on the Companys financial position
or results of operations.
|
|
3.
|
Fair
Value Measurements
|
Effective January 1, 2008, the Company implemented
SFAS No. 157 for its financial assets and liabilities
measured on a recurring basis. SFAS No. 157 applies to
all assets and liabilities that are measured and reported on a
fair value basis. Effective January 1, 2009, the Company
implemented SFAS No. 157 for certain nonfinancial
liabilities based on
FSP 157-2,
which delayed the effective date of SFAS No. 157 by
one year for certain nonfinancial assets and liabilities, with
no material impact to the Companys financial position or
results of operations as a result of this implementation.
9
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
As defined in SFAS No. 157, fair value is the price
that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants
at the measurement date. SFAS No. 157 requires
disclosure that establishes a framework for measuring fair value
and expands disclosure about fair value measurements. The
statement requires fair value measurements be classified and
disclosed in one of the following categories:
|
|
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible
at the measurement date for identical, unrestricted assets or
liabilities. |
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which
are observable, either directly or indirectly, for substantially
the full term of the asset or liability. |
|
Level 3: |
|
Measurement based on prices or valuation models that require
inputs that are both significant to the fair value measurement
and less observable for objective sources (i.e., supported by
little or no market activity). |
As required by SFAS No. 157, assets and liabilities
measured at fair value are classified based on the lowest level
of input that is significant to the fair value measurement. The
Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, which may
affect the valuation of the fair value of assets and liabilities
and their placement within the fair value hierarchy levels. The
determination of the fair values, stated below, takes into
account the market for the Companys financial assets and
liabilities, the associated credit risk and other factors as
required under SFAS No. 157. The Company considers
active markets as those in which transactions for the assets or
liabilities occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Fair
Value of Derivative Contracts
As required by SFAS No. 157, the Company has
classified its derivative contracts into one of three levels
based upon the data relied upon to determine the fair value. The
fair values of the Companys natural gas and crude oil
swaps and interest rate swaps are based upon quotes obtained
from counterparties to the derivative contracts. The Company
reviews other readily available market prices for its derivative
contracts as there is an active market for these contracts.
However, the Company does not have access to the specific
valuation models used by its counterparties or other market
participants. Included in these models are discount factors that
the Company must estimate in its calculation. Additionally, the
Company applies a value weighted average credit default risk
rating factor for its counterparties in determining the fair
value of its derivative contracts. Based on the inputs for the
fair value measurement, the Company classified its derivative
contract assets and liabilities as Level 3.
The following table summarizes the Companys financial
assets and liabilities measured at fair value on a recurring
basis by SFAS No. 157 pricing levels as of
June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets/
|
|
|
|
Fair Value Measurements Using:
|
|
|
Liabilities at
|
|
Description
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Fair Value
|
|
|
|
(In thousands)
|
|
|
Derivative assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
243,051
|
|
|
$
|
243,051
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
(6,971
|
)
|
|
|
(6,971
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
236,080
|
|
|
$
|
236,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
The tables below set forth a reconciliation of the
Companys derivative contracts measured at fair value using
significant unobservable inputs (Level 3) during the
three and six months ended June 30, 2009 (in thousands):
|
|
|
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
|
Balance at March 31, 2009
|
|
$
|
345,913
|
|
Total gains or losses (realized/unrealized)
|
|
|
(16,351
|
)
|
Purchases, issuances and settlements
|
|
|
(93,482
|
)
|
Transfers in and/or out of Level 3
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2009
|
|
$
|
236,080
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2009
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
237,903
|
|
Total gains or losses (realized/unrealized)
|
|
|
189,009
|
|
Purchases, issuances and settlements
|
|
|
(190,832
|
)
|
Transfers in and/or out of Level 3
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2009
|
|
$
|
236,080
|
|
|
|
|
|
|
Changes in unrealized gains (losses) on derivative contracts
held as of June 30, 2009
|
|
$
|
1,823
|
|
|
|
|
|
|
See Note 10 for further discussion of the Companys
derivative contracts.
Fair
Value of Debt
The Company measures fair value of its long-term debt in
accordance with SFAS No. 157, giving consideration to
the effect of the Companys credit risk. The estimated fair
value of the Companys senior notes, based on quoted market
prices, and the carrying value at June 30, 2009 were as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
Carrying Value
|
|
|
Senior Floating Rate Notes due 2014
|
|
$
|
277,304
|
|
|
$
|
350,000
|
|
8.625% Senior Notes due 2015
|
|
|
583,011
|
|
|
|
650,000
|
|
9.875% Senior Notes due 2016, net of discount
|
|
|
355,918
|
|
|
|
350,242
|
|
8.0% Senior Notes due 2018
|
|
|
646,934
|
|
|
|
750,000
|
|
The Companys carrying value for its senior credit facility
and remaining fixed rate debt instruments approximate fair value
based on current rates applicable to similar instruments. See
Note 8 for further discussion of the Companys
long-term debt.
11
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
|
|
4.
|
Property,
Plant and Equipment
|
Property, plant and equipment consists of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Natural gas and crude oil properties:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
4,996,188
|
|
|
$
|
4,676,072
|
|
Unproved
|
|
|
225,369
|
|
|
|
215,698
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil properties
|
|
|
5,221,557
|
|
|
|
4,891,770
|
|
Less accumulated depreciation, depletion and impairment(1)
|
|
|
(3,765,118
|
)
|
|
|
(2,369,840
|
)
|
|
|
|
|
|
|
|
|
|
Net natural gas and crude oil properties capitalized costs
|
|
|
1,456,439
|
|
|
|
2,521,930
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
13,937
|
|
|
|
11,250
|
|
Non natural gas and crude oil equipment(2)
|
|
|
563,358
|
|
|
|
764,792
|
|
Buildings and structures
|
|
|
85,066
|
|
|
|
71,859
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
662,361
|
|
|
|
847,901
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(197,898
|
)
|
|
|
(194,272
|
)
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
|
464,463
|
|
|
|
653,629
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
1,920,902
|
|
|
$
|
3,175,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes cumulative full cost ceiling limitation impairment
charges of $3,159.4 million and $1,855.0 million at
June 30, 2009 and December 31, 2008, respectively. |
|
(2) |
|
The amount of capitalized interest included in the above non
natural gas and crude oil equipment balance at both
June 30, 2009 and December 31, 2008 was approximately
$3.8 million. |
In 2009, the asset lives of certain drilling, oil field
services, midstream and other assets were changed to align with
industry average lives for similar assets.
Sale of Midstream Assets. In June 2009, the
Company completed the sale of its gathering and compression
assets located in the Piñon Field, part of the West Texas
Overthrust (WTO) located in Pecos and Terrell
counties, Texas. Net proceeds to the Company were approximately
$197.5 million. The sale resulted in a loss of
approximately $26.5 million. In conjunction with the sale,
the Company entered into a gas gathering agreement and an
operations and maintenance agreement. Under the gas gathering
agreement, the Company has dedicated its Piñon Field
acreage for priority gathering services for a period of twenty
years and the Company will pay a fee that was negotiated at
arms length for such services. Pursuant to the operations
and maintenance agreement, the Company will operate and maintain
the gathering system assets sold for a period of twenty years
unless the Company or the buyer of the assets chooses to
terminate the agreement.
Sale of East Texas Deep Rights. In June 2009,
the Company completed the sale of its drilling rights in East
Texas below the depth of the Cotton Valley formation for net
proceeds of approximately $55.9 million, subject to certain
post-closing adjustments. The sale of the deep rights was
accounted for as an adjustment to the full cost pool with no
gain or loss recognized.
Under the full cost method of accounting, the net book value of
natural gas and crude oil properties, less related deferred
income taxes, may not exceed a calculated ceiling.
The ceiling limitation is the discounted estimated after-tax
future net revenue from proved natural gas and crude oil
properties, excluding future cash outflows associated with
settling asset retirement obligations included in the net book
value of natural gas and crude oil
12
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
properties, plus the cost of properties not subject to
amortization. In calculating future net revenues, prices and
costs used are those as of the end of the appropriate period.
These prices are not changed except where different prices are
fixed and determinable from applicable contracts for the
remaining term of those contracts. The Company has entered into
various commodity derivative contracts; however, these
derivative contracts are not accounted for as cash flow hedges.
Accordingly, the effect of these derivative contracts has not
been considered in calculating the full cost ceiling limitation
as of June 30, 2009.
The net book value, less related deferred tax liabilities, is
compared to the ceiling limitation on a quarterly and annual
basis. Any excess of the net book value, less related deferred
taxes, is written off as an expense. An expense recorded in one
period may not be reversed in a subsequent period even though
higher natural gas and crude oil prices may have increased the
ceiling limitation in the subsequent period.
During the first quarter of 2009, the Company reduced the
carrying value of its natural gas and crude oil properties by
$1,304.4 million due to the full cost ceiling limitation.
As the full cost ceiling exceeded the net capitalized costs at
June 30, 2009, there was no such reduction of the
Companys carrying value of its natural gas and crude oil
properties during the second quarter of 2009.
|
|
6.
|
Costs in
Excess of Billings (Billings in Excess of Costs
Incurred)
|
In June 2008, the Company entered into an agreement with a
subsidiary of Occidental Petroleum Corporation
(Occidental) to construct a
CO2
treating plant (the Century Plant) and associated
compression and pipeline facilities for $800.0 million. The
Company will construct the Century Plant and Occidental will pay
a minimum of 100% of the contract price, plus any subsequent
agreed-upon
revisions, to the Company through periodic cost reimbursements
based upon the percentage of the project completed by the
Company. Upon
start-up,
the Century Plant, located in Pecos County, Texas, will be owned
and operated by Occidental for the purpose of separating and
removing
CO2
from natural gas delivered by the Company. Pursuant to a
thirty-year treating agreement executed simultaneously with the
construction agreement, Occidental will remove
CO2
from the Companys delivered production volumes. The
Company will retain all methane gas from the Century Plant.
The Company accounts for construction of the Century Plant using
the completed-contract method, under which contract revenues and
costs are recognized when work under the contract is completed
or substantially completed. In the interim, costs incurred on
and billings related to contracts in process are accumulated on
the balance sheet. Provisions for a contract loss are recognized
when it is determined that a loss will be incurred. Costs in
excess of billings (billings in excess of costs incurred) were
$16.4 million and ($14.1) million and were reported as
a current asset and current liability in the condensed
consolidated balance sheets at June 30, 2009 and
December 31, 2008, respectively.
|
|
7.
|
Asset
Retirement Obligation
|
A reconciliation of the beginning and ending aggregate carrying
amounts of the asset retirement obligation for the period from
December 31, 2008 to June 30, 2009 is as follows (in
thousands):
|
|
|
|
|
Asset retirement obligation, December 31, 2008
|
|
$
|
84,772
|
|
Liability incurred upon acquiring and drilling wells
|
|
|
1,409
|
|
Revisions in estimated cash flows
|
|
|
(162
|
)
|
Liability settled in current period
|
|
|
|
|
Accretion of discount expense
|
|
|
3,530
|
|
|
|
|
|
|
Asset retirement obligation, June 30, 2009
|
|
|
89,549
|
|
Less: Current portion
|
|
|
128
|
|
|
|
|
|
|
Asset retirement obligation, net of current
|
|
$
|
89,421
|
|
|
|
|
|
|
13
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Long-term debt consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Senior credit facility
|
|
$
|
18,000
|
|
|
$
|
573,457
|
|
Other notes payable:
|
|
|
|
|
|
|
|
|
Drilling rig fleet and related crude oil field services equipment
|
|
|
25,360
|
|
|
|
33,030
|
|
Mortgage
|
|
|
18,393
|
|
|
|
18,829
|
|
Senior Floating Rate Notes due 2014
|
|
|
350,000
|
|
|
|
350,000
|
|
8.625% Senior Notes due 2015
|
|
|
650,000
|
|
|
|
650,000
|
|
9.875% Senior Notes due 2016, net of $15,258 discount
|
|
|
350,242
|
|
|
|
|
|
8.0% Senior Notes due 2018
|
|
|
750,000
|
|
|
|
750,000
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
2,161,995
|
|
|
|
2,375,316
|
|
Less: Current maturities of long-term debt
|
|
|
15,380
|
|
|
|
16,532
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
2,146,615
|
|
|
$
|
2,358,784
|
|
|
|
|
|
|
|
|
|
|
For the three months ended June 30, 2009 and 2008, interest
payments, net of amounts capitalized, were approximately
$65.4 million and $25.4 million, respectively. For the
six months ended June 30, 2009 and 2008, interest payments,
net of amounts capitalized, were approximately
$75.4 million and $50.8 million, respectively.
Senior Credit Facility. The amount the Company
can borrow under its senior secured revolving credit facility
(the senior credit facility) is limited to a
borrowing base, which was $985.4 million at June 30,
2009. The senior credit facility matures on November 21,
2011 and is available to be drawn on and repaid so long as the
Company is in compliance with its terms, including certain
financial covenants as fully described below.
The senior credit facility contains various covenants that limit
the ability of the Company and certain of its subsidiaries to
grant certain liens; make certain loans and investments; make
distributions; redeem stock; redeem or prepay debt; merge or
consolidate with or into a third party; or engage in certain
asset dispositions, including a sale of all or substantially all
of the Companys assets. Additionally, the senior credit
facility limits the ability of the Company and certain of its
subsidiaries to incur additional indebtedness with certain
exceptions, including under the series of senior notes discussed
below.
The senior credit facility contains financial covenants,
including maintaining agreed levels for the (i) ratio of
total funded debt to EBITDAX (as defined in the senior credit
facility), which may not exceed 4.5:1.0 calculated using the
last four completed fiscal quarters, (ii) ratio of EBITDAX
to interest expense plus current maturities of long-term debt,
which must be at least 2.5:1.0 calculated using the last four
completed fiscal quarters, and (iii) ratio of current
assets to current liabilities, which must be at least 1.0:1.0.
In the current ratio calculation (as defined in the senior
credit facility) any amounts available to be drawn under the
senior credit facility are included in current assets, and
unrealized assets and liabilities resulting from
mark-to-market
adjustments on the Companys derivative contracts are
disregarded. As of June 30, 2009, the Company was in
compliance with all of the financial covenants under the senior
credit facility.
The obligations under the senior credit facility are guaranteed
by certain Company subsidiaries and are secured by first
priority liens on all shares of capital stock of each of the
Companys material present and future subsidiaries; all
intercompany debt of the Company; and substantially all of the
Companys assets, including proved natural gas and crude
oil reserves representing at least 80% of the discounted present
value (as defined in the senior credit facility) of proved
natural gas and crude oil reserves reviewed in determining the
borrowing base for the senior credit facility.
14
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
At the Companys election, interest under the senior credit
facility is determined by reference to (a) the London
Interbank Offered Rate (LIBOR) plus an applicable
margin between 2.00% and 3.00% per annum, or (b) the
base rate, which is the higher of (i) the
federal funds rate plus 0.5%, (ii) the prime rate published
by Bank of America or (iii) the Eurodollar rate (as defined
in the senior credit facility) plus 1.00% per annum, plus, in
each case under scenario (b), an applicable margin between 1.00%
and 2.00% per annum. Interest is payable quarterly for prime
rate loans and at the applicable maturity date for LIBOR loans,
except that if the interest period for a LIBOR loan is six
months, interest is paid at the end of each three-month period.
The average annual interest rates paid on amounts outstanding
under the senior credit facility were 2.68% and 2.28% for the
three months and six months ended June 30, 2009,
respectively.
The Companys borrowing base is redetermined in April and
October of each year. With respect to each redetermination, the
administrative agent and the lenders under the senior credit
facility consider several factors, including the Companys
proved reserves and projected cash requirements, and make
assumptions regarding, among other things, natural gas and crude
oil prices and production. Accordingly, the Companys
ability to develop its properties and changes in commodity
prices impact the borrowing base. The borrowing base remained
unchanged at $1.1 billion as a result of the April 2009
redetermination; however, the issuance of the 9.875% Senior
Notes due 2016 (discussed below) in May 2009 caused the
borrowing base to be reduced to $985.4 million. The Company
has incurred additional costs related to the senior credit
facility as a result of changes to the borrowing base. These
costs have been deferred and are included in other assets in the
accompanying condensed consolidated balance sheets. At
June 30, 2009, the Company had $18.0 million
outstanding under the senior credit facility along with
$24.5 million in outstanding letters of credit.
On October 3, 2008, Lehman Brothers Commodity Services,
Inc. (Lehman Brothers), a lender under the
Companys senior credit facility, filed for bankruptcy. At
the time that its parent, Lehman Brothers Holdings Inc.,
declared bankruptcy on September 15, 2008, Lehman Brothers
elected not to fund its pro rata share, or 0.29%, of borrowings
requested by the Company under the senior credit facility.
Accordingly, the Company does not anticipate that Lehman
Brothers will fund its pro rata share of any future borrowing
requests. The Company does not expect this reduced availability
of amounts under the senior credit facility to impact its
liquidity or business operations.
Other Notes Payable. The Company has financed
a portion of its drilling rig fleet and related oil field
services equipment through the issuance of notes secured by the
equipment. At June 30, 2009, the aggregate outstanding
balance of these notes was $25.4 million, with annual fixed
interest rates ranging from 7.64% to 8.67%. The notes have a
final maturity date of December 1, 2011 and require
aggregate monthly installments of principal and interest in the
amount of $1.2 million. The notes have a prepayment penalty
(currently ranging from 0.50% to 2.00%) that is triggered if the
Company repays the notes prior to maturity.
The debt incurred to purchase the downtown Oklahoma City
property that serves as the Companys corporate
headquarters is fully secured by a mortgage on one of the
buildings and a parking garage located on the property. The note
underlying the mortgage bears interest at 6.08% annually and
matures on November 15, 2022. Payments of principal and
interest in the amount of approximately $0.5 million are
due on a quarterly basis through the maturity date. During 2009,
the Company expects to make payments of principal and interest
on this note totaling $0.9 million and $1.1 million,
respectively.
Senior Floating Rate Notes Due 2014 and 8.625% Senior
Notes Due 2015. In May 2008, pursuant to an
exchange offer exempted from registration under the Securities
Act of 1933, as amended (the Securities Act), the
Company exchanged its senior term loans for senior unsecured
notes with registration rights which were subsequently exchanged
for substantially identical notes pursuant to an exchange offer
registered under the Securities Act. The effect of the exchange
offers resulted in the Company issuing $350.0 million of
Senior Floating Rate Notes due 2014 (Senior Floating Rate
Notes) in exchange for the total outstanding principal
amount of its senior floating rate term loan and
$650.0 million of 8.625% Senior Notes due 2015
(8.625% Senior Notes) in exchange for the total
outstanding principal amount of its 8.625% senior term
loan. Terms of these senior notes are
15
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
substantially identical to those of the exchanged senior term
loans and the terms of the unregistered notes for which the
senior term loans were exchanged. These senior notes are jointly
and severally, unconditionally guaranteed on an unsecured basis
by all of the Companys wholly owned subsidiaries, except
certain minor subsidiaries. See Note 19 for condensed
consolidating financial information of the subsidiary guarantors.
The Senior Floating Rate Notes bear interest at LIBOR plus
3.625% (4.83% at June 30, 2009), except for the period from
April 1, 2008 to June 30, 2008, for which the interest
rate was 6.323%. Interest is payable quarterly with principal
due on April 1, 2014. The average interest rates paid on
outstanding Senior Floating Rate Notes for the three months and
six months ended June 30, 2009 were 4.83% and 4.95%,
respectively, without consideration of the interest rate swap
discussed below. The 8.625% Senior Notes bear interest at a
fixed rate of 8.625% per annum with the principal due on
April 1, 2015. Under the terms of the 8.625% Senior
Notes, interest is payable semi-annually and, through the
interest payment due on April 1, 2011, interest may be
paid, at the Companys option, either entirely in cash or
entirely with additional fixed rate senior notes. If the Company
elects to pay the interest due during any period in additional
fixed rate senior notes, the interest rate will increase to
9.375% during that period. All interest payments made to date on
the 8.625% Senior Notes have been paid in cash.
In January 2008, the Company entered into a $350.0 million
notional interest rate swap agreement to fix the variable LIBOR
interest rate on the floating rate senior term loan for the
period from April 1, 2008 to April 1, 2011. As a
result of the exchange of the floating rate senior term loan to
Senior Floating Rate Notes, the interest rate swap is now used
to fix the variable LIBOR interest rate on the Senior Floating
Rate Notes at an annual rate of 6.26% through April 1,
2011. In May 2009, the Company entered into a
$350.0 million notional interest rate swap agreement to fix
the variable LIBOR interest rate on the Senior Floating Rate
Notes at an annual rate of 6.69% for the period from
April 1, 2011 to April 1, 2013. The two interest rate
swaps effectively serve to fix the Companys variable
interest rate on its Senior Floating Rate Notes for the majority
of the term of these notes. These swaps have not been designated
as hedges.
The Company may redeem, at specified redemption prices, some or
all of the Senior Floating Rate Notes at any time and some or
all of the 8.625% Senior Notes on or after April 1,
2011.
The Company incurred $26.1 million of debt issuance costs
in connection with the senior term loans. As the senior term
loans were exchanged for unsecured senior notes with
substantially identical terms, the remaining unamortized debt
issuance costs on the senior term loans will be amortized over
the terms of the Senior Floating Rate Notes and the
8.625% Senior Notes. These costs are included in other
assets in the accompanying condensed consolidated balance sheets.
9.875% Senior Notes Due 2016. In May
2009, the Company completed a private placement of
$365.5 million of unsecured 9.875% Senior Notes due
2016 (9.875% Senior Notes) to qualified
institutional investors eligible under Rule 144A of the
Securities Act. These notes were issued at a discount which will
be amortized into interest expense over the term of the notes.
Net proceeds from the offering were approximately
$342.2 million after deducting offering expenses of
$7.8 million. The Company used the net proceeds from the
offering to repay outstanding borrowings under the senior credit
facility and for general corporate purposes. The notes bear
interest at a fixed rate of 9.875% per annum, payable
semi-annually, with the principal due on May 15, 2016. The
9.875% Senior Notes are redeemable, in whole or in part,
prior to their maturity at specified redemption prices. The
notes are jointly and severally, unconditionally guaranteed on
an unsecured basis by all of the Companys wholly owned
subsidiaries, except certain minor subsidiaries. See
Note 19 for condensed consolidated financial information of
the subsidiary guarantors. The notes will become freely tradable
180 days after their issuance, pursuant to Rule 144
under the Securities Act.
Debt issuance costs of $7.8 million incurred in connection
with the offering of the 9.875% Senior Notes are included
in other assets in the condensed consolidated balance sheet and
are being amortized over the term of the notes.
16
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
8.0% Senior Notes Due 2018. In May 2008,
the Company issued $750.0 million of unsecured
8.0% Senior Notes due 2018 (8.0% Senior
Notes). The notes bear interest at a fixed rate of 8.0%
per annum, payable
semi-annually,
with the principal due on June 1, 2018. The notes are
redeemable, in whole or in part, prior to their maturity at
specified redemption prices. The 8.0% Senior Notes are
jointly and severally, unconditionally guaranteed on an
unsecured basis, by all of the Companys wholly owned
subsidiaries, except certain minor subsidiaries. See
Note 19 for condensed consolidated financial information of
the subsidiary guarantors. The notes became freely tradable on
November 17, 2008, 180 days after their issuance,
pursuant to Rule 144 under the Securities Act.
The Company incurred $16.0 million of debt issuance costs
in connection with the offering of the 8.0% Senior Notes.
These costs are included in other assets in the condensed
consolidated balance sheet and amortized over the term of the
notes.
The indentures governing all of the senior notes contain
financial covenants similar to those of the senior credit
facility and include limitations on the incurrence of
indebtedness, payment of dividends, investments, asset sales,
certain asset purchases, transactions with related parties and
consolidations or mergers. As of June 30, 2009, the Company
was in compliance with all of the covenants contained in the
indentures governing the senior notes.
|
|
9.
|
Other
Long-Term Obligations
|
The Company has recorded a long-term obligation for amounts to
be paid under a settlement agreement with Conoco, Inc. entered
into in January 2007. The Company agreed to pay approximately
$25.0 million plus interest, payable in $5.0 million
increments on April 1, 2007, July 1, 2008,
July 1, 2009, July 1, 2010 and July 1, 2011. The
payment to be made on July 1, 2009 has been included in
accounts payable-trade in the accompanying condensed
consolidated balance sheets at June 30, 2009 and
December 31, 2008. The non-current unpaid settlement amount
of $10.0 million has been included in other long-term
obligations in the accompanying condensed consolidated balance
sheets at June 30, 2009 and December 31, 2008.
The Companys derivative contracts have not been designated
as hedges. The Company records all derivative contracts, which
include commodity derivatives and interest rate swaps, at fair
value. Changes in derivative contract fair values are recognized
in earnings. Cash settlements and valuation gains and losses are
included in loss (gain) on derivative contracts for the
commodity derivative contracts and in interest expense for the
interest rate swaps in the consolidated statements of
operations. Commodity derivative contracts are settled on a
monthly basis. Settlements on the interest rate swaps occur
quarterly. Derivative assets and liabilities arising from the
Companys derivative contracts with the same counterparty
that provide for net settlement are reported on a net basis in
the consolidated balance sheet.
Commodity Derivatives. The Company is exposed
to commodity price risk, which impacts the predictability of its
cash flows related to the sale of natural gas and crude oil and
is managed by the Companys use of commodity derivative
contracts. These derivative contracts allow the Company to limit
its exposure to a portion of its projected natural gas and crude
oil sales. None of the Companys derivative contracts may
be terminated early as a result of a party having its credit
rating downgraded. At June 30, 2009 and December 31,
2008, the Companys commodity derivative contracts
consisted of fixed price swaps and basis swaps, which are
described below:
|
|
|
Fixed price swaps
|
|
The Company receives a fixed price for the contract and pays a
floating market price to the counterparty over a specified
period for a contracted volume.
|
|
|
|
Basis swaps
|
|
The Company receives a payment from the counterparty if the
settled price differential is greater than the stated terms of
the contract and pays the counterparty if the settled price
differential is less than the stated terms of the contract,
which guarantees the Company a price differential for natural
gas from a specified delivery point.
|
17
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Interest Rate Swaps. The Company is exposed to
interest rate risk on its long-term fixed and variable interest
rate borrowings. Fixed rate debt, where the interest rate is
fixed over the life of the instrument, exposes the Company to
(i) changes in market interest rates reflected in the fair
value of the debt and (ii) the risk that the Company may
need to refinance maturing debt with new debt at a higher rate.
Variable rate debt, where the interest rate fluctuates, exposes
the Company to short-term changes in market interest rates as
the Companys interest obligations on these instruments are
periodically redetermined based on prevailing market interest
rates, primarily LIBOR and the federal funds rate.
The Company has entered into two interest rate swap agreements
to manage the interest rate risk on a portion of its floating
rate debt by effectively fixing the variable interest rate on
its Senior Floating Rate Notes. See Note 8 for further
discussion of the Companys interest rate swaps.
Fair Value of Derivatives. The balance sheet
classification of assets and liabilities related to derivative
contracts is summarized below at June 30, 2009 and
December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet
|
|
Fair Value
|
|
Type of Contract
|
|
Classification
|
|
June 30, 2009
|
|
|
December 31, 2008
|
|
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
Natural gas swaps
|
|
Derivative assets-current
|
|
$
|
202,430
|
|
|
$
|
188,045
|
|
Crude oil price swaps
|
|
Derivative assets-current
|
|
|
4,912
|
|
|
|
13,066
|
|
Natural gas swaps
|
|
Derivative assets-noncurrent
|
|
|
34,557
|
|
|
|
45,537
|
|
Interest rate swaps
|
|
Derivative assets-noncurrent
|
|
|
1,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative assets
|
|
|
|
$
|
243,051
|
|
|
$
|
246,648
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
|
Derivative liabilities-current
|
|
$
|
6,238
|
|
|
$
|
5,106
|
|
Natural gas basis swaps
|
|
Derivative liabilities-noncurrent
|
|
|
733
|
|
|
|
3,639
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative liabilities
|
|
|
|
$
|
6,971
|
|
|
$
|
8,745
|
|
|
|
|
|
|
|
|
|
|
|
|
A counterparty to one of the Companys derivative
contracts, Lehman Brothers, declared bankruptcy on
October 3, 2008. Due to Lehman Brothers bankruptcy
and the declaration of bankruptcy by its parent,
Lehman Brothers Holdings Inc., on September 15, 2008,
the Company has not assigned any value to this derivative
contract as of June 30, 2009.
The following table summarizes the effect of the Companys
derivative contracts on the condensed consolidated statements of
operations for the three and six-month periods ended
June 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of (Gain) Loss Recognized in Income
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
Location of (Gain) Loss
|
|
June 30,
|
|
|
June 30,
|
|
Type of Contract
|
|
Recognized in Income
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Interest rate swap
|
|
Interest expense
|
|
$
|
(2,641
|
)
|
|
$
|
(9,643
|
)
|
|
$
|
(1,354
|
)
|
|
$
|
(10,449
|
)
|
Natural gas and crude oil swaps
|
|
Loss (gain) on derivative contracts
|
|
|
18,992
|
|
|
|
159,768
|
|
|
|
(187,655
|
)
|
|
|
296,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
$
|
16,351
|
|
|
$
|
150,125
|
|
|
$
|
(189,009
|
)
|
|
$
|
286,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
The following table summarizes the cash settlements and
valuation gains and losses on commodity derivative contracts for
the three and six-month periods ended June 30, 2009 and
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Realized (gain) loss
|
|
$
|
(94,747
|
)
|
|
$
|
58,003
|
|
|
$
|
(193,136
|
)
|
|
$
|
50,674
|
|
Unrealized loss
|
|
|
113,739
|
|
|
|
101,765
|
|
|
|
5,481
|
|
|
|
245,938
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss (gain) on derivative contracts
|
|
$
|
18,992
|
|
|
$
|
159,768
|
|
|
$
|
(187,655
|
)
|
|
$
|
296,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gains of $2.6 million ($3.9 million unrealized
gain and $1.3 million realized losses) and
$1.4 million ($3.7 million unrealized gain and
$2.3 million realized losses) related to the interest rate
swaps discussed above were included in interest expense in the
condensed consolidated statement of operations for the three
months and six months ended June 30, 2009, respectively.
Unrealized gains of $9.6 million and $10.4 million
were included in the condensed consolidated statements of
operations for the three months and six months ended
June 30, 2008, respectively.
See Note 3 for additional discussion on the fair value
measurement of the Companys derivative contracts.
19
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Open Derivative Contracts. At June 30,
2009, the Companys open natural gas and crude oil
commodity derivative contracts consisted of the following:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(MMcf)(1)
|
|
|
Fixed Price
|
|
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
18,710
|
|
|
$
|
8.09
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
19,010
|
|
|
$
|
8.46
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
January 2010 March 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,475
|
|
|
$
|
7.95
|
|
Basis swap contracts
|
|
|
20,250
|
|
|
$
|
(0.74
|
)
|
April 2010 June 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
19,793
|
|
|
$
|
7.32
|
|
Basis swap contracts
|
|
|
20,475
|
|
|
$
|
(0.74
|
)
|
July 2010 September 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,010
|
|
|
$
|
7.55
|
|
Basis swap contracts
|
|
|
20,700
|
|
|
$
|
(0.74
|
)
|
October 2010 December 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,010
|
|
|
$
|
7.97
|
|
Basis swap contracts
|
|
|
20,700
|
|
|
$
|
(0.74
|
)
|
January 2011 March 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
25,650
|
|
|
$
|
(0.47
|
)
|
April 2011 June 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
25,935
|
|
|
$
|
(0.47
|
)
|
July 2011 September 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
26,220
|
|
|
$
|
(0.47
|
)
|
October 2011 December 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
26,220
|
|
|
$
|
(0.47
|
)
|
January 2012 March 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,020
|
|
|
$
|
(0.54
|
)
|
April 2012 June 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,020
|
|
|
$
|
(0.54
|
)
|
July 2012 September 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,240
|
|
|
$
|
(0.54
|
)
|
October 2012 December 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,240
|
|
|
$
|
(0.54
|
)
|
|
|
|
(1) |
|
Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total
notional of 3,680 MMcf from 2009 contracts for the Lehman
Brothers basis swap contract. |
20
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Crude
Oil
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(in MBbls)
|
|
|
Fixed Price
|
|
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.61
|
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.51
|
|
In accordance with GAAP, the Company estimates for each interim
reporting period the effective tax rate expected for the full
fiscal year and uses that estimated rate in providing income
taxes on a current
year-to-date
basis.
The provisions (benefits) for income taxes consisted of the
following components for the three and six-month periods ended
June 30 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(50
|
)
|
|
$
|
|
|
|
$
|
(2,220
|
)
|
|
$
|
|
|
State
|
|
|
(315
|
)
|
|
|
945
|
|
|
|
682
|
|
|
|
1,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(365
|
)
|
|
|
945
|
|
|
|
(1,538
|
)
|
|
|
1,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
|
|
|
|
(10,749
|
)
|
|
|
4
|
|
|
|
(41,236
|
)
|
State
|
|
|
|
|
|
|
(1,043
|
)
|
|
|
|
|
|
|
(1,173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,792
|
)
|
|
|
4
|
|
|
|
(42,409
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total benefits
|
|
$
|
(365
|
)
|
|
$
|
(10,847
|
)
|
|
$
|
(1,534
|
)
|
|
$
|
(41,385
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts
used for income tax reporting. Deferred tax assets are reduced
by a valuation allowance if a determination is made that it is
more likely than not that some or all of the deferred assets
will not be realized based on the weight of all available
evidence. For the year ended December 31, 2008, the Company
determined it was appropriate to record a full valuation
allowance against its net deferred tax asset. For the six-month
period ended June 30, 2009, the Company recorded a
$438.5 million increase to the previously established
valuation allowance. The increase is primarily a result of not
recording a tax benefit for the current period loss before
income taxes of $1,247.6 million.
Internal Revenue Code (IRC) Section 382
addresses company ownership changes and specifically limits the
utilization of certain tax attributes on an annual basis
following an ownership change. The Company has experienced
several owner shifts, within the meaning of IRC
Section 382, since the time of its last ownership change,
which occurred in June 2008. Further owner shifts occurring
during the three-year period beginning as of June 2008 may
result in another ownership change. In the event another
ownership change occurs, the application of IRC Section 382
may limit the amount of tax attributes, including the 2009
projected net operating loss, that the Company can utilize on an
annual basis. The Company will continue to closely monitor its
ownership activity.
No reserves for uncertain income tax positions have been
recorded pursuant to FASB Interpretation No. 48
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109
(FIN 48). Tax
21
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
years 1994 to present remain open for the majority of taxing
authorities due to net operating loss utilization. The
Companys accounting policy is to recognize interest and
penalties, if any, related to unrecognized tax benefits as
income tax expense. The Company does not have an accrued
liability for interest and penalties at June 30, 2009.
For the three-month period ended June 30, 2009 and 2008,
income tax payments, net of refunds, were approximately
$3.6 million and $1.7 million, respectively. For the
six-month period ended June 30, 2009 and 2008, income tax
payments, net of refunds, were approximately $3.0 million
and $1.9 million, respectively.
|
|
12.
|
Earnings
(Loss) Per Share
|
Basic earnings per share are computed using the weighted average
number of common shares outstanding during the period. Diluted
earnings per share are computed using the weighted average
shares outstanding during the period, but also include the
dilutive effect of awards of restricted stock and outstanding
convertible preferred stock. The following table summarizes the
calculation of weighted average common shares outstanding used
in the computation of diluted earnings per share, for the three
and six-month periods ended June 30, 2009 and 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Weighted average basic common shares outstanding
|
|
|
174,154
|
|
|
|
155,204
|
|
|
|
168,767
|
|
|
|
148,124
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible preferred stock outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common and potential common shares
outstanding
|
|
|
174,154
|
|
|
|
155,204
|
|
|
|
168,767
|
|
|
|
148,124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three-month periods ended June 30, 2009 and 2008,
restricted stock awards covering 2.4 million shares and
1.3 million shares, respectively, were excluded from the
computation of net loss per share because their effect would
have been antidilutive. For the six-month periods ended
June 30, 2009 and 2008, restricted stock awards covering
2.5 million shares and 1.3 million shares,
respectively, were excluded from the computation of net loss per
share because their effect would have been antidilutive.
In computing diluted earnings per share, the Company evaluated
the if-converted method with respect to its outstanding 8.5%
convertible perpetual preferred stock for the three and
six-month periods ended June 30, 2009 and with respect to
its then outstanding redeemable convertible preferred stock for
the three and six-month periods ended June 30, 2008. Under
this method, the Company assumes the conversion of the preferred
stock to common stock and determines if this is more dilutive
than including the preferred stock dividends (paid and unpaid)
in the computation of income available to common stockholders.
The Company determined the if-converted method is not more
dilutive for the three and six-month periods ended June 30,
2009 and 2008.
|
|
13.
|
Commitments
and Contingencies
|
The Company is a defendant in lawsuits from time to time in the
normal course of business. In managements opinion, the
Company is not currently involved in any legal proceedings that,
individually or in the aggregate, could have a material effect
on the financial condition, results of operations or cash flows
of the Company.
|
|
14.
|
Redeemable
Convertible Preferred Stock
|
In November 2006, the Company sold 2,136,667 shares of
redeemable convertible preferred stock to finance a portion of
its acquisition of NEG Oil & Gas, LLC. Each holder of
redeemable convertible preferred stock was entitled to quarterly
cash dividends at the annual rate of 7.75% of the accreted
value, or $210 per share, of their
22
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
redeemable convertible preferred stock. Each share of redeemable
convertible preferred stock was initially convertible into ten
shares, and ultimately convertible into 10.2 shares, of
common stock at the option of the holder. A summary of dividends
declared and paid on the redeemable convertible preferred stock
is as follows (in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
Declared
|
|
Dividend Period
|
|
per Share
|
|
|
Total
|
|
|
Payment Date
|
|
January 31, 2007
|
|
November 21, 2006 February 1, 2007
|
|
$
|
3.21
|
|
|
$
|
6,859
|
|
|
February 15, 2007
|
May 8, 2007
|
|
February 2, 2007 May 1, 2007
|
|
|
3.97
|
|
|
|
8,550
|
|
|
May 15, 2007
|
June 8, 2007
|
|
May 2, 2007 August 1, 2007
|
|
|
4.10
|
|
|
|
8,956
|
|
|
August 15, 2007
|
September 24, 2007
|
|
August 2, 2007 November 1, 2007
|
|
|
4.10
|
|
|
|
8,956
|
|
|
November 15, 2007
|
December 16, 2007
|
|
November 2, 2007 February 1, 2008
|
|
|
4.10
|
|
|
|
8,956
|
|
|
February 15, 2008
|
March 7, 2008
|
|
February 2, 2008 May 1, 2008
|
|
|
4.01
|
|
|
|
8,095
|
|
|
(1)
|
May 7, 2008
|
|
May 2, 2008 May 7, 2008
|
|
|
4.01
|
|
|
|
501
|
|
|
May 7, 2008
|
|
|
|
(1) |
|
Includes $0.6 million of prorated dividends paid to holders
of redeemable convertible preferred shares at the time their
shares converted to common stock in March 2008. The remaining
dividends of $7.5 million were paid during May 2008. |
On March 30, 2007, certain holders of the Companys
common units (consisting of shares of common stock and a warrant
to purchase redeemable convertible preferred stock upon the
surrender of common stock) exercised warrants to purchase
redeemable convertible preferred stock. The holders converted
526,316 shares of common stock into 47,619 shares of
redeemable convertible preferred stock.
During March 2008, holders of 339,823 shares of the
Companys redeemable convertible preferred stock elected to
convert those shares into 3,465,593 shares of the
Companys common stock. Additionally, during May 2008, the
Company converted the remaining outstanding
1,844,464 shares of its redeemable convertible preferred
stock into 18,810,260 shares of its common stock as
permitted under the terms of the redeemable convertible
preferred stock. These conversions resulted in increases to
additional paid-in capital totaling $452.2 million, which
represents the difference between the par value of the common
stock issued and the carrying value of the redeemable
convertible shares converted. The Company also recorded charges
to retained earnings totaling $7.2 million in accelerated
accretion expense related to the converted redeemable
convertible preferred shares. Prorated dividends totaling
$0.5 million for the period from May 2, 2008 to the
date of conversion (May 7, 2008) were paid to the
holders of the converted shares on May 7, 2008. On and
after the conversion date, dividends ceased to accrue and the
rights of common unit holders to exercise outstanding warrants
to purchase redeemable convertible preferred shares terminated.
Approximately $0.5 million and $8.6 million in paid
and unpaid dividends on the redeemable convertible preferred
stock has been included in the Companys earnings per share
calculations for the three-month period and six-month period
ended June 30, 2008, respectively, as presented in the
condensed consolidated statements of operations.
Preferred Stock. The following table presents
information regarding the Companys preferred stock (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Shares authorized
|
|
|
50,000
|
|
|
|
50,000
|
|
Shares outstanding at end of period
|
|
|
2,650
|
|
|
|
|
|
23
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
In January 2009, the Company completed a private placement of
2,650,000 shares of 8.5% convertible perpetual preferred
stock to qualified institutional investors eligible under
Rule 144A under the Securities Act. The offering included
400,000 shares of convertible perpetual preferred stock
issued upon the full exercise of the initial purchasers
option to cover over-allotments. Net proceeds from the offering
were approximately $243.3 million after deducting offering
expenses of approximately $8.6 million. The Company used
the net proceeds from the offering to repay outstanding
borrowings under the senior credit facility and for general
corporate purposes.
Each share of 8.5% convertible perpetual preferred stock has a
liquidation preference of $100 and is convertible at the
holders option at any time initially into approximately
12.4805 shares of the Companys common stock, subject
to adjustments upon the occurrence of certain events. Each
holder of the convertible perpetual preferred stock is entitled
to an annual dividend of $8.50 per share to be paid
semi-annually in cash, common stock or a combination thereof at
the Companys election, with the first dividend payment due
in February 2010. The convertible perpetual preferred stock is
not redeemable by the Company at any time. After
February 20, 2014, the Company may cause all outstanding
shares of the convertible perpetual preferred stock to
automatically convert into common stock at the then-prevailing
conversion rate if certain conditions are met.
Common Stock. The following table presents
information regarding the Companys common stock (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Shares authorized
|
|
|
400,000
|
|
|
|
400,000
|
|
Shares outstanding at end of period
|
|
|
181,856
|
|
|
|
166,046
|
|
Shares held in treasury
|
|
|
1,398
|
|
|
|
1,326
|
|
During March 2008, the Company issued 3,465,593 shares of
common stock upon the conversion of 339,823 shares of its
redeemable convertible preferred stock. In May 2008, the Company
converted the remaining 1,844,464 outstanding shares of its
redeemable convertible preferred stock into
18,810,260 shares of its common stock as permitted under
the terms of the redeemable convertible preferred stock. See
additional discussion in Note 14.
In April 2009, the Company completed a registered underwritten
offering of 14,480,000 shares of its common stock,
including 2,280,000 shares of common stock acquired by the
underwriters from the Company to cover over-allotments. Net
proceeds to the Company from the offering were approximately
$107.7 million, after deducting offering expenses of
approximately $2.3 million, and were used to repay a
portion of the amount outstanding under the senior credit
facility and for general corporate purposes.
Treasury Stock. The Company makes required tax
payments on behalf of employees when their restricted stock
awards vest and then withholds a number of vested shares of
common stock having a value on the date of vesting equal to the
tax obligation. As a result of such transactions, the Company
withheld approximately 71,000 shares having a total value
of $0.5 million and approximately 52,000 shares having
a total value of $1.9 million during the six-month periods
ended June 30, 2009 and 2008, respectively. These shares
were accounted for as treasury stock.
In February 2008, the Company transferred 184,484 shares of
its treasury stock into an account established for the benefit
of the Companys 401(k) Plan. The transfer was made in
order to satisfy the Companys $5.0 million accrued
payable to match employee contributions made to the plan during
2007. The historical cost of the shares transferred totaled
approximately $2.4 million and resulted in an increase to
the Companys additional paid-in capital of approximately
$2.6 million.
Equity Compensation. The Company awards
restricted common stock under incentive compensation plans, and
such awards vest over specified periods of time, subject to
certain conditions. Awards issued prior to 2006 had vesting
periods of one, four or seven years. All awards issued during
and after 2006 have four year vesting periods.
24
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Shares of restricted common stock are subject to restriction on
transfer. Unvested restricted stock awards are included in the
Companys outstanding shares of common stock.
For the three-month and six-month periods ended June 30,
2009, the Company recognized stock-based compensation expense of
$5.2 million and $10.4 million, net of
$0.8 million and $2.0 million capitalized,
respectively, related to restricted common stock. For the
three-month and six-month periods ended June 30, 2008, the
Company recognized stock-based compensation expense of
$4.1 million and $7.3 million, respectively, related
to restricted common stock. There was no stock-based
compensation capitalized in 2008. Stock-based compensation
expense is reflected in general and administrative expenses in
the condensed consolidated statements of operations.
Effective June 5, 2009, the Company adopted the SandRidge
Energy, Inc. 2009 Incentive Plan (the 2009 Incentive
Plan). Under the terms of the 2009 Incentive Plan, the
Company may grant stock options, stock appreciation rights,
shares of restricted stock, restricted stock units and other
forms of awards based on the value (or increase in the value) of
shares of the common stock of the Company for up to
12,000,000 shares of common stock. The 2009 Incentive Plan
also permits cash incentive awards. Consistent with the prior
plan, the Company intends for shares of restricted stock to be
the primary form of awards granted under the 2009 Incentive Plan.
Noncontrolling Interest. On January 1,
2009, the Company implemented SFAS No. 160, which
established accounting and reporting standards for ownership
interests in subsidiaries held by parties other than the parent,
the amount of consolidated net income attributable to the parent
and to the noncontrolling interest, changes in a parents
ownership interest and the valuation of retained noncontrolling
equity investments when a subsidiary is deconsolidated. As
required by SFAS No. 160, the noncontrolling interest
in one of the Companys subsidiaries represents an
ownership interest in the consolidated entity and is included as
a component of equity in the condensed consolidated balance
sheets and condensed consolidated statement of changes in equity.
|
|
16.
|
Related
Party Transactions
|
The Company has transactions with certain stockholders and other
related parties in the ordinary course of business. These
transactions primarily consist of purchases of drilling
equipment and sales of oil field service supplies. Following is
a summary of significant transactions with such related parties
for the three and six-month periods ended June 30, 2009 and
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Sales to and reimbursements from related parties
|
|
$
|
974
|
|
|
$
|
27,070
|
|
|
$
|
4,406
|
|
|
$
|
52,426
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of services from related parties
|
|
$
|
5,464
|
|
|
$
|
19,171
|
|
|
$
|
14,406
|
|
|
$
|
39,061
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company leases office space in Oklahoma City from a member
of its Board of Directors. The Company believes that the
payments made under this lease are at fair market rates. Rent
expense related to the lease totaled $0.2 million and
$0.3 million for the three-month periods ended
June 30, 2009 and 2008, respectively. For the six-month
periods ended June 30, 2009 and 2008, rent expense under
this lease was $0.5 million and $0.7 million,
respectively. The lease expires in August 2009.
Larclay, L.P. Until April 15, 2009,
Lariat and its partner Clayton Williams Energy, Inc.
(CWEI) each owned a 50% interest in Larclay L.P.
(Larclay), a limited partnership, and, until such
time, Lariat operated the rigs owned by the partnership. On
April 15, 2009, Lariat completed an assignment to CWEI of
Lariats 50% equity interest in Larclay pursuant to the
terms of an Assignment and Assumption Agreement (the
Larclay Assignment) entered into between Lariat and
CWEI on March 13, 2009. Pursuant to the Larclay Assignment,
Lariat assigned all of its right, title and interest in and to
Larclay to CWEI effective April 15, 2009, and CWEI assumed
all of the obligations and liabilities of Lariat relating to
Larclay from and after April 15, 2009. The Company fully
impaired
25
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
both the investment in and notes receivable due from Larclay at
December 31, 2008. There were no additional losses on
Larclay during the three or six-month period ended June 30,
2009 or as a result of the Larclay Assignment.
The following table summarizes the Companys other
transactions with Larclay for the three and six-month periods
ended June 30, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Sales to and reimbursements from Larclay
|
|
$
|
214
|
|
|
$
|
12,035
|
|
|
$
|
2,962
|
|
|
$
|
22,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of services from Larclay
|
|
$
|
|
|
|
$
|
13,288
|
|
|
$
|
1,762
|
|
|
$
|
23,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Accounts receivable from Larclay
|
|
$
|
5
|
|
|
$
|
6,060
|
|
Accounts payable to Larclay
|
|
$
|
|
|
|
$
|
152
|
|
Events occurring after June 30, 2009 were evaluated as of
August 6, 2009, the date this Quarterly Report was issued,
in compliance with SFAS No. 165 to ensure that any
subsequent events that met the criteria for recognition
and/or
disclosure in this report have been included. No such events
were noted.
|
|
18.
|
Business
Segment Information
|
The Company has three business segments: exploration and
production, drilling and oil field services and midstream gas
services. These segments represent the Companys three main
business units, each offering different products and services.
The exploration and production segment is engaged in the
acquisition, development and production of natural gas and crude
oil properties. The drilling and oil field services segment is
engaged in the land contract drilling of natural gas and crude
oil wells. The midstream gas services segment is engaged in the
purchasing, gathering, processing, treating and selling of
natural gas. The all other column in the tables below includes
items not related to the Companys reportable segments
including the Companys
CO2
gathering and sales operations and corporate operations.
26
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Management evaluates the performance of the Companys
business segments based on operating income, which is defined as
segment operating revenues less operating expenses and
depreciation, depletion and amortization. Summarized financial
information concerning the Companys segments is shown in
the following table (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Drilling and Oil
|
|
|
Midstream Gas
|
|
|
|
|
|
Consolidated
|
|
|
|
Production
|
|
|
Field Services
|
|
|
Services
|
|
|
All Other
|
|
|
Total
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
103,727
|
|
|
$
|
55,975
|
|
|
$
|
71,838
|
|
|
$
|
6,511
|
|
|
$
|
238,051
|
|
Inter-segment revenue
|
|
|
(64
|
)
|
|
|
(50,877
|
)
|
|
|
(52,742
|
)
|
|
|
(269
|
)
|
|
|
(103,952
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
103,663
|
|
|
$
|
5,098
|
|
|
$
|
19,096
|
|
|
$
|
6,242
|
|
|
$
|
134,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$
|
(5,248
|
)
|
|
$
|
(2,801
|
)
|
|
$
|
(28,030
|
)
|
|
$
|
(13,908
|
)
|
|
$
|
(49,987
|
)
|
Interest expense, net
|
|
|
(41,387
|
)
|
|
|
(558
|
)
|
|
|
|
|
|
|
(286
|
)
|
|
|
(42,231
|
)
|
Other income, net
|
|
|
483
|
|
|
|
|
|
|
|
200
|
|
|
|
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
$
|
(46,152
|
)
|
|
$
|
(3,359
|
)
|
|
$
|
(27,830
|
)
|
|
$
|
(14,194
|
)
|
|
$
|
(91,535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures(2)
|
|
$
|
121,347
|
|
|
$
|
188
|
|
|
$
|
17,340
|
|
|
$
|
8,813
|
|
|
$
|
147,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
35,025
|
|
|
$
|
6,909
|
|
|
$
|
2,115
|
|
|
$
|
4,335
|
|
|
$
|
48,384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
293,472
|
|
|
$
|
108,720
|
|
|
$
|
219,819
|
|
|
$
|
5,653
|
|
|
$
|
627,664
|
|
Inter-segment revenue
|
|
|
(44
|
)
|
|
|
(96,856
|
)
|
|
|
(151,523
|
)
|
|
|
(1,191
|
)
|
|
|
(249,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
293,428
|
|
|
$
|
11,864
|
|
|
$
|
68,296
|
|
|
$
|
4,462
|
|
|
$
|
378,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(6,545
|
)
|
|
$
|
4,644
|
|
|
$
|
6,553
|
|
|
$
|
(16,447
|
)
|
|
$
|
(11,795
|
)
|
Interest expense, net
|
|
|
(19,823
|
)
|
|
|
(770
|
)
|
|
|
|
|
|
|
(297
|
)
|
|
|
(20,890
|
)
|
Other income (expense), net
|
|
|
848
|
|
|
|
(109
|
)
|
|
|
664
|
|
|
|
108
|
|
|
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(25,520
|
)
|
|
$
|
3,765
|
|
|
$
|
7,217
|
|
|
$
|
(16,636
|
)
|
|
$
|
(31,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures(2)
|
|
$
|
459,135
|
|
|
$
|
17,870
|
|
|
$
|
38,203
|
|
|
$
|
7,993
|
|
|
$
|
523,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
72,998
|
|
|
$
|
9,344
|
|
|
$
|
3,359
|
|
|
$
|
2,335
|
|
|
$
|
88,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Drilling and Oil
|
|
|
Midstream Gas
|
|
|
|
|
|
Consolidated
|
|
|
|
Production
|
|
|
Field Services
|
|
|
Services
|
|
|
All Other
|
|
|
Total
|
|
|
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
225,660
|
|
|
$
|
149,789
|
|
|
$
|
166,205
|
|
|
$
|
12,407
|
|
|
$
|
554,061
|
|
Inter-segment revenue
|
|
|
(130
|
)
|
|
|
(138,380
|
)
|
|
|
(121,695
|
)
|
|
|
(744
|
)
|
|
|
(260,949
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
225,530
|
|
|
$
|
11,409
|
|
|
$
|
44,510
|
|
|
$
|
11,663
|
|
|
$
|
293,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss(1)
|
|
$
|
(1,101,110
|
)
|
|
$
|
(5,556
|
)
|
|
$
|
(27,820
|
)
|
|
$
|
(31,781
|
)
|
|
$
|
(1,166,267
|
)
|
Interest expense, net
|
|
|
(81,205
|
)
|
|
|
(1,191
|
)
|
|
|
|
|
|
|
(572
|
)
|
|
|
(82,968
|
)
|
Other income, net
|
|
|
1,243
|
|
|
|
|
|
|
|
434
|
|
|
|
|
|
|
|
1,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
$
|
(1,181,072
|
)
|
|
$
|
(6,747
|
)
|
|
$
|
(27,386
|
)
|
|
$
|
(32,353
|
)
|
|
$
|
(1,247,558
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures(2)
|
|
$
|
383,231
|
|
|
$
|
2,201
|
|
|
$
|
41,288
|
|
|
$
|
17,764
|
|
|
$
|
444,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
95,785
|
|
|
$
|
14,195
|
|
|
$
|
3,957
|
|
|
$
|
7,266
|
|
|
$
|
121,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,894,446
|
|
|
$
|
246,173
|
|
|
$
|
109,640
|
|
|
$
|
114,057
|
|
|
$
|
2,364,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
500,438
|
|
|
$
|
188,558
|
|
|
$
|
368,054
|
|
|
$
|
11,507
|
|
|
$
|
1,068,557
|
|
Inter-segment revenue
|
|
|
(88
|
)
|
|
|
(164,372
|
)
|
|
|
(254,671
|
)
|
|
|
(2,290
|
)
|
|
|
(421,421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
500,350
|
|
|
$
|
24,186
|
|
|
$
|
113,383
|
|
|
$
|
9,217
|
|
|
$
|
647,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(53,934
|
)
|
|
$
|
2,496
|
|
|
$
|
6,585
|
|
|
$
|
(29,753
|
)
|
|
$
|
(74,606
|
)
|
Interest expense, net
|
|
|
(43,235
|
)
|
|
|
(1,412
|
)
|
|
|
|
|
|
|
(603
|
)
|
|
|
(45,250
|
)
|
Other income, net
|
|
|
780
|
|
|
|
109
|
|
|
|
1,306
|
|
|
|
159
|
|
|
|
2,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(96,389
|
)
|
|
$
|
1,193
|
|
|
$
|
7,891
|
|
|
$
|
(30,197
|
)
|
|
$
|
(117,502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures(2)
|
|
$
|
813,900
|
|
|
$
|
35,791
|
|
|
$
|
69,429
|
|
|
$
|
15,181
|
|
|
$
|
934,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
138,588
|
|
|
$
|
21,692
|
|
|
$
|
6,133
|
|
|
$
|
4,664
|
|
|
$
|
171,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,986,070
|
|
|
$
|
275,164
|
|
|
$
|
284,281
|
|
|
$
|
109,543
|
|
|
$
|
3,655,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The operating loss for the exploration and production segment
for the six-month period ended June 30, 2009 includes a
$1,304.4 million non-cash full cost ceiling impairment on
the Companys natural gas and crude oil properties. |
|
(2) |
|
Capital expenditures are presented on an accrual basis. |
|
|
19.
|
Condensed
Consolidating Financial Information
|
The Company is providing condensed consolidating financial
information for its subsidiaries that are guarantors of its
registered debt. Subsidiary guarantors are wholly owned and
have, jointly and severally, unconditionally guaranteed on an
unsecured basis the Companys 8.625% Senior Notes and
Senior Floating Rate Notes. The subsidiary guarantees
(i) rank equally in right of payment with all of the
existing and future senior debt of the subsidiary guarantors;
(ii) rank senior to all of the existing and future
subordinated debt of the subsidiary
28
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
guarantors; (iii) are effectively subordinated in right of
payment to any existing or future secured obligations of the
subsidiary guarantors to the extent of the value of the assets
securing such obligations; and (iv) are structurally
subordinated to all debt and other obligations of the
subsidiaries of the guarantors who are not themselves guarantors.
The Company has not presented separate financial and narrative
information for each of the subsidiary guarantors because it
believes that such financial and narrative information would not
provide any additional information that would be material in
evaluating the sufficiency of the guarantees.
Effective May 1, 2009, SandRidge Energy, Inc., the parent,
contributed all of its rights, title and interest in its natural
gas and crude oil related assets and accompanying liabilities to
one of its wholly owned subsidiaries, leaving it with no natural
gas or crude oil related assets or operations.
The following condensed consolidating financial information
represents the financial information of SandRidge Energy, Inc.
and its wholly owned subsidiary guarantors, prepared on the
equity basis of accounting. The non-guarantor subsidiaries are
minor and, therefore, not presented separately. The information
is presented in accordance with the requirements of
Rule 3-10
under the SECs
Regulation S-X.
The financial information may not necessarily be indicative of
the financial position, results of operations, or cash flows had
the subsidiary guarantors operated as independent entities.
29
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Condensed
Consolidating Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
162
|
|
|
$
|
459
|
|
|
$
|
|
|
|
$
|
621
|
|
Accounts and notes receivable, net
|
|
|
58,417
|
|
|
|
364,633
|
|
|
|
(349,724
|
)
|
|
|
73,326
|
|
Derivative contracts
|
|
|
|
|
|
|
207,342
|
|
|
|
|
|
|
|
207,342
|
|
Other current assets
|
|
|
|
|
|
|
40,169
|
|
|
|
|
|
|
|
40,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
58,579
|
|
|
|
612,603
|
|
|
|
(349,724
|
)
|
|
|
321,458
|
|
Property, plant and equipment, net
|
|
|
|
|
|
|
1,920,902
|
|
|
|
|
|
|
|
1,920,902
|
|
Investment in subsidiaries
|
|
|
2,249,681
|
|
|
|
|
|
|
|
(2,249,681
|
)
|
|
|
|
|
Other assets
|
|
|
44,548
|
|
|
|
128,792
|
|
|
|
(51,384
|
)
|
|
|
121,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,352,808
|
|
|
$
|
2,662,297
|
|
|
$
|
(2,650,789
|
)
|
|
$
|
2,364,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
320,147
|
|
|
$
|
215,205
|
|
|
$
|
(349,724
|
)
|
|
$
|
185,628
|
|
Other current liabilities
|
|
|
6,238
|
|
|
|
15,508
|
|
|
|
|
|
|
|
21,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
326,385
|
|
|
|
230,713
|
|
|
|
(349,724
|
)
|
|
|
207,374
|
|
Long-term debt
|
|
|
2,118,243
|
|
|
|
79,756
|
|
|
|
(51,384
|
)
|
|
|
2,146,615
|
|
Asset retirement obligation
|
|
|
|
|
|
|
89,421
|
|
|
|
|
|
|
|
89,421
|
|
Other liabilities
|
|
|
|
|
|
|
12,700
|
|
|
|
|
|
|
|
12,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,444,628
|
|
|
|
412,590
|
|
|
|
(401,108
|
)
|
|
|
2,456,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Deficit) equity
|
|
|
(91,820
|
)
|
|
|
2,249,707
|
|
|
|
(2,249,681
|
)
|
|
|
(91,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
2,352,808
|
|
|
$
|
2,662,297
|
|
|
$
|
(2,650,789
|
)
|
|
$
|
2,364,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
18
|
|
|
$
|
618
|
|
|
$
|
|
|
|
$
|
636
|
|
Accounts and notes receivable, net
|
|
|
863,129
|
|
|
|
66,463
|
|
|
|
(820,519
|
)
|
|
|
109,073
|
|
Derivative contracts
|
|
|
201,111
|
|
|
|
|
|
|
|
|
|
|
|
201,111
|
|
Other current assets
|
|
|
3,194
|
|
|
|
41,899
|
|
|
|
|
|
|
|
45,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,067,452
|
|
|
|
108,980
|
|
|
|
(820,519
|
)
|
|
|
355,913
|
|
Property, plant and equipment, net
|
|
|
1,106,623
|
|
|
|
2,068,936
|
|
|
|
|
|
|
|
3,175,559
|
|
Investment in subsidiaries
|
|
|
1,002,336
|
|
|
|
|
|
|
|
(1,002,336
|
)
|
|
|
|
|
Other assets
|
|
|
135,161
|
|
|
|
39,809
|
|
|
|
(51,384
|
)
|
|
|
123,586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,311,572
|
|
|
$
|
2,217,725
|
|
|
$
|
(1,874,239
|
)
|
|
$
|
3,655,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
163,068
|
|
|
$
|
1,024,018
|
|
|
$
|
(820,519
|
)
|
|
$
|
366,567
|
|
Other current liabilities
|
|
|
5,106
|
|
|
|
30,951
|
|
|
|
|
|
|
|
36,057
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
168,174
|
|
|
|
1,054,969
|
|
|
|
(820,519
|
)
|
|
|
402,624
|
|
Long-term debt
|
|
|
2,323,458
|
|
|
|
86,710
|
|
|
|
(51,384
|
)
|
|
|
2,358,784
|
|
Asset retirement obligation
|
|
|
12,759
|
|
|
|
71,738
|
|
|
|
|
|
|
|
84,497
|
|
Other liabilities
|
|
|
13,660
|
|
|
|
1,942
|
|
|
|
|
|
|
|
15,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
2,518,051
|
|
|
|
1,215,359
|
|
|
|
(871,903
|
)
|
|
|
2,861,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
793,521
|
|
|
|
1,002,366
|
|
|
|
(1,002,336
|
)
|
|
|
793,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
$
|
3,311,572
|
|
|
$
|
2,217,725
|
|
|
$
|
(1,874,239
|
)
|
|
$
|
3,655,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Condensed
Consolidating Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
9,588
|
|
|
$
|
124,558
|
|
|
$
|
(47
|
)
|
|
$
|
134,099
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
5,561
|
|
|
|
87,564
|
|
|
|
(47
|
)
|
|
|
93,078
|
|
General and administrative
|
|
|
5,152
|
|
|
|
18,480
|
|
|
|
|
|
|
|
23,632
|
|
Depreciation, depletion, amortization and impairment
|
|
|
4,689
|
|
|
|
43,695
|
|
|
|
|
|
|
|
48,384
|
|
(Gain) loss on derivative contracts
|
|
|
(30,704
|
)
|
|
|
49,696
|
|
|
|
|
|
|
|
18,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
(15,302
|
)
|
|
|
199,435
|
|
|
|
(47
|
)
|
|
|
184,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
24,890
|
|
|
|
(74,877
|
)
|
|
|
|
|
|
|
(49,987
|
)
|
Equity earnings from subsidiaries
|
|
|
(75,008
|
)
|
|
|
|
|
|
|
75,008
|
|
|
|
|
|
Interest expense, net
|
|
|
(41,421
|
)
|
|
|
(810
|
)
|
|
|
|
|
|
|
(42,231
|
)
|
Other income, net
|
|
|
|
|
|
|
683
|
|
|
|
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income tax benefit
|
|
|
(91,539
|
)
|
|
|
(75,004
|
)
|
|
|
75,008
|
|
|
|
(91,535
|
)
|
Income tax benefit
|
|
|
(365
|
)
|
|
|
|
|
|
|
|
|
|
|
(365
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(91,174
|
)
|
|
|
(75,004
|
)
|
|
|
75,008
|
|
|
|
(91,170
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to SandRidge Energy, Inc.
|
|
$
|
(91,174
|
)
|
|
$
|
(75,008
|
)
|
|
$
|
75,008
|
|
|
$
|
(91,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
104,294
|
|
|
$
|
275,013
|
|
|
$
|
(1,257
|
)
|
|
$
|
378,050
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
20,010
|
|
|
|
97,085
|
|
|
|
(1,257
|
)
|
|
|
115,838
|
|
General and administrative
|
|
|
10,130
|
|
|
|
16,073
|
|
|
|
|
|
|
|
26,203
|
|
Depreciation, depletion, and amortization
|
|
|
29,007
|
|
|
|
59,029
|
|
|
|
|
|
|
|
88,036
|
|
Loss on derivative contracts
|
|
|
159,768
|
|
|
|
|
|
|
|
|
|
|
|
159,768
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
218,915
|
|
|
|
172,187
|
|
|
|
(1,257
|
)
|
|
|
389,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(114,621
|
)
|
|
|
102,826
|
|
|
|
|
|
|
|
(11,795
|
)
|
Equity earnings from subsidiaries
|
|
|
103,440
|
|
|
|
|
|
|
|
(103,440
|
)
|
|
|
|
|
Interest expense, net
|
|
|
(20,002
|
)
|
|
|
(888
|
)
|
|
|
|
|
|
|
(20,890
|
)
|
Other (expense) income, net
|
|
|
(7
|
)
|
|
|
1,518
|
|
|
|
|
|
|
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income tax benefit
|
|
|
(31,190
|
)
|
|
|
103,456
|
|
|
|
(103,440
|
)
|
|
|
(31,174
|
)
|
Income tax benefit
|
|
|
(10,847
|
)
|
|
|
|
|
|
|
|
|
|
|
(10,847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(20,343
|
)
|
|
|
103,456
|
|
|
|
(103,440
|
)
|
|
|
(20,327
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to SandRidge Energy, Inc.
|
|
$
|
(20,343
|
)
|
|
$
|
103,440
|
|
|
$
|
(103,440
|
)
|
|
$
|
(20,343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
58,271
|
|
|
$
|
236,946
|
|
|
$
|
(2,105
|
)
|
|
$
|
293,112
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
27,737
|
|
|
|
143,664
|
|
|
|
(2,105
|
)
|
|
|
169,296
|
|
General and administrative
|
|
|
15,515
|
|
|
|
36,602
|
|
|
|
|
|
|
|
52,117
|
|
Depreciation, depletion, amortization and impairment
|
|
|
627,478
|
|
|
|
798,143
|
|
|
|
|
|
|
|
1,425,621
|
|
(Gain) loss on derivative contracts
|
|
|
(237,351
|
)
|
|
|
49,696
|
|
|
|
|
|
|
|
(187,655
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
433,379
|
|
|
|
1,028,105
|
|
|
|
(2,105
|
)
|
|
|
1,459,379
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(375,108
|
)
|
|
|
(791,159
|
)
|
|
|
|
|
|
|
(1,166,267
|
)
|
Equity earnings from subsidiaries
|
|
|
(791,369
|
)
|
|
|
|
|
|
|
791,369
|
|
|
|
|
|
Interest expense, net
|
|
|
(81,190
|
)
|
|
|
(1,778
|
)
|
|
|
|
|
|
|
(82,968
|
)
|
Other income, net
|
|
|
102
|
|
|
|
1,575
|
|
|
|
|
|
|
|
1,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income tax benefit
|
|
|
(1,247,565
|
)
|
|
|
(791,362
|
)
|
|
|
791,369
|
|
|
|
(1,247,558
|
)
|
Income tax benefit
|
|
|
(1,534
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,534
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
|
(1,246,031
|
)
|
|
|
(791,362
|
)
|
|
|
791,369
|
|
|
|
(1,246,024
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to SandRidge Energy, Inc.
|
|
$
|
(1,246,031
|
)
|
|
$
|
(791,369
|
)
|
|
$
|
791,369
|
|
|
$
|
(1,246,031
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
168,610
|
|
|
$
|
480,893
|
|
|
$
|
(2,367
|
)
|
|
$
|
647,136
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses
|
|
|
35,523
|
|
|
|
173,700
|
|
|
|
(2,367
|
)
|
|
|
206,856
|
|
General and administrative
|
|
|
17,300
|
|
|
|
29,897
|
|
|
|
|
|
|
|
47,197
|
|
Depreciation, depletion, and amortization
|
|
|
51,936
|
|
|
|
119,141
|
|
|
|
|
|
|
|
171,077
|
|
Loss on derivative contracts
|
|
|
296,612
|
|
|
|
|
|
|
|
|
|
|
|
296,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
401,371
|
|
|
|
322,738
|
|
|
|
(2,367
|
)
|
|
|
721,742
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income from operations
|
|
|
(232,761
|
)
|
|
|
158,155
|
|
|
|
|
|
|
|
(74,606
|
)
|
Equity earnings from subsidiaries
|
|
|
158,081
|
|
|
|
|
|
|
|
(158,081
|
)
|
|
|
|
|
Interest expense, net
|
|
|
(43,610
|
)
|
|
|
(1,640
|
)
|
|
|
|
|
|
|
(45,250
|
)
|
Other (expense) income, net
|
|
|
(63
|
)
|
|
|
2,417
|
|
|
|
|
|
|
|
2,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income tax benefit
|
|
|
(118,353
|
)
|
|
|
158,932
|
|
|
|
(158,081
|
)
|
|
|
(117,502
|
)
|
Income tax benefit
|
|
|
(41,385
|
)
|
|
|
|
|
|
|
|
|
|
|
(41,385
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
|
(76,968
|
)
|
|
|
158,932
|
|
|
|
(158,081
|
)
|
|
|
(76,117
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
|
|
|
|
851
|
|
|
|
|
|
|
|
851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income attributable to SandRidge Energy, Inc.
|
|
$
|
(76,968
|
)
|
|
$
|
158,081
|
|
|
$
|
(158,081
|
)
|
|
$
|
(76,968
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
SANDRIDGE
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS (CONTINUED)
Condensed
Consolidating Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
104,718
|
|
|
$
|
37,264
|
|
|
$
|
|
|
|
$
|
141,982
|
|
Net cash used in investing activities
|
|
|
(240,992
|
)
|
|
|
(29,306
|
)
|
|
|
|
|
|
|
(270,298
|
)
|
Net cash provided by (used in) financing activities
|
|
|
136,418
|
|
|
|
(8,117
|
)
|
|
|
|
|
|
|
128,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
144
|
|
|
|
(159
|
)
|
|
|
|
|
|
|
(15
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
18
|
|
|
|
618
|
|
|
|
|
|
|
|
636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
162
|
|
|
$
|
459
|
|
|
$
|
|
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by operating activities
|
|
$
|
(133,603
|
)
|
|
$
|
430,437
|
|
|
$
|
|
|
|
$
|
296,834
|
|
Net cash used in investing activities
|
|
|
(384,314
|
)
|
|
|
(401,577
|
)
|
|
|
|
|
|
|
(785,891
|
)
|
Net cash provided by (used in) financing activities
|
|
|
730,540
|
|
|
|
(28,730
|
)
|
|
|
|
|
|
|
701,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
212,623
|
|
|
|
130
|
|
|
|
|
|
|
|
212,753
|
|
Cash and cash equivalents at beginning of period
|
|
|
62,967
|
|
|
|
168
|
|
|
|
|
|
|
|
63,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
275,590
|
|
|
$
|
298
|
|
|
$
|
|
|
|
$
|
275,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
ITEM 2.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
Introduction
The following discussion and analysis is intended to help the
reader understand our business, financial condition, results of
operations, liquidity and capital resources. This discussion and
analysis should be read in conjunction with our condensed
consolidated financial statements and the accompanying notes
included in this Quarterly Report, as well as our audited
consolidated financial statements and the accompanying notes
included in our 2008
Form 10-K.
The financial information with respect to the three and
six-month periods ended June 30, 2009 and June 30,
2008 that is discussed below is unaudited. In the opinion of
management, this information contains all adjustments,
consisting only of normal recurring adjustments, necessary to
state fairly the unaudited condensed consolidated financial
statements. The results of operations for the interim periods
are not necessarily indicative of the results of operations for
the full fiscal year.
Overview
of Our Company
We currently generate the majority of our consolidated revenues,
earnings and cash flow from the production and sale of natural
gas and crude oil. Our revenues, profitability and future growth
depend substantially on prevailing prices for natural gas and
crude oil and on our ability to find and economically develop
and produce natural gas and crude oil reserves. Prices for
natural gas and crude oil fluctuate widely. In order to reduce
our exposure to these fluctuations, we enter into derivative
commodity contracts for a portion of our anticipated future
natural gas and crude oil production. Reducing our exposure to
price volatility helps ensure that we have adequate funds
available for our capital expenditure programs.
We operate businesses that are complementary to our exploration,
development and production activities. We own related gas
gathering and treating facilities, a gas marketing business and
an oil field services business. The extent to which each of
these supplemental businesses contributes to our consolidated
results of operations largely is determined by the amount of
work each performs for third parties. Revenues and costs related
to work performed by these businesses for our own account are
eliminated in consolidation and, therefore, do not contribute to
our consolidated results of operations.
Segment
Overview
We operate in three business segments: exploration and
production, drilling and oil field services and midstream gas
services. The all other column in the tables below includes
items not related to our reportable segments including our
CO2
gathering and sales operations and corporate operations.
Management evaluates the performance of our business segments
based on operating income, which is defined as segment operating
revenue less operating expenses and depreciation, depletion and
amortization. Results of these measures provide important
35
information to us about the activity and profitability of our
lines of business. Set forth in the table below is financial
information regarding each of our business segments (in
thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Drilling and Oil
|
|
|
Midstream Gas
|
|
|
|
|
|
Consolidated
|
|
|
|
Production
|
|
|
Field Services
|
|
|
Services
|
|
|
All Other
|
|
|
Total
|
|
|
Three Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
103,727
|
|
|
$
|
55,975
|
|
|
$
|
71,838
|
|
|
$
|
6,511
|
|
|
$
|
238,051
|
|
Inter-segment revenue
|
|
|
(64
|
)
|
|
|
(50,877
|
)
|
|
|
(52,742
|
)
|
|
|
(269
|
)
|
|
|
(103,952
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
103,663
|
|
|
$
|
5,098
|
|
|
$
|
19,096
|
|
|
$
|
6,242
|
|
|
$
|
134,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
$
|
(5,248
|
)
|
|
$
|
(2,801
|
)
|
|
$
|
(28,030
|
)
|
|
$
|
(13,908
|
)
|
|
$
|
(49,987
|
)
|
Interest expense, net
|
|
|
(41,387
|
)
|
|
|
(558
|
)
|
|
|
|
|
|
|
(286
|
)
|
|
|
(42,231
|
)
|
Other income, net
|
|
|
483
|
|
|
|
|
|
|
|
200
|
|
|
|
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
$
|
(46,152
|
)
|
|
$
|
(3,359
|
)
|
|
$
|
(27,830
|
)
|
|
$
|
(14,194
|
)
|
|
$
|
(91,535
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
293,472
|
|
|
$
|
108,720
|
|
|
$
|
219,819
|
|
|
$
|
5,653
|
|
|
$
|
627,664
|
|
Inter-segment revenue
|
|
|
(44
|
)
|
|
|
(96,856
|
)
|
|
|
(151,523
|
)
|
|
|
(1,191
|
)
|
|
|
(249,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
293,428
|
|
|
$
|
11,864
|
|
|
$
|
68,296
|
|
|
$
|
4,462
|
|
|
$
|
378,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(6,545
|
)
|
|
$
|
4,644
|
|
|
$
|
6,553
|
|
|
$
|
(16,447
|
)
|
|
$
|
(11,795
|
)
|
Interest expense, net
|
|
|
(19,823
|
)
|
|
|
(770
|
)
|
|
|
|
|
|
|
(297
|
)
|
|
|
(20,890
|
)
|
Other income (expense), net
|
|
|
848
|
|
|
|
(109
|
)
|
|
|
664
|
|
|
|
108
|
|
|
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(25,520
|
)
|
|
$
|
3,765
|
|
|
$
|
7,217
|
|
|
$
|
(16,636
|
)
|
|
$
|
(31,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Drilling and Oil
|
|
|
Midstream Gas
|
|
|
|
|
|
Consolidated
|
|
|
|
Production
|
|
|
Field Services
|
|
|
Services
|
|
|
All Other
|
|
|
Total
|
|
|
Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
225,660
|
|
|
$
|
149,789
|
|
|
$
|
166,205
|
|
|
$
|
12,407
|
|
|
$
|
554,061
|
|
Inter-segment revenue
|
|
|
(130
|
)
|
|
|
(138,380
|
)
|
|
|
(121,695
|
)
|
|
|
(744
|
)
|
|
|
(260,949
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
225,530
|
|
|
$
|
11,409
|
|
|
$
|
44,510
|
|
|
$
|
11,663
|
|
|
$
|
293,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss(1)
|
|
$
|
(1,101,110
|
)
|
|
$
|
(5,556
|
)
|
|
$
|
(27,820
|
)
|
|
$
|
(31,781
|
)
|
|
$
|
(1,166,267
|
)
|
Interest expense, net
|
|
|
(81,205
|
)
|
|
|
(1,191
|
)
|
|
|
|
|
|
|
(572
|
)
|
|
|
(82,968
|
)
|
Other income, net
|
|
|
1,243
|
|
|
|
|
|
|
|
434
|
|
|
|
|
|
|
|
1,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
$
|
(1,181,072
|
)
|
|
$
|
(6,747
|
)
|
|
$
|
(27,386
|
)
|
|
$
|
(32,353
|
)
|
|
$
|
(1,247,558
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
500,438
|
|
|
$
|
188,558
|
|
|
$
|
368,054
|
|
|
$
|
11,507
|
|
|
$
|
1,068,557
|
|
Inter-segment revenue
|
|
|
(88
|
)
|
|
|
(164,372
|
)
|
|
|
(254,671
|
)
|
|
|
(2,290
|
)
|
|
|
(421,421
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
500,350
|
|
|
$
|
24,186
|
|
|
$
|
113,383
|
|
|
$
|
9,217
|
|
|
$
|
647,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
$
|
(53,934
|
)
|
|
$
|
2,496
|
|
|
$
|
6,585
|
|
|
$
|
(29,753
|
)
|
|
$
|
(74,606
|
)
|
Interest expense, net
|
|
|
(43,235
|
)
|
|
|
(1,412
|
)
|
|
|
|
|
|
|
(603
|
)
|
|
|
(45,250
|
)
|
Other income, net
|
|
|
780
|
|
|
|
109
|
|
|
|
1,306
|
|
|
|
159
|
|
|
|
2,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
$
|
(96,389
|
)
|
|
$
|
1,193
|
|
|
$
|
7,891
|
|
|
$
|
(30,197
|
)
|
|
$
|
(117,502
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The operating loss for the exploration and production segment
for the six-month period ended June 30, 2009 includes a
$1,304.4 million non-cash full cost ceiling impairment on
our natural gas and crude oil properties. |
36
Exploration
and Production Segment
The primary factors affecting the financial results of our
exploration and production segment are the prices we receive for
our natural gas and crude oil production, the quantity of
natural gas and crude oil we produce and changes in the fair
value of commodity derivative contracts we use to reduce the
volatility of the prices we receive for our natural gas and
crude oil production. A three and six-month comparison of
production and prices is presented in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mmcf)
|
|
|
22,255
|
|
|
|
21,715
|
|
|
|
46,687
|
|
|
|
40,888
|
|
Crude oil (MBbls)
|
|
|
722
|
|
|
|
620
|
|
|
|
1,440
|
|
|
|
1,231
|
|
Combined equivalent volumes (Mmcfe)
|
|
|
26,587
|
|
|
|
25,435
|
|
|
|
55,327
|
|
|
|
48,274
|
|
Average daily combined equivalent volumes (Mmcfe/d)
|
|
|
292
|
|
|
|
280
|
|
|
|
306
|
|
|
|
265
|
|
Average prices as reported(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.95
|
|
|
$
|
10.22
|
|
|
$
|
3.41
|
|
|
$
|
9.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (per Bbl)(2)
|
|
$
|
51.79
|
|
|
$
|
113.12
|
|
|
$
|
45.13
|
|
|
$
|
101.55
|
|
Combined equivalent (per Mcfe)
|
|
$
|
3.88
|
|
|
$
|
11.49
|
|
|
$
|
4.05
|
|
|
$
|
10.31
|
|
Average prices including impact of derivative
contract settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.07
|
|
|
$
|
7.93
|
|
|
$
|
7.40
|
|
|
$
|
8.11
|
|
Crude oil (per Bbl)(2)
|
|
$
|
56.01
|
|
|
$
|
99.97
|
|
|
$
|
49.85
|
|
|
$
|
93.74
|
|
Combined equivalent (per Mcfe)
|
|
$
|
7.44
|
|
|
$
|
9.21
|
|
|
$
|
7.54
|
|
|
$
|
9.26
|
|
|
|
|
(1) |
|
Prices represent actual average prices for the periods presented
and do not give effect to derivative transactions. |
|
(2) |
|
Includes natural gas liquids. |
Exploration
and Production Segment Three months ended
June 30, 2009 compared to the three months ended
June 30, 2008
Exploration and production segment revenues decreased 64.7% to
$103.7 million in the three months ended June 30, 2009
from $293.4 million in the three months ended June 30,
2008, as a result of a 66.2% decrease in the combined average
price we received for our natural gas and crude oil production.
In the three-month period ended June 30, 2009, we increased
natural gas production by 0.5 Bcf to 22.2 Bcf and
increased crude oil production by 102 MBbls to
722 MBbls from the comparable period in 2008. The total
combined 1.2 Bcfe increase in production was primarily due
to an increase in the number of producing wells in which we
owned interests as a result of our successful drilling program
in the Mid-Continent and West Texas area.
The average price we received for our natural gas production for
the three-month period ended June 30, 2009 decreased 71.1%,
or $7.27 per Mcf, to $2.95 per Mcf from $10.22 per Mcf in the
comparable period in 2008. The average price received for our
crude oil production decreased 54.2%, or $61.33 per barrel, to
$51.79 per barrel during the three months ended June 30,
2009 from $113.12 per barrel during the same period in 2008.
Including the impact of derivative contract settlements, the
effective price received for natural gas for the three-month
period ended June 30, 2009 was $7.07 per Mcf compared to
$7.93 per Mcf during the same period in 2008. Including the
impact of derivative contract settlements, the effective price
received for crude oil for the three-month period ended
June 30, 2009 was $56.01 per Bbl compared to $99.97 per Bbl
during the same period in 2008. During 2008 and continuing into
2009, we entered into derivative contracts to mitigate the
impact of commodity price fluctuations on our production through
2012. Due to the long-term nature of our investment in the
development of the WTO, we enter into natural gas and crude oil
swaps and natural gas basis swaps for a portion of our
production in order to stabilize future cash inflows for
planning purposes. Our derivative contracts are not designated
as hedges and, as a
37
result, gains or losses on commodity derivative contracts are
recorded as a component of operating expense. Internally,
management views the settlement of such derivative contracts as
adjustments to the price received for natural gas and crude oil
production to determine effective prices.
For the three months ended June 30, 2009, we had a
$5.2 million operating loss in our exploration and
production segment compared to a loss of $6.5 million for
the same period in 2008. The operating loss for the three months
ended June 30, 2009 is attributable to a
$189.7 million decrease in exploration and production
revenues, partially offset by a $140.8 million decrease in
the net loss on our commodity derivative positions, a
$38.0 million decrease in depreciation, depletion and
amortization and a $12.9 million decrease in production
taxes.
During the three-month period ended June 30, 2009, the
exploration and production segment reported a $19.0 million
net loss on our commodity derivative positions
($113.7 million unrealized loss and $94.7 million
realized gains) compared to a $159.8 million net loss on
our commodity derivative positions ($101.8 million
unrealized loss and $58.0 million realized losses) in the
comparable period in 2008. Unrealized gains or losses on
derivative contracts represent the change in fair value of open
derivative contracts during the period. The unrealized loss on
natural gas and crude oil derivative contracts recorded during
the three months ended June 30, 2009 was attributable to an
increase in average natural gas and crude oil prices at
June 30, 2009 compared to the average natural gas and crude
oil prices at March 31, 2009 or the contract price for
contracts entered into during the second quarter of 2009.
Exploration
and Production Segment Six months ended
June 30, 2009 compared to the six months ended
June 30, 2008
Exploration and production segment revenues decreased 54.9% to
$225.5 million in the six months ended June 30, 2009
from $500.4 million in the six months ended June 30,
2008, as a result of a 60.7% decrease in the combined average
price we received for our natural gas and crude oil production.
The decrease in prices received was slightly offset by a 14.6%
increase in combined production volumes. In the six-month period
ended June 30, 2009, we increased natural gas production by
5.8 Bcf to 46.7 Bcf and increased crude oil production
by 209 MBbls to 1,440 MBbls from the comparable period
in 2008. The total combined 7.1 Bcfe increase in production
was primarily due to an increase in the number of producing
wells in which we owned interests as a result of the successful
drilling programs in the WTO and the Mid-Continent.
The average price we received for our natural gas production for
the six-month period ended June 30, 2009 decreased 62.6%,
or $5.70 per Mcf, to $3.41 per Mcf from $9.11 per Mcf in the
comparable period in 2008. The average price received for our
crude oil production decreased 55.6%, or $56.42 per barrel, to
$45.13 per barrel during the six months ended June 30, 2009
from $101.55 per barrel during the same period in 2008.
Including the impact of derivative contract settlements, the
effective price received for natural gas for the six-month
period ended June 30, 2009 was $7.40 per Mcf compared to
$8.11 per Mcf during the same period in 2008. Including the
impact of derivative contract settlements, the effective price
received for crude oil for the six-month period ended
June 30, 2009 was $49.85 per Bbl compared to $93.74 per Bbl
during the same period in 2008.
For the six months ended June 30, 2009, we had a
$1,101.1 million operating loss in our exploration and
production segment compared to a loss of $53.9 million for
the same period in 2008. The operating loss for the six months
ended June 30, 2009 is attributable to a
$274.8 million decrease in exploration and production
revenues and a first quarter $1,304.4 million full cost
ceiling impairment, partially offset by a $187.7 million
net gain on our commodity derivative contracts, of which
$5.5 million was an unrealized loss, a $42.8 million
decrease in depreciation, depletion and amortization and a
$20.7 million decrease in production taxes. The full cost
ceiling impairment was the result of the decline of the future
value of our reserves due to depressed natural gas and crude oil
prices at March 31, 2009. No additional full cost ceiling
impairment was recognized at June 30, 2009.
During the six-month period ended June 30, 2009, the
exploration and production segment reported a
$187.7 million net gain on our commodity derivative
positions ($5.5 million unrealized loss and
$193.2 million realized gains) compared to a
$296.6 million net loss on our commodity derivative
positions ($245.9 million unrealized loss and
$50.7 million realized losses) in the same period in 2008.
The unrealized loss on natural gas and crude oil derivative
contracts recorded during the six months ended June 30,
2009 was attributable to an increase in average natural gas and
crude oil prices at June 30, 2009 compared to the average
natural gas and crude oil prices at
38
December 31, 2008 or the contract price for contracts
entered into during 2009. The realized gain of
$193.2 million for the six months ended June 30, 2009
was primarily due to a decline in natural gas prices at the time
of settlement compared to the contract price.
Drilling
and Oil Field Services Segment
The financial results of our drilling and oil field services
segment depend on many factors, particularly the demand for and
the price we can charge for our services. In addition to
providing drilling services, our oil field services business
also conducts operations that complement our drilling services
such as providing pulling units, trucking, rental tools,
location and road construction and roustabout services. On a
consolidated basis, drilling and oil field service revenues
earned and expenses incurred in performing services for third
parties, including third party working interests in wells we
operate, are included in drilling and services revenue and
expense while drilling and oil field service revenues earned and
expenses incurred in performing services for our own account are
eliminated in consolidation.
As of June 30, 2009, we owned 31 drilling rigs, of which 23
were idle, through Lariat. As Lariats rigs are primarily
to drill for our account, there is not a significant impact to
our consolidated results of operations in having this number of
rigs idle. The table below presents information concerning rigs
owned by Lariat:
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
Rigs working for SandRidge
|
|
|
6
|
|
|
|
27
|
|
Rigs working for third parties
|
|
|
|
|
|
|
2
|
|
Idle rigs(1)
|
|
|
23
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Total operational
|
|
|
29
|
|
|
|
31
|
|
Non-operational rigs
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
Total rigs owned
|
|
|
31
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes two rigs receiving stand-by rates from third parties at
June 30, 2009. |
In addition to the rigs we owned during the quarter ended
June 30, 2009, we also indirectly owned eleven operational
rigs through our investment in Larclay. Although our ownership
in Larclay afforded us access to Larclays operational
rigs, we did not control Larclay, and, therefore, did not
consolidate the results of its operations with ours. Only the
activities of our wholly owned drilling and oil field services
subsidiaries are included in the financial results of our
drilling and oil field services segment. On April 15, 2009,
Lariat completed an assignment to CWEI of Lariats 50%
equity interest in Larclay. Pursuant to the Larclay Assignment,
Lariat assigned all of its right, title and interest in and to
Larclay to CWEI effective as of April 15, 2009, and CWEI
assumed all of the obligations and liabilities of Lariat
relating to Larclay from and after April 15, 2009. We fully
impaired our investment in and notes receivable due from Larclay
at December 31, 2008. There were no additional losses on
Larclay during the three or six-month periods ended
June 30, 2009 or as a result of the Larclay Assignment.
Drilling
and Oil Field Services Segment Three months ended
June 30, 2009 compared to the three months ended
June 30, 2008
Drilling and oil field services segment revenues decreased to
$5.1 million in the three-month period ended June 30,
2009 from $11.9 million in the three-month period ended
June 30, 2008. This resulted in an operating loss of
$2.8 million in the three-month period ended June 30,
2009 compared to operating income of $4.6 million for the
same period in 2008. The decline in revenues and operating
income was primarily attributable to a decrease in the number of
our rigs operating and services performed for third parties as
well as lower operating margins. All six of our rigs working at
June 30, 2009, were working for our account, compared to 27
of our 29 working rigs working for our account at June 30,
2008. Additionally, the average daily rate received per rig
working for third parties declined to an average of $9,000 per
rig per working day during the three-month period ended
June 30, 2009 from an average of $13,932 per rig per
working day during the comparable period in 2008. We received
reduced, or stand-by, rates on two of our rigs during the
three-month period ended June 30, 2009.
39
Drilling
and Oil Field Services Segment Six months ended
June 30, 2009 compared to the six months ended
June 30, 2008
Drilling and oil field services segment revenues decreased to
$11.4 million in the six-month period ended June 30,
2009 from $24.2 million in the six-month period ended
June 30, 2008. This resulted in an operating loss of
$5.6 million in the three-month period ended June 30,
2009 compared to operating income of $2.5 million in the
same period in 2008. The decline in revenues and operating
income was primarily attributable to the decrease in the number
of our rigs operating and services performed for third parties
as well as lower operating margins. During the six-month period
ended June 30, 2009, approximately 92.4%, or
$138.4 million, of our drilling and oil field service
revenues were generated by work performed on our own account and
eliminated in consolidation compared to approximately 87.2%, or
$164.4 million, for the same period in 2008. The average
daily rate received per rig working for third parties declined
to an average of $10,264 per rig per working day during the
six-month period ended June 30, 2009 from an average of
$14,000 per rig per working day during the comparable period in
2008. During the six-month period ended June 30, 2008, one
of our rigs working for a third-party was operated under a
turnkey contract, while none of our rigs were operated under
turnkey contracts during the six-month period ended
June 30, 2009. Additionally, we received reduced, or
stand-by, rates on two of our rigs during the six-month period
ended June 30, 2009.
Midstream
Gas Services Segment
Midstream gas services segment revenues consist mostly of gas
marketing revenue, one of our largest revenue components;
however, gas marketing is a very low-margin business. On a
consolidated basis, midstream and marketing revenues represent
natural gas sold on behalf of third parties and the fees we
charge related to gathering, compressing and treating this gas.
Gas marketing operating costs represent payments made to third
parties for the proceeds from the sale of gas owned by such
parties, net of any applicable margin and actual costs to
gather, compress and treat the gas that we charge. The primary
factors affecting midstream gas services are the quantity of
natural gas we gather, treat and market and the prices we pay
and receive for natural gas.
In June 2009, we completed the sale of our gathering and
compression assets located in the Piñon Field of the WTO.
Net proceeds from the sale were approximately
$197.5 million, which resulted in a loss on the sale of
$26.5 million. The sale of these assets is not expected to
have a significant impact on our future consolidated results of
operations. In conjunction with the sale, we entered into a gas
gathering agreement and an operations and maintenance agreement.
Under the gas gathering agreement, we have dedicated our
Piñon Field acreage for priority gathering services for a
period of twenty years and we will pay a fee for such services
that was negotiated at arms length. Pursuant to the
operations and maintenance agreement, we will operate and
maintain the gathering system assets sold for a period of twenty
years unless we or the buyer of the assets chooses to terminate
the agreement.
Midstream
Gas Services Segment Three months ended
June 30, 2009 compared to the three months ended
June 30, 2008
Midstream gas services segment revenues for the three months
ended June 30, 2009 were $19.1 million compared to
$68.3 million in the comparable period of 2008. The
quarterly decrease in midstream gas services revenues was
attributable to a 68.3% decrease in natural gas prices received
in the three-month period ended June 30, 2009 compared to
the same period in 2008. Operating costs decreased in proportion
to revenues due to the decrease in natural gas prices paid in
the three-month period ended June 30, 2009 compared to the
same period in 2008. Profit margin for the three-month period
ended June 30, 2009 was 6.1% compared to a profit margin of
6.8% for the same period in 2008. The net loss of
$27.8 million for the three months ended June 30, 2009
was primarily attributable to the loss on the sale of our
gathering and compression assets in the Piñon Field.
40
Midstream
Gas Services Segment Six months ended June 30,
2009 compared to the six months ended June 30,
2008
Midstream gas services segment revenues for the six months ended
June 30, 2009 were $44.5 million compared to
$113.4 million in the comparable period of 2008. The
decrease in midstream gas services revenues was attributable to
a 60.8% decrease in natural gas prices received in the six-month
period ended June 30, 2009 compared to the same period in
2008. Midstream operating costs decreased in proportion to
revenue based on the decrease in natural gas prices paid in the
six-month period ended June 30, 2009 compared to the same
period in 2008. Profit margin for the six-month period ended
June 30, 2009 was 8.3% compared to a profit margin of 9.3%
for the same period in 2008. The net loss of $27.4 million
for the six-month period ended June 30, 2009 compared to
net income of $7.9 million for the same period in 2008 is
primarily attributable to the loss on the sale of our gathering
and compression assets in the Piñon Field in 2009.
Results
of Operations Consolidated
Three
months ended June 30, 2009 compared to the three months
ended June 30, 2008
Revenues. Total revenues decreased 64.5% to
$134.1 million for the three months ended June 30,
2009 from $378.1 million in the same period in 2008. This
decrease was primarily due to a $189.1 million decrease in
natural gas and crude oil sales combined with decreases in
midstream and marketing revenues. The table below presents a
comparison of revenues for the three-month periods ended
June 30, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
103,039
|
|
|
$
|
292,134
|
|
|
$
|
(189,095
|
)
|
|
|
(64.7
|
)%
|
Drilling and services
|
|
|
5,176
|
|
|
|
11,957
|
|
|
|
(6,781
|
)
|
|
|
(56.7
|
)%
|
Midstream and marketing
|
|
|
19,642
|
|
|
|
69,488
|
|
|
|
(49,846
|
)
|
|
|
(71.7
|
)%
|
Other
|
|
|
6,242
|
|
|
|
4,471
|
|
|
|
1,771
|
|
|
|
39.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
134,099
|
|
|
$
|
378,050
|
|
|
$
|
(243,951
|
)
|
|
|
(64.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total natural gas and crude oil revenues decreased
$189.1 million to $103.0 million for the three months
ended June 30, 2009 compared to $292.1 million for the
same period in 2008. The decrease was primarily attributable to
a decrease in prices received for our natural gas and crude oil
production. The average price received, excluding the impact of
derivative contracts, for our natural gas and crude oil
production decreased 66.2% in the 2009 period to $3.88 per Mcfe
compared to $11.49 per Mcfe in 2008.
Drilling and services revenues decreased 56.7% to
$5.2 million for the three months ended June 30, 2009
compared to $12.0 million in the same period in 2008. The
decline in revenues was due to the decrease in rigs operating
for and services provided to third parties combined with the
decline in the average daily rate received per rig working for
third parties.
Midstream and marketing revenues decreased $49.8 million,
or 71.7%, with revenues of $19.6 million in the three-month
period ended June 30, 2009 compared to $69.5 million
in the three-month period ended June 30, 2008. The
quarterly decrease in midstream gas services revenues was
primarily attributable to the decrease in natural gas prices for
third party volumes we marketed in the three-month period ended
June 30, 2009 compared to the same period in 2008.
Other revenue increased to $6.2 million for the three
months ended June 30, 2009 from $4.5 million for the
same period in 2008 due to higher
CO2
volumes sold to third parties for the three months ended
June 30, 2009. Other revenue was generated primarily by our
CO2
gathering and sales operations.
41
Operating Costs and Expenses. Total operating
costs and expenses decreased to $184.1 million for the
three months ended June 30, 2009 compared to
$389.8 million for the same period in 2008. The decrease
was primarily due to decreases in production taxes, midstream
and marketing, depreciation, depletion and amortization
(DD&A) and loss on derivative contracts. The
table below presents a comparison of operating costs and
expenses for the three-month periods ended June 30, 2009
and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
41,450
|
|
|
$
|
40,254
|
|
|
$
|
1,196
|
|
|
|
3.0
|
%
|
Production taxes
|
|
|
593
|
|
|
|
13,519
|
|
|
|
(12,926
|
)
|
|
|
(95.6
|
)%
|
Drilling and services
|
|
|
6,415
|
|
|
|
5,066
|
|
|
|
1,349
|
|
|
|
26.6
|
%
|
Midstream and marketing
|
|
|
18,450
|
|
|
|
64,733
|
|
|
|
(46,283
|
)
|
|
|
(71.5
|
)%
|
Depreciation, depletion and amortization natural gas
and crude oil
|
|
|
34,350
|
|
|
|
72,256
|
|
|
|
(37,906
|
)
|
|
|
(52.5
|
)%
|
Depreciation, depletion and amortization other
|
|
|
14,034
|
|
|
|
15,780
|
|
|
|
(1,746
|
)
|
|
|
(11.1
|
)%
|
General and administrative
|
|
|
23,632
|
|
|
|
26,203
|
|
|
|
(2,571
|
)
|
|
|
(9.8
|
)%
|
Loss on derivative contracts
|
|
|
18,992
|
|
|
|
159,768
|
|
|
|
(140,776
|
)
|
|
|
(88.1
|
)%
|
Loss (gain) on sale of assets
|
|
|
26,170
|
|
|
|
(7,734
|
)
|
|
|
33,904
|
|
|
|
(438.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
$
|
184,086
|
|
|
$
|
389,845
|
|
|
$
|
(205,759
|
)
|
|
|
(52.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses include the costs associated with our
exploration and production activities, including, but not
limited to, lease operating expenses and treating costs. The
increase in production expense is attributable to an increase in
the number of wells in which we owned an interest during the
quarter and increased production volumes for the quarter. In the
three-month period ended June 30, 2009, we increased
natural gas production by 0.5 Bcf to 22.2 Bcf and
increased crude oil production by 102 MBbls to
722 MBbls from the comparable period in 2008. Production
taxes decreased $12.9 million, or 95.6%, to
$0.6 million primarily due to severance tax refunds
received in 2009 and the decreased prices received for
production during the three months ended June 30, 2009.
Drilling and services expenses, which includes operating
expenses attributable to the drilling and oil field services
segment and our
CO2
services companies, increased 26.6% for the three months ended
June 30, 2009 compared to the same period in 2008. The
increase was primarily due to less rig activity and lower profit
margins in 2009. This resulted in less costs being eliminated by
intercompany activity.
Midstream and marketing expenses decreased $46.3 million,
or 71.5%, to $18.5 million due to lower natural gas prices
paid for natural gas that we sold on behalf of third parties
during the three months ended June 30, 2009 than during the
comparable period in 2008.
DD&A for our natural gas and crude oil properties decreased
to $34.4 million for the three months ended June 30,
2009 from $72.3 million for the same period in 2008. Our
DD&A per Mcfe decreased $1.55 to $1.29 in the second
quarter of 2009 from $2.84 in the comparable period in 2008 as a
result of the cumulative $3,159.4 million full cost ceiling
impairment, which reduced the carrying value of our natural gas
and crude oil properties. Of the cumulative impairment,
$1,855.0 million was incurred at December 31, 2008 and
$1,304.4 million was incurred at March 31, 2009. See
Note 5 of Notes to the Condensed Consolidated Financial
Statements included in Item 1. Financial
Statements for additional information regarding the full
cost ceiling impairment.
DD&A for our other assets consists primarily of
depreciation of our drilling rigs, midstream gathering and
compression facilities and other equipment. The decrease in
DD&A for our other assets was attributable primarily to a
change in asset lives of certain of our drilling, oil field
services, midstream and other assets to align with
42
industry average lives for similar assets. We calculate
depreciation of property and equipment using the straight-line
method over the estimated useful lives of the assets, which
range from 3 to 39 years.
General and administrative expenses decreased $2.6 million
to $23.6 million for the three months ended June 30,
2009 from $26.2 million for the comparable period in 2008.
The decrease was principally attributable to higher professional
services and fees for the three months ended June 30, 2008
related to audit, consulting and legal fees. General and
administrative expenses included non-cash stock compensation
expense of $4.6 million, net of amounts capitalized, for
the three months ended June 30, 2009 compared to
$4.1 million for the comparable period in 2008. Salaries
and wages and stock compensation were reduced by
$5.4 million in capitalized general and administrative
expenses, which included $0.8 million of capitalized stock
compensation expense, for the three months ended June 30,
2009 compared to $4.3 million for the three months ended
June 30, 2008.
We recorded a net loss of $19.0 million
($113.7 million unrealized loss and $94.7 million
realized gains) on our commodity derivative contracts for the
three months ended June 30, 2009 compared to a
$159.8 million net loss ($101.8 million unrealized
loss and $58.0 million realized losses) for the same period
in 2008. The unrealized loss recorded in the second quarter of
2009 was attributable to an increase in average natural gas
prices at June 30, 2009 compared to average natural gas
prices at March 31, 2009 or the contract date for contracts
entered into during the second quarter of 2009.
The loss on sale of assets for the three months ended
June 30, 2009 was primarily due to the $26.5 million
loss on the sale of our gathering and compression assets located
in the Piñon Field. For the three months ended
June 30, 2008, a gain of approximately $7.5 million
was recognized on the sale of our assets located in the Piceance
Basin of Colorado.
Other Income (Expense). Total other expense
increased to $41.5 million in the three-month period ended
June 30, 2009 from $19.4 million in the three-month
period ended June 30, 2008. The increase is reflected in
the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
188
|
|
|
$
|
1,333
|
|
|
$
|
(1,145
|
)
|
|
|
(85.9
|
)%
|
Interest expense
|
|
|
(42,419
|
)
|
|
|
(22,223
|
)
|
|
|
(20,196
|
)
|
|
|
90.9
|
%
|
Income from equity investments
|
|
|
200
|
|
|
|
556
|
|
|
|
(356
|
)
|
|
|
(64.0
|
)%
|
Other income, net
|
|
|
483
|
|
|
|
955
|
|
|
|
(472
|
)
|
|
|
(49.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(41,548
|
)
|
|
|
(19,379
|
)
|
|
|
(22,169
|
)
|
|
|
114.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income tax benefit
|
|
|
(91,535
|
)
|
|
|
(31,174
|
)
|
|
|
(60,361
|
)
|
|
|
193.6
|
%
|
Income tax benefit
|
|
|
(365
|
)
|
|
|
(10,847
|
)
|
|
|
10,482
|
|
|
|
(96.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(91,170
|
)
|
|
$
|
(20,327
|
)
|
|
$
|
(70,843
|
)
|
|
|
348.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income decreased to $0.2 million for the three
months ended June 30, 2009 from $1.3 million for the
same period in 2008. This decrease was generally due to lower
excess cash levels during the three months ended June 30,
2009 compared to the same period in 2008.
Interest expense increased to $42.4 million for the three
months ended June 30, 2009 from $22.2 million for the
same period in 2008. This increase was primarily attributable to
the higher average debt balances outstanding during the three
months ended June 30, 2009, which was slightly offset by
the net gain of $2.6 million on our interest rate swap.
Also contributing to the increase was a $9.6 million
unrealized gain on our interest rate swap which reduced interest
expense for the three months ended June 30, 2008.
We reported an income tax benefit of $0.4 million for the
three months ended June 30, 2009, compared to a benefit of
$10.9 million for the same period in 2008. The current
period income tax benefit represents an effective income tax
rate of 0.4% compared to an effective income tax rate of 34.8%
in the same period in 2008. The lower
43
effective income tax rate associated with the current period
loss before income taxes was primarily a result of not recording
a tax benefit for the loss due to our full valuation allowance
on our net deferred tax asset.
Six
months ended June 30, 2009 compared to the six months ended
June 30, 2008
Revenues. Total revenues decreased 54.7% to
$293.1 million for the six months ended June 30, 2009
from $647.1 million for the same period in 2008. This
decrease was primarily due to a $273.3 million decrease in
natural gas and crude oil sales and a decrease in midstream and
marketing revenues. The table below presents a comparison of
revenues for the six-month periods ended June 30, 2009 and
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil
|
|
$
|
224,280
|
|
|
$
|
497,621
|
|
|
$
|
(273,341
|
)
|
|
|
(54.9
|
)%
|
Drilling and services
|
|
|
11,571
|
|
|
|
24,291
|
|
|
|
(12,720
|
)
|
|
|
(52.4
|
)%
|
Midstream and marketing
|
|
|
45,598
|
|
|
|
115,897
|
|
|
|
(70,299
|
)
|
|
|
(60.7
|
)%
|
Other
|
|
|
11,663
|
|
|
|
9,327
|
|
|
|
2,336
|
|
|
|
25.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
293,112
|
|
|
$
|
647,136
|
|
|
$
|
(354,024
|
)
|
|
|
(54.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and crude oil revenues decreased $273.3 million
to $224.3 million for the six months ended June 30,
2009 compared to $497.6 million for the same period in
2008, primarily as a result of a decrease in prices received for
our natural gas and crude oil production, which was slightly
offset by an increase in the natural gas and crude oil produced.
The average price received, excluding the impact of derivative
contracts, for our natural gas and crude oil production
decreased 60.7% in the 2009 period to $4.05 per Mcfe compared to
$10.31 per Mcfe in 2008. Total natural gas production increased
14.2% to 46.7 Bcf in 2009 compared to 40.9 Bcf in
2008, while crude oil production increased 17.0% to
1,440 MBbls in 2009 from 1,231 MBbls in 2008.
Drilling and services revenues decreased 52.4% to
$11.6 million for the six months ended June 30, 2009
compared to $24.3 million for the same period in 2008. The
decline in revenues was due to the decrease in rigs operating
for and services provided to third parties and the decline in
the average daily rate received per rig working for third
parties.
Midstream and marketing revenues decreased $70.3 million,
or 60.7%, with revenues of $45.6 million in the six-month
period ended June 30, 2009 compared to $115.9 million
in the six-month period ended June 30, 2008. The decrease
was attributable to the decrease in prices for natural gas that
we sold on behalf of third parties in the six-month period ended
June 30, 2009 compared to the same period in 2008.
Other revenue increased to $11.7 million for the six months
ended June 30, 2009 from $9.3 million for the same
period in 2008. Other revenue was generated primarily by our
CO2
gathering and sales operations.
Operating Costs and Expenses. Total operating
costs and expenses increased to $1,459.4 million for the
six months ended June 30, 2009 compared to
$721.7 million for the same period in 2008. The increase
was primarily due to a first quarter 2009 full cost ceiling
impairment and increases in production and general and
administrative expenses. These increases were partially offset
by decreases in production taxes, midstream and marketing and
44
DD&A and an increase in realized gains on derivative
contracts. The table below presents a comparison of operating
costs and expenses for the six-month periods ended June 30,
2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
87,029
|
|
|
$
|
74,442
|
|
|
$
|
12,587
|
|
|
|
16.9
|
%
|
Production taxes
|
|
|
2,084
|
|
|
|
22,739
|
|
|
|
(20,655
|
)
|
|
|
(90.8
|
)%
|
Drilling and services
|
|
|
12,021
|
|
|
|
12,235
|
|
|
|
(214
|
)
|
|
|
(1.7
|
)%
|
Midstream and marketing
|
|
|
41,812
|
|
|
|
105,151
|
|
|
|
(63,339
|
)
|
|
|
(60.2
|
)%
|
Depreciation, depletion, and amortization natural
gas and crude oil
|
|
|
94,443
|
|
|
|
137,332
|
|
|
|
(42,889
|
)
|
|
|
(31.2
|
)%
|
Depreciation, depletion and amortization other
|
|
|
26,760
|
|
|
|
33,745
|
|
|
|
(6,985
|
)
|
|
|
(20.7
|
)%
|
Impairment
|
|
|
1,304,418
|
|
|
|
|
|
|
|
1,304,418
|
|
|
|
100.0
|
%
|
General and administrative
|
|
|
52,117
|
|
|
|
47,197
|
|
|
|
4,920
|
|
|
|
10.4
|
%
|
(Gain) loss on derivative contracts
|
|
|
(187,655
|
)
|
|
|
296,612
|
|
|
|
(484,267
|
)
|
|
|
(163.3
|
)%
|
Loss (gain) on sale of assets
|
|
|
26,350
|
|
|
|
(7,711
|
)
|
|
|
34,061
|
|
|
|
(441.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
$
|
1,459,379
|
|
|
$
|
721,742
|
|
|
$
|
737,637
|
|
|
|
102.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses increased $12.6 million primarily due
to an increase in the number of wells in which we own an
interest and increased production volumes. In the six-month
period ended June 30, 2009, we increased natural gas
production by 5.8 Bcf to 46.7 Bcf and increased crude
oil production by 209 MBbls to 1,440 MBbls from the
comparable period in 2008. Production taxes decreased
$20.7 million, or 90.8%, to $2.1 million. The decrease
was primarily due to severance tax refunds received in 2009 and
the decreased prices received for production during the six
months ended June 30, 2009.
Midstream and marketing expenses decreased $63.3 million,
or 60.2%, to $41.8 million due to lower prices paid for
natural gas that we sold on behalf of third parties during the
six months ended June 30, 2009 than during the comparable
period in 2008.
DD&A for our natural gas and crude oil properties decreased
to $94.4 million for the six months ended June 30,
2009 from $137.3 million during the same period in 2008.
Our average DD&A per Mcfe decreased $1.14 to $1.71 in the
first six months of 2009 from $2.85 for the comparable period in
2008 as a result of the $3,159.4 million cumulative full
cost ceiling impairment, which reduced the carrying value of our
natural gas and crude oil properties. The effect of the decrease
in DD&A per Mcfe was slightly offset by the 14.6% increase
in production during the first six months of 2009 compared to
the same period in 2008.
DD&A for our other assets consists primarily of
depreciation of our drilling rigs, midstream gathering and
compression facilities and other equipment. The decrease in
DD&A for our other assets was attributable primarily to the
change in asset lives of certain of our drilling, oil field
services, midstream and other assets to align with industry
average lives for similar assets.
General and administrative expenses increased $4.9 million
to $52.1 million for the six months ended June 30,
2009 from $47.2 million for the comparable period in 2008.
The increase was principally attributable to an increase in
corporate salaries and wages, including non-cash stock
compensation expense. The increase in corporate salaries was
primarily due to the increase in the average number of corporate
and support staff employed during the six months ended
June 30, 2009 compared to the same period in 2008. General
and administrative expenses included non-cash stock compensation
expense, net of amounts capitalized, of $9.4 million for
the six months ended June 30, 2009 compared to
$7.3 million for the comparable period in 2008. The
increases in salaries and wages and stock compensation were
partially offset by $12.9 million in capitalized general
and administrative expenses, which
45
included $2.0 million of capitalized stock compensation
expense, for the six months ended June 30, 2009 compared to
$7.5 million for the six months ended June 30, 2008.
We recorded a net gain of $187.7 million ($5.5 million
unrealized loss and $193.2 million realized gains) on our
commodity derivatives contracts for the six months ended
June 30, 2009 compared to a $296.6 million net loss
($245.9 million unrealized loss and $50.7 million
realized losses) for the same period in 2008. The unrealized
loss recorded in 2009 was attributable to an increase in average
natural gas prices at June 30, 2009 compared to average
natural gas prices at December 31, 2008 or the contract
date for contracts entered into during 2009. The realized gains
of $193.2 million for the six months ended June 30, 2009 were
primarily due to a decline in natural gas prices at the time of
settlement compared to the contract price.
The loss on sale of assets for the six months ended
June 30, 2009 was primarily due to the $26.5 million
loss on the sale of our gathering and compression assets in the
Piñon Field. For the six months ended June 30, 2008,
the gain on sale of assets of $7.7 million was attributable
to the approximately $7.5 million gain on the sale of our
assets located in the Piceance Basin of Colorado.
Other Income (Expense). Total other expense
increased to $81.3 million in the six-month period ended
June 30, 2009 from $42.9 million in the six-month
period ended June 30, 2008. The increase is reflected in
the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
$ Change
|
|
|
% Change
|
|
|
|
(In thousands)
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
199
|
|
|
$
|
2,145
|
|
|
$
|
(1,946
|
)
|
|
|
(90.7
|
)%
|
Interest expense
|
|
|
(83,167
|
)
|
|
|
(47,395
|
)
|
|
|
(35,772
|
)
|
|
|
75.5
|
%
|
Income from equity investments
|
|
|
434
|
|
|
|
1,415
|
|
|
|
(981
|
)
|
|
|
(69.3
|
)%
|
Other income, net
|
|
|
1,243
|
|
|
|
939
|
|
|
|
304
|
|
|
|
32.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(81,291
|
)
|
|
|
(42,896
|
)
|
|
|
(38,395
|
)
|
|
|
89.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income tax benefit
|
|
|
(1,247,558
|
)
|
|
|
(117,502
|
)
|
|
|
(1,130,056
|
)
|
|
|
961.7
|
%
|
Income tax benefit
|
|
|
(1,534
|
)
|
|
|
(41,385
|
)
|
|
|
39,851
|
|
|
|
(96.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(1,246,024
|
)
|
|
$
|
(76,117
|
)
|
|
$
|
(1,169,907
|
)
|
|
|
1,537.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income decreased to $0.2 million for the six
months ended June 30, 2009 from $2.1 million for the
same period in 2008. The decrease was generally due to lower
excess cash levels during the six months ended June 30,
2009 compared to the same period in 2008.
Interest expense increased to $83.2 million for the six
months ended June 30, 2009 from $47.4 million for the
same period in 2008. This increase was attributable to the
higher average debt balances outstanding during the six months
ended June 30, 2009. Also contributing to the increase was
a $10.4 million unrealized gain related to our interest
rate swap which reduced interest expense for the six months
ended June 30, 2008.
We reported an income tax benefit of $1.5 million for the
six months ended June 30, 2009, compared to a benefit of
$41.4 million for the same period in 2008. The current
period income tax benefit represents an effective income tax
rate of 0.1% compared to an effective income tax rate of 35.0%
for the same period in 2008. The lower effective income tax rate
associated with the current period loss before income taxes was
primarily a result of not recording a tax benefit for the loss
due to our full valuation allowance on our net deferred tax
asset.
Liquidity
and Capital Resources
We historically have funded our capital requirements through a
combination of cash flow generated from operations, borrowings
under our senior credit facility, the issuance of equity and
debt securities and, to a lesser extent, the sale of assets.
During the first six months of 2009, our primary sources of cash
were cash flow generated from operations, borrowings under our
senior credit facility, proceeds from the issuance of
convertible perpetual
46
preferred stock and common stock, proceeds from the issuance of
our 9.875% Senior Notes, proceeds from the sale of
gathering and compression assets related to our midstream
operations in the Piñon Field and proceeds from the sale of
our drilling rights in East Texas below the depth of the Cotton
Valley formation. Our primary uses of cash during the first six
months of 2009 were capital expenditures related to the
development of our natural gas and crude oil properties and
other fixed assets and the repayment of amounts outstanding on
our senior credit facility.
Our cash flows for the six months ended June 30, 2009 and
2008 are presented in the following table and discussed below:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash flows provided by operating activities
|
|
$
|
141,982
|
|
|
$
|
296,834
|
|
Cash flows used in investing activities
|
|
|
(270,298
|
)
|
|
|
(785,891
|
)
|
Cash flows provided by financing activities
|
|
|
128,301
|
|
|
|
701,810
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(15
|
)
|
|
$
|
212,753
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Operations
Our operating cash flow is mainly influenced by the prices we
receive for our natural gas and crude oil production; the
quantity of natural gas we produce and, to a lesser extent, the
quantity of crude oil we produce; the demand for our drilling
rigs and oil field services and the rates we are able to charge
for these services; and the margins we obtain from our natural
gas and
CO2
gathering and treating contracts.
Net cash provided by operating activities for the six months
ended June 30, 2009 and 2008 was $142.0 million and
$296.8 million, respectively. The decrease in cash provided
by operating activities in 2009 compared to 2008 was primarily
due to a 60.7% decrease in the combined average prices we
received for our natural gas and crude oil production for the
six months ended June 30, 2009. Decreases in midstream and
marketing revenues also contributed to the decrease in operating
cash flows.
Cash
Flows from Investing
We dedicate and expect to continue to dedicate a substantial
portion of our capital expenditure program toward the
exploration, development, production and acquisition of natural
gas and crude oil reserves. These capital expenditures are
necessary to offset inherent declines in production and proven
reserves, which is typical in the capital-intensive natural gas
and crude oil industry. Net cash used in investing activities,
which included capital expenditures for property, plant and
equipment, for the six months ended June 30, 2009 and 2008
was $270.3 million and $785.9 million, respectively.
During the first six months of 2009 and 2008, our capital
expenditures, on an accrual basis, by segment were:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Capital Expenditures:
|
|
|
|
|
|
|
|
|
Exploration and production
|
|
$
|
383,231
|
|
|
$
|
813,900
|
|
Drilling and oil field services
|
|
|
2,201
|
|
|
|
35,791
|
|
Midstream gas services
|
|
|
41,288
|
|
|
|
69,429
|
|
Other
|
|
|
17,764
|
|
|
|
15,181
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
444,484
|
|
|
$
|
934,301
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures decreased $489.8 million to
$444.5 million for the six months ended June 30, 2009
compared to $934.3 million for the same period in 2008 due
to our decreased drilling activities. Cash outflows from capital
expenditures in the first six months of 2009 were partially
offset by approximately $254.0 million in
47
combined proceeds from the sale of our gathering and compression
assets located in the Piñon Field and our deep drilling
rights in East Texas. Cash outflows from capital expenditures in
the first six months of 2008 were partially offset by
approximately $147.2 million in proceeds from the sale of
our assets located in the Piceance Basin of Colorado.
Cash
Flows from Financing
Our financing activities provided $128.3 million in cash
for the six-month period ended June 30, 2009 compared to
$701.8 million for the same period in 2008. Proceeds from
borrowings, including the senior notes described below, were
$1,431.8 million for the six months ended June 30,
2009 compared to $1,408.0 million for the same period in
2008. Repayments of approximately $1,645.3 million resulted
in net repayments during the six-month period ended
June 30, 2009 of approximately $213.5 million.
Repayments of $665.6 million during the first six months of
2008 resulted in net borrowings during the period of
$742.4 million. Additionally, the issuance of our 8.5%
convertible perpetual preferred stock and 14,480,000 shares
of common stock provided additional net proceeds of
$243.3 million and $107.7 million, respectively,
during the six months ended June 30, 2009.
Long-Term
Debt Issuances and Repayments
Senior Credit Facility. As a result of net
repayments of $555.5 million during the first six months of
2009, we had total outstanding indebtedness of
$18.0 million under our senior credit facility as of
June 30, 2009. The amount we may borrow under the facility
is limited to a borrowing base amount, which is currently
$985.4 million, and is subject to periodic
redeterminations. The borrowing base is available to be drawn on
and repaid so long as we are in compliance with its terms,
including certain financial covenants. The borrowing base is
determined based upon proved developed producing reserves,
proved developed non-producing reserves and proved undeveloped
reserves. Our ability to develop properties and changes in
commodity prices may affect the borrowing base of our senior
credit facility. Based on the April 2009 redetermination, our
borrowing base remained unchanged from the previous
determination of $1.1 billion; however, the borrowing base
was reduced to $985.4 million as a result of our issuance
of the 9.875% Senior Notes in May 2009. The average annual
interest rate paid on amounts outstanding under our senior
credit facility was 2.28% for the six months ended June 30,
2009. Our senior credit facility matures on November 21,
2011.
9.875% Senior Notes Due 2016. In May
2009, we completed a private placement of $365.5 million of
unsecured 9.875% Senior Notes to qualified institutional
investors eligible under Rule 144A of the Securities Act.
These notes were issued at a discount which will be amortized
into interest expense over the term of the notes. Net proceeds
from the offering were approximately $342.2 million after
deducting the discount and offering expenses of
$7.8 million. We used the net proceeds from the offering to
repay outstanding borrowings under our senior credit facility
and for general corporate purposes. The notes bear interest at a
fixed rate of 9.875% per annum, payable semi-annually, with the
principal due on May 15, 2016. We may redeem the notes, in
whole or in part, prior to their maturity at specified
redemption prices. The notes are jointly and severally,
unconditionally guaranteed on an unsecured basis by all of the
Companys wholly owned subsidiaries, except certain minor
subsidiaries, and will become freely tradable 180 days
after their issuance pursuant to Rule 144 under the
Securities Act.
8.0% Senior Notes Due 2018. In May 2008,
we received approximately $735.0 million net proceeds from
the issuance of $750.0 million of unsecured
8.0% Senior Notes due 2018. The notes bear interest at a
fixed rate of 8.0% per annum, payable semi-annually, with the
principal due on June 1, 2018. The notes are redeemable, in
whole or in part, prior to their maturity at specified
redemption prices. The notes became freely tradable on
November 17, 2008, 180 days after their issuance,
pursuant to Rule 144 under the Securities Act.
Preferred
and Common Stock Issuances
8.5% Convertible Perpetual Preferred
Stock. In January 2009, we completed a private
placement of 2,650,000 shares of 8.5% convertible perpetual
preferred stock to qualified institutional buyers eligible under
Rule 144A under the Securities Act. The offering included
400,000 shares of convertible perpetual preferred stock
issued upon the full exercise of the initial purchasers
option to cover over-allotments. Net proceeds from the offering
were approximately $243.3 million after deducting offering
expenses of approximately $8.6 million. We
48
used the net proceeds of the offering to repay outstanding
borrowings under our senior credit facility and for general
corporate purposes.
Each share of 8.5% convertible perpetual preferred stock has a
liquidation preference of $100 and is convertible at the
holders option at any time initially into approximately
12.4805 shares of our common stock, subject to adjustments
upon the occurrence of certain events. Each holder of the
convertible perpetual preferred stock is entitled to an annual
dividend of $8.50 per share to be paid semi-annually in cash,
common stock or a combination thereof at our election with the
first dividend payment due in February 2010. The convertible
perpetual preferred stock is not redeemable by us at any time.
After February 20, 2014, we may cause all outstanding
shares of the convertible perpetual preferred stock to
automatically convert into common stock at the then-prevailing
conversion rate if certain conditions are met.
Common Stock. On April 29, 2009, we
completed a registered underwritten offering of
14,480,000 shares of our common stock, including
2,280,000 shares of common stock acquired by the
underwriters from us to cover over-allotments. Net proceeds from
the offering were approximately $107.7 million after
deducting offering expenses of approximately $2.3 million
and were used to repay a portion of the amount outstanding under
our senior credit facility and for general corporate purposes.
Outlook
We have budgeted a range of $500.0 million to
$700.0 million for capital expenditures, excluding
acquisitions, for the year ending December 31, 2009. The
majority of our planned capital expenditures are discretionary
and could be curtailed if our cash flows decline from expected
levels or we are unable to obtain capital on attractive terms.
We may increase or decrease planned capital expenditures
depending on natural gas prices, asset sales and the
availability of capital through the issuance of additional
long-term debt or equity. Additionally, we have entered into
interest rate swaps as well as fixed-price swaps and basis swaps
for a portion of our production through 2012 in order to
stabilize future cash flows for planning purposes. See
Item 3. Quantitative and Qualitative Disclosures
About Market Risk for additional information regarding our
derivative contracts.
As of June 30, 2009, our cash and cash equivalents were
$0.6 million and we had approximately $2.2 billion in
total debt outstanding. Amounts outstanding under our senior
credit facility at June 30, 2009 totaled
$18.0 million. As of June 30, 2009, we were in
compliance with all of the covenants under all of our senior
notes and our senior credit facility. See Note 8 of Notes
to the Condensed Consolidated Financial Statements included in
Item 1. Financial Statements for additional
information regarding our long-term debt. As of July 31,
2009, our cash and cash equivalents were approximately
$83.2 million, the balance outstanding under our senior
credit facility was $124.6 million and we had
$30.5 million in outstanding letters of credit.
If future capital expenditures exceed operating cash flow and
cash on hand, funds would likely be supplemented as needed by
borrowings under our senior credit facility. We may choose to
refinance borrowings outstanding under the facility by issuing
long-term debt or equity in the public or private markets, or
both.
Debt and equity capital markets experienced adverse conditions
during the latter part of 2008 and into 2009. Continued
volatility in the capital markets may increase costs associated
with issuing debt due to increased interest rates, and may
affect our ability to access these markets. Currently, we do not
believe our liquidity has been, or in the near future will be,
materially affected by recent events in the global financial
markets. Nevertheless, we continue to monitor events and
circumstances surrounding each of the 27 lenders under our
senior credit facility. To date, the only disruption to our
ability to access the full amounts available under our senior
credit facility was the bankruptcy of Lehman Brothers, a lender
responsible for 0.29% of the obligations under our senior credit
facility. The largest commitment from any lender under the
senior credit facility is 6.6% of the total amount available
under the facility. We cannot predict with any certainty the
impact to us of any further disruptions in the credit markets.
Contractual
Obligations
Gas Gathering Agreement. In conjunction with
the sale of our gathering and compression assets located in the
Piñon Field of the WTO, we entered into a gas gathering
agreement. Under the gas gathering agreement, we
49
have dedicated our Piñon Field acreage for priority
gathering services over a period of twenty years and we will pay
a fee that was negotiated at arms length for such
services. Pursuant to the gas gathering agreement, the base fee
can be reduced if certain criteria are met. The table below
presents our contractual obligations under this agreement.
|
|
|
|
|
|
|
Payments Due
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
7,584
|
|
2010
|
|
|
22,226
|
|
2011
|
|
|
33,780
|
|
2012
|
|
|
42,814
|
|
2013
|
|
|
42,634
|
|
After 2013
|
|
|
327,749
|
|
|
|
|
|
|
|
|
$
|
476,787
|
|
|
|
|
|
|
Long-Term Debt. We issued our
9.875% Senior Notes in May 2009. This debt issuance along
with the pay down of the outstanding balance on the senior
credit are discussed further under Long-Term Debt
Issuances and Repayments above.
|
|
ITEM 3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
General
The discussion in this section provides information about the
financial instruments we use to manage commodity prices and
interest rate volatility. All contracts are settled in cash and
do not require the actual delivery of a commodity at settlement.
Commodity Price Risk. Our most significant
market risk relates to the prices we receive for our natural gas
and crude oil production. Due to the historical volatility of
these commodities, we periodically have entered into, and expect
in the future to enter into, derivative arrangements for the
purpose of reducing the variability of natural gas and crude oil
prices we receive for our production. From time to time, we
enter into commodity pricing derivative contracts for a portion
of our anticipated production volumes depending upon
managements view of opportunities under the then current
market conditions. We do not intend to enter into derivative
contracts that would exceed our expected production volumes for
the period covered by the derivative arrangement. Our current
credit agreement limits our ability to enter into derivative
transactions to 85% of expected production volumes from
estimated proved reserves. Future credit agreements could
require a minimum level of commodity price hedging.
The use of derivative contracts also involves the risk that the
counterparties will be unable to meet their obligations under
the contracts. Our derivative contracts are with multiple
counterparties to minimize our exposure to any individual
counterparty. As of June 30, 2009, we had eighteen approved
derivative counterparties, seventeen of which are lenders under
our senior credit facility. We currently have derivative
contracts outstanding with twelve of these counterparties,
including Lehman Brothers. We have no derivative contracts in
2009 and beyond with counterparties other than those that are
lenders under our senior credit facility. Lehman Brothers is a
counterparty on one of our derivative contracts. Due to the
bankruptcy of Lehman Brothers and its parent, Lehman Brothers
Holdings Inc., we did not assign any value to this derivative
contract (notional amount of 3,680 MMcf) at June 30,
2009.
We use, and may continue to use, a variety of commodity-based
derivative contracts, including collars, fixed-price swaps and
basis protection swaps. Our fixed price swap transactions are
settled based upon NYMEX prices, and our basis protection swap
transactions are settled based upon the index price of natural
gas at the Waha hub, a West Texas gas marketing and delivery
center and the Houston Ship Channel. Settlement for natural gas
derivative contracts occurs in the production month.
We have not designated any of our derivative contracts as hedges
for accounting purposes. We record all derivative contracts on
the balance sheet at fair value, which reflects changes in
natural gas and crude oil prices. We establish fair value of our
derivative contracts by price quotations obtained from
counterparties to the derivative contracts. Changes in fair
values of our derivative contracts are recognized as unrealized
gains and losses in current
50
period earnings. As a result, our current period earnings may be
significantly affected by changes in fair value of our
commodities derivative contracts. Changes in fair value are
principally measured based on period-end prices compared to the
contract price.
At June 30, 2009, our open natural gas and crude oil
commodity derivative contracts consisted of the following:
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(MMcf)(1)
|
|
|
Fixed Price
|
|
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
18,710
|
|
|
$
|
8.09
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
19,010
|
|
|
$
|
8.46
|
|
Basis swap contracts
|
|
|
15,640
|
|
|
$
|
(0.74
|
)
|
January 2010 March 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,475
|
|
|
$
|
7.95
|
|
Basis swap contracts
|
|
|
20,250
|
|
|
$
|
(0.74
|
)
|
April 2010 June 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
19,793
|
|
|
$
|
7.32
|
|
Basis swap contracts
|
|
|
20,475
|
|
|
$
|
(0.74
|
)
|
July 2010 September 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,010
|
|
|
$
|
7.55
|
|
Basis swap contracts
|
|
|
20,700
|
|
|
$
|
(0.74
|
)
|
October 2010 December 2010
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
20,010
|
|
|
$
|
7.97
|
|
Basis swap contracts
|
|
|
20,700
|
|
|
$
|
(0.74
|
)
|
January 2011 March 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
25,650
|
|
|
$
|
(0.47
|
)
|
April 2011 June 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
25,935
|
|
|
$
|
(0.47
|
)
|
July 2011 September 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
26,220
|
|
|
$
|
(0.47
|
)
|
October 2011 December 2011
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
26,220
|
|
|
$
|
(0.47
|
)
|
January 2012 March 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,020
|
|
|
$
|
(0.54
|
)
|
April 2012 June 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,020
|
|
|
$
|
(0.54
|
)
|
July 2012 September 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,240
|
|
|
$
|
(0.54
|
)
|
October 2012 December 2012
|
|
|
|
|
|
|
|
|
Basis swap contracts
|
|
|
20,240
|
|
|
$
|
(0.54
|
)
|
|
|
|
(1) |
|
Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total
notional of 3,680 MMcf from 2009 contracts for the Lehman
Brothers basis swap contract. |
51
Crude
Oil
|
|
|
|
|
|
|
|
|
|
|
Notional
|
|
|
Weighted Avg.
|
|
Period and Type of Contract
|
|
(in MBbls)
|
|
|
Fixed Price
|
|
|
July 2009 September 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.61
|
|
October 2009 December 2009
|
|
|
|
|
|
|
|
|
Price swap contracts
|
|
|
46
|
|
|
$
|
126.51
|
|
The following table summarizes the cash settlements and
valuation gains and losses on our commodity derivative contracts
for the six months ended June 30, 2009 and 2008 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
|
|
2009
|
|
|
2008
|
|
|
Realized (gain) loss
|
|
$
|
(193,136
|
)
|
|
$
|
50,674
|
|
Unrealized loss
|
|
|
5,481
|
|
|
|
245,938
|
|
|
|
|
|
|
|
|
|
|
(Gain) loss on derivative contracts
|
|
$
|
(187,655
|
)
|
|
$
|
296,612
|
|
|
|
|
|
|
|
|
|
|
Credit Risk. A portion of our liquidity is
concentrated in derivative contracts that enable us to mitigate
a portion of our exposure to natural gas and crude oil prices
and interest rate volatility. We periodically review the credit
quality of each counterparty to our derivative contracts and the
level of financial exposure we have to each counterparty to
limit our credit risk exposure with respect to these contracts.
Additionally, we apply a credit default risk rating factor for
our counterparties in determining the fair value of our
derivative contracts.
Our ability to fund our capital expenditure budget is partially
dependent upon the availability of funds under our senior credit
facility. In order to mitigate the credit risk associated with
individual financial institutions committed to participate in
our senior credit facility, our bank group consists of 27
financial institutions with commitments ranging from 0.25% to
6.6%. Lehman Brothers, a lender under our senior credit
facility, declared bankruptcy on October 3, 2008. As a
result of the bankruptcy of Lehman Brothers and its parent
company, Lehman Brothers Holdings Inc., on September 15,
2008, Lehman Brothers elected not to fund its pro rata share, or
0.29%, of borrowings requested by us under the facility.
Although we do not currently expect this reduced amount
available under the senior credit facility to impact our
liquidity or business operations, the inability of one or more
of our other lenders to fund their obligations under the
facility could have a material adverse effect on our financial
condition.
Interest Rate Risk. We are subject to interest
rate risk on our long-term fixed and variable interest rate
borrowings. Fixed rate debt, where the interest rate is fixed
over the life of the instrument, exposes us to (i) changes
in market interest rates reflected in the fair value of the debt
and (ii) the risk that we may need to refinance maturing
debt with new debt at a higher rate. Variable rate debt, where
the interest rate fluctuates, exposes us to short-term changes
in market interest rates as our interest obligations on these
instruments are periodically redetermined based on prevailing
market interest rates, primarily LIBOR and the federal funds
rate.
In addition to commodity price derivative arrangements, we may
enter into derivative transactions to fix the interest we pay on
a portion of the money we borrow under our credit agreement. In
January 2008, we entered into a $350.0 million notional
amount interest rate swap agreement with a financial institution
that effectively fixed the interest rate on our variable rate
term loan for the period from April 1, 2008 through
April 1, 2011. As a result of the exchange of our variable
rate term loan to Senior Floating Rate Notes, the interest rate
swap is now used to fix the variable LIBOR interest rate on the
Senior Floating Rate Notes at 6.26% through April 2011. In May
2009, we entered into a $350.0 million notional amount
interest rate swap agreement with a financial institution that
effectively fixed the interest rate on our Senior Floating Rate
Notes at 6.69% for the period from April 1, 2011 through
April 1, 2013. These swaps have not been designated as
hedges.
Our interest rate swaps reduce our market risk on our Senior
Floating Rate Notes. We use sensitivity analyses to determine
the impact that market risk exposures could have on our variable
interest rate borrowings if not for our interest rate swaps.
Based on the $350.0 million outstanding balance of our
Senior Floating Rate Notes at June 30, 2009, a one percent
change in the applicable rates, with all other variables held
constant, would have resulted in a
52
change in our interest expense of approximately
$0.9 million and $1.8 million for the three months and
six months ended June 30, 2009, respectively.
Unrealized gains of $3.9 million and $9.6 million were
recorded in interest expense in the consolidated statements of
operations for the change in fair value of the interest rate
swap for the three months ended June 30, 2009 and 2008,
respectively. Unrealized gains of $3.7 million and
$10.4 million were recorded in interest expense in the
consolidated statements of operations for the change in fair
value of the interest rate swap for the six months ended
June 30, 2009 and 2008, respectively. Realized losses of
$1.3 million and $2.3 million were included in
interest expense in the condensed consolidated statements of
operations for the three and six months ended June 30,
2009, respectively. There were no realized gains or losses
recorded on our interest rate swap during the first six months
of 2008.
|
|
ITEM 4.
|
Controls
and Procedures
|
Under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief
Financial Officer, we performed an evaluation of the
effectiveness of the design and operation of our disclosure
controls and procedures pursuant to Exchange Act
Rules 13a-15
and 15d-15
as of the end of the period covered by this Quarterly Report.
Based on that evaluation, our Chief Executive Officer and our
Chief Financial Officer concluded that our disclosure controls
and procedures were effective as of June 30, 2009 to
provide reasonable assurance that the information required to be
disclosed by us in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the rules and forms of the
Securities and Exchange Commission, and such information is
accumulated and communicated to management, as appropriate to
allow timely decisions regarding required disclosure.
There was no change in our internal control over financial
reporting during the quarter ended June 30, 2009 that has
materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
PART II.
Other Information
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|
ITEM 1.
|
Legal
Proceedings
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The Company is a defendant in lawsuits from time to time in the
normal course of business. In managements opinion, the
Company is not currently involved in any legal proceedings that,
individually or in the aggregate, could have a material adverse
effect on its results of operations, financial condition or cash
flows.
Certain
U.S. federal income tax deductions currently available with
respect to oil and gas exploration and development may be
eliminated as a result of future legislation.
President Obamas Proposed Fiscal Year 2010 Budget includes
proposed legislation that would, if enacted into law, make
significant changes to United States tax laws, including the
elimination of certain key U.S. federal income tax
incentives currently available to oil and natural gas
exploration and production companies. These changes include, but
are not limited to, (i) the repeal of the percentage
depletion allowance for oil and natural gas properties,
(ii) the elimination of current deductions for intangible
drilling and development costs, (iii) the elimination of
the deduction for certain domestic production activities, and
(iv) an extension of the amortization period for certain
geological and geophysical expenditures. It is unclear whether
any such changes will be enacted or how soon any such changes
could become effective. The passage of any legislation as a
result of these proposals or any other similar changes in
U.S. federal income tax laws could negatively affect our
financial condition and results of operations.
The
adoption of derivatives legislation by Congress could have an
adverse impact on our ability to hedge risks associated with our
business.
Congress is currently considering legislation to impose
restrictions on certain transactions involving derivatives,
which could affect the use of derivatives in hedging
transactions. The American Clean Energy
53
and Security Act of 2009, also known as the
Waxman-Markey
cap-and-trade
legislation or ACESA, which was approved for adoption by
the U.S. House of Representatives on June 26, 2009,
contains provisions that would prohibit private
over-the-counter
energy commodity derivative and hedging transactions. ACESA
would expand the power of the Commodity Futures Trading
Commission, or CFTC, to regulate derivative transactions related
to energy commodities, including oil and natural gas, and to
mandate clearance of such derivative contracts through
registered derivative clearing organizations. Under ACESA, the
CFTCs expanded authority over energy derivatives would
terminate upon the adoption of general legislation covering
derivative regulatory reform. The Chairman of the CFTC has
announced that the CFTC intends to conduct hearings to determine
whether to set limits on trading and positions in commodities
with finite supply, particularly energy commodities, such as
crude oil, natural gas and other energy products. The CFTC also
is evaluating whether position limits should be applied
consistently across all markets and participants. In addition,
the Treasury Department recently has indicated that it intends
to propose legislation to subject all OTC derivative dealers and
all other major OTC derivative market participants to
substantial supervision and regulation, including by imposing
conservative capital and margin requirements and strong business
conduct standards. Derivative contracts that are not cleared
through central clearinghouses and exchanges may be subject to
substantially higher capital and margin requirements. Although
it is not possible at this time to predict whether or when
Congress may act on derivatives legislation or how any climate
change bill approved by the Senate would be reconciled with
ACESA, any laws or regulations that may be adopted that subject
us to additional capital or margin requirements relating to, or
to additional restrictions on, our trading and commodity
positions could have an adverse effect on our ability to hedge
risks associated with our business or on the cost of our hedging
activity.
Federal
and state legislation and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
Congress is currently considering legislation to amend the
federal Safe Drinking Water Act to require the disclosure of
chemicals used by the oil and gas industry in the hydraulic
fracturing process. Hydraulic fracturing involves the injection
of water, sand and chemicals under pressure into rock formations
to stimulate natural gas production. Sponsors of bills currently
pending before the Senate and House of Representatives have
asserted that chemicals used in the fracturing process could
adversely affect drinking water supplies. The proposed
legislation would require the reporting and public disclosure of
chemicals used in the fracturing process, which could make it
easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based on allegations that
specific chemicals used in the fracturing process could
adversely affect groundwater. In addition, these bills, if
adopted, could establish an additional level of regulation at
the federal level that could lead to operational delays or
increased operating costs and could result in additional
regulatory burdens that could make it more difficult to perform
hydraulic fracturing and increase our costs of compliance and
doing business.
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ITEM 2.
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Unregistered
Sales of Equity Securities and Use of Proceeds
|
As part of our restricted stock program, we make required tax
payments on behalf of employees as their stock awards vest and
then withhold a number of vested shares having a value on the
date of vesting equal to the tax obligation. The shares withheld
are recorded as treasury shares. During the quarter ended
June 30, 2009, the following shares were withheld in
satisfaction of tax withholding obligations arising from the
vesting of restricted stock:
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Total Number of
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Maximum Number
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|
|
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|
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Shares Purchased
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of Shares that May
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Total Number
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Average
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as Part of Publicly
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Yet Be Purchased
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of Shares
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Price Paid
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Announced Plans
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Under the Plans
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Period
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Purchased
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per Share
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or Programs
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or Programs
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April 1, 2009 April 30, 2009
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398
|
|
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$
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8.16
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N/A
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N/A
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May 1, 2009 May 31, 2009
|
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457
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10.72
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N/A
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N/A
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June 1, 2009 June 30, 2009
|
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132
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8.47
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N/A
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N/A
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54
|
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ITEM 4.
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Submission
of Matters to a Vote of Security Holders
|
(a) Our Annual Meeting of Stockholders was held in Oklahoma
City on June 5, 2009.
(b) Proxies for the meeting were solicited pursuant to
Regulation 14A under the Exchange Act. There was no
solicitation in opposition to the person nominated by our Board
of Directors to serve as a Class III director of the
Company. The terms of the Companys Class I directors,
William A. Gilliland, D. Dwight Scott and Jeffrey S. Serota,
expire at the Companys Annual Meeting of Stockholders in
2010. The terms of the Companys Class II directors,
Tom L. Ward and Roy T. Oliver, expire at the Companys
Annual Meeting of Stockholders in 2011.
(c) A total of 143,687,782 shares of our common stock
outstanding and entitled to vote were present at the
June 5, 2009 meeting in person or by proxy. Each share of
common stock was entitled to one vote. The matters voted upon
and results were as follows:
1. Election of one Class III director to serve until
the Companys Annual Meeting of Stockholders in 2012.
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Nominee
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For
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Authority Withheld
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Daniel W. Jordan
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120,703,644
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22,984,139
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2. Ratification of PricewaterhouseCoopers LLP as our
independent registered public accounting firm for the fiscal
year ending December 31, 2009.
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FOR:
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143,301,476
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AGAINST:
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333,273
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ABSTAIN:
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53,033
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3. Adoption of the SandRidge Energy, Inc. 2009 Incentive
Plan.
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FOR:
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90,193,905
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AGAINST:
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15,793,396
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ABSTAIN:
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101,971
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See the Exhibit Index accompanying this Quarterly Report.
55
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
SandRidge Energy, Inc.
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|
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By:
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/s/ Dirk
M. Van Doren
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Dirk M. Van Doren
Executive Vice President and
Chief Financial Officer
Date: August 6, 2009
EXHIBIT INDEX
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Incorporated by Reference
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Exhibit
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SEC
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|
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Filed
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No.
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|
Exhibit Description
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|
Form
|
|
File No.
|
|
Exhibit
|
|
Filing Date
|
|
Herewith
|
|
|
3
|
.1
|
|
Certificate of Incorporation of SandRidge Energy, Inc.
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S-1
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333-148956
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3.1
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01/30/2008
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|
|
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3
|
.2
|
|
Amended and Restated Bylaws of SandRidge Energy, Inc.
|
|
8-K
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001-33784
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3.1
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03/09/2009
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4
|
.1
|
|
Amendment, dated April 23, 2009, to Registration Rights
Agreement, dated March 20, 2007, among SandRidge Energy,
Inc. and the purchasers named therein
|
|
8-K
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|
001-33784
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|
4.1
|
|
04/28/2009
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|
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|
4
|
.2
|
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Indenture, dated May 14, 2009, among SandRidge Energy, Inc.
and the several guarantors named therein, and Wells Fargo Bank,
National Association, as trustee
|
|
8-K
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|
001-33784
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|
4.1
|
|
05/15/2009
|
|
|
|
4
|
.3
|
|
Registration Rights Agreement, dated May 14, 2009, among
SandRidge Energy, Inc., the several guarantors named therein and
Barclays Capital Inc., Banc of America Securities LLC,
J.P. Morgan Securities Inc., RBC Capital Markets
Corporation and RBS Securities Inc., as representatives of the
several initial purchasers
|
|
8-K
|
|
001-33784
|
|
4.2
|
|
05/15/2009
|
|
|
|
10
|
.1
|
|
Amendment No. 6 to Senior Credit Facility, dated
April 17, 2009
|
|
8-K
|
|
001-33784
|
|
10.1
|
|
04/21/2009
|
|
|
|
10
|
.2
|
|
Underwriting Agreement, dated April 23, 2009, among
SandRidge Energy, Inc., Tom L. Ward and Morgan
Stanley & Co. Incorporated, as representative of the
underwriters named therein
|
|
8-K
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|
001-33784
|
|
1.1
|
|
04/28/2009
|
|
|
|
10
|
.3
|
|
SandRidge Energy, Inc. 2009 Incentive Plan
|
|
8-K
|
|
001-33784
|
|
10.1
|
|
06/09/2009
|
|
|
|
10
|
.4
|
|
Membership Interest Purchase Agreement, dated June 30,
2009, between SandRidge Midstream, Inc. and TCW Pecos Midstream,
L.L.C.
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*
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10
|
.5
|
|
Gas Gathering Agreement, dated June 30, 2009, between
SandRidge Exploration and Production, LLC and Piñon
Gathering Company, LLC. Portions of this exhibit have been
omitted pursuant to a request for confidential treatment. The
omitted portions have been filed separately with the Securities
and Exchange Commission.
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*
|
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10
|
.6
|
|
Operations and Maintenance Agreement, dated June 30, 2009,
between SandRidge Midstream, Inc. and Piñon Gathering
Company, LLC
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*
|
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31
|
.1
|
|
Section 302 Certification Chief Executive
Officer
|
|
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*
|
|
31
|
.2
|
|
Section 302 Certification Chief Financial
Officer
|
|
|
|
|
|
|
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*
|
|
32
|
.1
|
|
Section 906 Certifications of Chief Executive Officer and
Chief Financial Officer
|
|
|
|
|
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*
|
|
101
|
.INS
|
|
XBRL Instance Document
|
|
|
|
|
|
|
|
|
|
*
|
|
101
|
.SCH
|
|
XBRL Taxonomy Extension Schema Document
|
|
|
|
|
|
|
|
|
|
*
|
|
101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
|
101
|
.LAB
|
|
XBRL Taxonomy Extension Label Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
|
101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
|
|
|
|
|
|
|
|
*
|
|
101
|
.DEF
|
|
XBRL Taxonomy Extension Definition Document
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
|
|
Management contract or compensatory plan or arrangement |