|
[x]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d)
|
|
OF
THE SECURITIES EXCHANGE ACT OF 1934
|
|
OR
|
|
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d)
|
|
OF
THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
73-1283193
|
|
(State
or other jurisdiction of incorporation)
|
(I.R.S.
Employer Identification No.)
|
7130
South Lewis, Suite1000,
Tulsa,
Oklahoma
|
74136
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
(918) 493-7700
|
|
(Registrant’s
telephone number, including area
code)
|
None
|
|
(Former
name, former address and former fiscal year,
|
|
if
changed since last report)
|
Yes
[x]
|
No
[ ]
|
Yes
[ ]
|
No
[ ]
|
Large
accelerated filer [x]
|
Accelerated
filer [ ]
|
Non-accelerated
filer [ ]
|
Smaller
reporting company [ ]
|
Yes
[ ]
|
No
[x]
|
Page
|
|||
Number
|
|||
PART
I. Financial Information
|
|||
Item
1.
|
Financial
Statements (Unaudited)
|
||
Condensed
Consolidated Balance Sheets
|
|||
March
31, 2009 and December 31, 2008
|
3
|
||
Condensed
Consolidated Statements of Operations
|
|||
Three
Months Ended March 31, 2009 and 2008
|
5
|
||
Condensed
Consolidated Statements of Cash Flows
|
|||
Three
Months Ended March 31, 2009 and 2008
|
6
|
||
Condensed
Consolidated Statements of Comprehensive Income (Loss)
|
|||
Three
Months Ended March 31, 2009 and 2008
|
7
|
||
Notes
to Condensed Consolidated Financial Statements
|
8
|
||
Report
of Independent Registered Public Accounting Firm
|
20
|
||
Item
2.
|
Management’s
Discussion and Analysis of Financial
|
||
Condition
and Results of Operations
|
21
|
||
Item
3.
|
Quantitative
and Qualitative Disclosure About Market Risk
|
40
|
|
Item
4.
|
Controls
and Procedures
|
41
|
|
PART
II. Other Information
|
|||
Item
1.
|
Legal
Proceedings
|
41
|
|
Item
1A.
|
Risk
Factors
|
41
|
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
42
|
|
Item
3.
|
Defaults
Upon Senior Securities
|
42
|
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
42
|
|
Item
5.
|
Other
Information
|
42
|
|
Item
6.
|
Exhibits
|
42
|
|
Signatures
|
43
|
March
31,
|
December
31,
|
||||||||
2009
|
2008
|
||||||||
(In
thousands except share amounts)
|
|||||||||
ASSETS
|
|||||||||
Current
assets:
|
|||||||||
Cash
and cash equivalents
|
$
|
1,012
|
$
|
584
|
|||||
Restricted
cash
|
20
|
20
|
|||||||
Accounts
receivable, net of allowance for doubtful accounts of $4,893 at March 31,
2009 and $4,893 at December 31, 2008
|
130,576
|
192,408
|
|||||||
Materials
and supplies
|
10,436
|
9,923
|
|||||||
Current
derivative assets (Note 8)
|
86,274
|
52,177
|
|||||||
Current
income tax receivable
|
4,246
|
11,768
|
|||||||
Prepaid
expenses and other
|
17,492
|
19,705
|
|||||||
Total
current assets
|
250,056
|
286,585
|
|||||||
Property
and equipment:
|
|||||||||
Drilling
equipment
|
1,182,730
|
1,172,655
|
|||||||
Oil
and natural gas properties, on the full cost method:
|
|||||||||
Proved
properties
|
2,148,030
|
2,090,623
|
|||||||
Undeveloped
leasehold not being amortized
|
167,057
|
160,034
|
|||||||
Gas
gathering and processing equipment
|
172,799
|
169,402
|
|||||||
Transportation
equipment
|
32,975
|
33,611
|
|||||||
Other
|
22,785
|
22,484
|
|||||||
3,726,376
|
3,648,809
|
||||||||
Less
accumulated depreciation, depletion, amortization
|
|||||||||
and
impairment
|
1,776,875
|
1,447,157
|
|||||||
Net
property and equipment
|
1,949,501
|
2,201,652
|
|||||||
Goodwill
|
62,808
|
62,808
|
|||||||
Other
intangible assets, net
|
8,397
|
9,384
|
|||||||
Non-current
derivative assets (Note 8)
|
22,249
|
5,218
|
|||||||
Other
assets
|
15,862
|
16,219
|
|||||||
Total
assets
|
$
|
2,308,873
|
$
|
2,581,866
|
March
31,
|
December
31,
|
||||||||
2009
|
2008
|
||||||||
(In
thousands except share amounts)
|
|||||||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||||||
Current
liabilities:
|
|||||||||
Accounts
payable
|
$
|
74,898
|
$
|
129,755
|
|||||
Accrued
liabilities
|
55,801
|
51,659
|
|||||||
Contract
advances
|
2,562
|
2,889
|
|||||||
Current
portion of derivative liabilities (Note 8)
|
2,393
|
1,481
|
|||||||
Current
portion of other liabilities (Note 4)
|
11,401
|
10,615
|
|||||||
Total current liabilities
|
147,055
|
196,399
|
|||||||
Long-term
debt
|
163,500
|
199,500
|
|||||||
Long-term
derivative liabilities (Note 8)
|
1,910
|
1,780
|
|||||||
Other
long-term liabilities (Note 4)
|
73,861
|
74,027
|
|||||||
Deferred
income taxes
|
393,630
|
477,061
|
|||||||
Shareholders’
equity:
|
|||||||||
Preferred
stock, $1.00 par value, 5,000,000 shares
|
|||||||||
authorized,
none issued
|
—
|
—
|
|||||||
Common
stock, $.20 par value, 175,000,000 shares
|
|||||||||
authorized,
47,537,200 and 47,255,964 shares
|
|||||||||
issued,
respectively
|
9,369
|
9,325
|
|||||||
Capital
in excess of par value
|
377,788
|
367,000
|
|||||||
Accumulated
other comprehensive income
|
65,763
|
33,284
|
|||||||
Retained
earnings
|
1,075,997
|
1,223,490
|
|||||||
Total shareholders’ equity
|
1,528,917
|
1,633,099
|
|||||||
Total
liabilities and shareholders’ equity
|
$
|
2,308,873
|
$
|
2,581,866
|
Three
Months Ended
|
||||||
March
31,
|
||||||
2009
|
2008
|
|||||
(In
thousands except per share amounts)
|
||||||
Revenues:
|
||||||
Contract
drilling
|
$
|
88,699
|
$
|
147,247
|
||
Oil
and natural gas
|
88,904
|
130,002
|
||||
Gas
gathering and processing
|
22,143
|
44,223
|
||||
Other
income (expense), net
|
1,316
|
(110
|
)
|
|||
Total
revenues
|
201,062
|
321,362
|
||||
Expenses:
|
||||||
Contract
drilling:
|
||||||
Operating
costs
|
50,330
|
74,461
|
||||
Depreciation
|
12,619
|
15,364
|
||||
Oil
and natural gas:
|
||||||
Operating
costs
|
24,816
|
27,601
|
||||
Depreciation,
depletion and amortization
|
38,006
|
35,715
|
||||
Impairment
of oil and natural gas properties (Note 2)
|
281,241
|
—
|
||||
Gas
gathering and processing:
|
||||||
Operating
costs
|
20,677
|
35,072
|
||||
Depreciation
and amortization
|
4,061
|
3,481
|
||||
General
and administrative
|
6,089
|
6,525
|
||||
Interest,
net
|
477
|
820
|
||||
Total
operating expenses
|
438,316
|
199,039
|
||||
Income
(loss) before income taxes
|
(237,254
|
)
|
122,323
|
|||
Income
tax expense (benefit):
|
||||||
Current
|
—
|
15,447
|
||||
Deferred
|
(89,761
|
)
|
29,812
|
|||
Total
income taxes
|
(89,761
|
)
|
45,259
|
|||
Net
income (loss)
|
$
|
(147,493
|
)
|
$
|
77,064
|
|
Net
income (loss) per common share:
|
||||||
Basic
|
$
|
(3.14
|
)
|
$
|
1.66
|
|
Diluted
|
$
|
(3.14
|
)
|
$
|
1.65
|
Three
Months Ended
|
|||||||||
March
31,
|
|||||||||
2009
|
2008
|
||||||||
(In
thousands)
|
|||||||||
OPERATING
ACTIVITIES:
|
|||||||||
Net
income (loss)
|
$
|
(147,493
|
)
|
$
|
77,064
|
||||
Adjustments
to reconcile net income to net cash
|
|||||||||
provided
by operating activities:
|
|||||||||
Depreciation,
depletion and amortization
|
54,958
|
54,734
|
|||||||
Impairment
of oil and natural gas properties (Note 2)
|
281,241
|
—
|
|||||||
Unrealized
loss on derivatives
|
1,968
|
—
|
|||||||
Deferred
tax expense (benefit)
|
(89,761
|
)
|
29,812
|
||||||
Other
|
2,469
|
4,108
|
|||||||
Changes
in operating assets and liabilities
|
|||||||||
increasing
(decreasing) cash:
|
|||||||||
Accounts
receivable
|
61,832
|
(15,650
|
)
|
||||||
Accounts
payable
|
1,204
|
2,119
|
|||||||
Material
and supplies inventory
|
(513
|
)
|
(292
|
)
|
|||||
Accrued
liabilities
|
(2,423
|
)
|
8,729
|
||||||
Contract
advances
|
(327
|
)
|
(2,853
|
)
|
|||||
Other
– net
|
9,735
|
1,019
|
|||||||
Net
cash provided by operating activities
|
172,890
|
158,790
|
|||||||
INVESTING
ACTIVITIES:
|
|||||||||
Capital
expenditures
|
(115,904
|
)
|
(159,504
|
)
|
|||||
Proceeds
from disposition of assets
|
3,870
|
736
|
|||||||
Net
cash used in investing activities
|
(112,034
|
)
|
(158,768
|
)
|
|||||
FINANCING
ACTIVITIES:
|
|||||||||
Borrowings
under line of credit
|
50,800
|
56,500
|
|||||||
Payments
under line of credit
|
(86,800
|
)
|
(60,500
|
)
|
|||||
Proceeds
from exercise of stock options
|
17
|
323
|
|||||||
Book
overdrafts
|
(24,445
|
)
|
3,427
|
||||||
Net
cash used in financing activities
|
(60,428
|
)
|
(250
|
)
|
|||||
Net
increase (decrease) in cash and cash equivalents
|
428
|
(228
|
)
|
||||||
Cash
and cash equivalents, beginning of period
|
584
|
1,076
|
|||||||
Cash
and cash equivalents, end of period
|
$
|
1,012
|
$
|
848
|
Three
Months Ended
|
|||||||
March
31,
|
|||||||
2009
|
2008
|
||||||
(In
thousands)
|
|||||||
Net
income (loss)
|
$
|
(147,493
|
)
|
$
|
77,064
|
||
Other
comprehensive income (loss), net of taxes:
|
|||||||
Change in value of derivative instruments used as
|
|||||||
cash
flow hedges, net of tax of $29,406 and ($13,294)
|
49,005
|
(22,664
|
)
|
||||
Reclassification
- derivative settlements,
|
|||||||
net
of tax of ($9,847) and ($1)
|
(16,554
|
)
|
(1
|
)
|
|||
Ineffective
portion of derivatives, net of tax of $16 and zero
|
28
|
—
|
|||||
Comprehensive
income (loss)
|
$
|
(115,014
|
)
|
$
|
54,399
|
Income/(Loss)
|
Weighted
Shares
|
Per-Share
|
||||||||
(Numerator)
|
(Denominator)
|
Amount
|
||||||||
(In
thousands except per share amounts)
|
||||||||||
For
the three months ended
|
||||||||||
March
31, 2009:
|
||||||||||
Basic
earnings (loss) per common share
|
$
|
(147,493
|
)
|
46,921
|
(3.14
|
)
|
||||
Effect
of dilutive stock options, restricted
|
||||||||||
stock
and stock appreciation rights
|
—
|
—
|
—
|
|||||||
Diluted
earnings (loss) per common share
|
$
|
(147,493
|
)
|
46,921
|
(3.14
|
)
|
||||
For
the three months ended
|
||||||||||
March
31, 2008:
|
||||||||||
Basic
earnings per common share
|
$
|
77,064
|
46,481
|
$
|
1.66
|
|||||
Effect
of dilutive stock options, restricted
|
||||||||||
stock
and stock appreciation rights
|
—
|
319
|
(0.01
|
)
|
||||||
Diluted
earnings per common share
|
$
|
77,064
|
46,800
|
$
|
1.65
|
March
31,
|
||||||||
2009
|
2008
|
|||||||
Options
and SARs
|
374,921
|
105,665
|
||||||
Average
Exercise Price
|
$
|
47.09
|
$
|
56.33
|
March
31,
|
December
31,
|
||||||
2009
|
2008
|
||||||
(In
thousands)
|
|||||||
Revolving
credit facility,
|
|||||||
with
interest of 3.0% at March 31, 2009 and
|
|||||||
3.2%
at December 31, 2008
|
$
|
163,500
|
$
|
199,500
|
|||
Less
current portion
|
—
|
—
|
|||||
Total
long-term debt
|
$
|
163,500
|
$
|
199,500
|
|||
·
|
the
payment of dividends (other than stock dividends) during any fiscal year
in excess of 25% of our consolidated net income for the preceding fiscal
year;
|
·
|
the
incurrence of additional debt with certain limited exceptions;
and
|
·
|
the
creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any of our properties, except in favor of
our lenders.
|
·
|
consolidated
net worth of at least $900 million;
|
·
|
a
current ratio (as defined in the Credit Facility) of not less than 1 to 1;
and
|
·
|
a leverage ratio of long-term debt to consolidated EBITDA (as defined in the Credit Facility) for the most recently ended rolling four fiscal quarters of no greater than 3.50 to 1.0. |
March
31,
|
December
31,
|
||||||
2009
|
2008
|
||||||
(In
thousands)
|
|||||||
Plugging
liability
|
$
|
50,598
|
$
|
49,230
|
|||
Workers’
compensation
|
23,059
|
23,473
|
|||||
Separation
benefit plans
|
6,157
|
6,435
|
|||||
Gas
balancing liability
|
3,364
|
3,364
|
|||||
Deferred
compensation plan
|
2,047
|
2,030
|
|||||
Retirement
agreements
|
37
|
110
|
|||||
85,262
|
84,642
|
||||||
Less
current portion
|
11,401
|
10,615
|
|||||
Total
other long-term liabilities
|
$
|
73,861
|
$
|
74,027
|
Three
Months Ended
March
31,
|
|||||||
2009
|
2008
|
||||||
(In
thousands)
|
|||||||
Plugging
liability, January 1:
|
$
|
49,230
|
$
|
33,191
|
|||
Accretion
of discount
|
632
|
422
|
|||||
Liability
incurred
|
898
|
588
|
|||||
Liability
settled
|
(202
|
)
|
(163
|
)
|
|||
Revision
of estimates
|
40
|
47
|
|||||
Plugging
liability, March 31:
|
50,598
|
34,085
|
|||||
Less
current portion
|
1,135
|
710
|
|||||
Total
long-term plugging liability
|
$
|
49,463
|
$
|
33,375
|
Three
Months Ended
|
|||||||
March
31,
|
|||||||
2009
|
2008
|
||||||
Shares
granted
|
—
|
14,500
|
|||||
Estimated
fair value (in millions)
|
$
|
—
|
$
|
0.6
|
|||
Percentage
of shares granted
|
|||||||
expected
to be distributed
|
—
|
%
|
89
|
%
|
|||
Term
|
Amount
|
Fixed
Rate
|
Floating
Rate
|
|||
December
2007 – May 2012
|
$ 15,000,000
|
4.53%
|
3
month LIBOR
|
|||
December
2007 – May 2012
|
$ 15,000,000
|
4.16%
|
3
month LIBOR
|
·
|
Swaps. We
receive or pay a fixed price for the hedged commodity and pay or receive a
floating market price to the counterparty. The fixed-price
payment and the floating-price payment are netted, resulting in a net
amount due to or from the
counterparty.
|
·
|
Collars. A
collar contains a fixed floor price (put) and a ceiling price
(call). If the market price exceeds the call strike price or
falls below the put strike price, we receive the fixed price and pay the
market price. If the market price is between the call and the
put strike price, no payments are due from either
party.
|
·
|
Basis Swaps. We receive
or pay the NYMEX settlement value plus or minus a fixed delivery point
price for the hedged commodity and pay or receive the published index
price at the specified delivery point. We use basis swaps to hedge the
price risk between NYMEX and its physical delivery
points.
|
Term
|
Commodity
|
Hedged
Volume
|
Weighted
Average Fixed Price for Swaps
|
Hedged
Market
|
||||
Apr’09
– Dec’09
|
Crude
oil - collar
|
500
Bbl/day
|
$100.00
put & $156.25 call
|
WTI
– NYMEX
|
||||
Apr’09
– Dec’09
|
Crude
oil – swap
|
2,000
Bbl/day
|
$51.87
|
WTI
– NYMEX
|
||||
Apr’09
– Dec’09
|
Natural
gas - collar
|
10,000
MMBtu/day
|
$
8.22 put & $10.80 call
|
IF –
NYMEX (HH)
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
7.01
|
IF –
Tenn Zone 0
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
6.32
|
IF –
CEGT
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
25,000
MMBtu/day
|
$
5.57
|
IF –
PEPL
|
||||
Jan’10
– Dec’10
|
Crude
oil – swap
|
1,000
Bbl/day
|
$59.81
|
WTI
– NYMEX
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
15,000
MMBtu/day
|
$
7.20
|
IF –
NYMEX (HH)
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
20,000
MMBtu/day
|
$
6.89
|
IF –
Tenn Zone 0
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
6.12
|
IF –
CEGT
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
20,000
MMBtu/day
|
$
5.67
|
IF –
PEPL
|
||||
Jan’10
– Dec’10
|
Natural
gas – basis differential swap
|
10,000
MMBtu/day
|
($0.79)
|
PEPL
– NYMEX
|
Term
|
Commodity
|
Hedged
Volume
|
Basis
Differential
|
Hedged
Market
|
||||
Apr’09
– Dec’09
|
Natural
gas – basis differential swap
|
10,000
MMBtu/day
|
($1.02)
|
PEPL
– NYMEX
|
||||
Apr’09
– Dec’09
|
Natural
gas – basis differential swap
|
10,000
MMBtu/day
|
($1.10)
|
CEGT
– NYMEX
|
Term
|
Commodity
|
Hedged
Volume
|
Weighted
Average Fixed Price for Swaps
|
Hedged
Market
|
||||
Jan’10
– Dec’10
|
Crude
oil – swap
|
500
Bbl/day
|
$64.45
|
WTI
– NYMEX
|
Derivative
Assets
|
|||||||||
Fair
Value
|
|||||||||
March
31,
|
December
31,
|
||||||||
Balance
Sheet Location
|
2009
|
2008
|
|||||||
Derivatives
designated as hedging instruments
|
(In
thousands)
|
||||||||
Commodity
derivatives:
|
|||||||||
Current
|
Current
derivative assets
|
$
|
86,274
|
$
|
51,130
|
||||
Long-term
|
Non-current
derivative assets
|
22,249
|
5,218
|
||||||
Total
derivatives designated as hedging instruments
|
108,523
|
56,348
|
|||||||
Derivatives
not designated as hedging instruments
|
|||||||||
Commodity
derivatives:
|
|||||||||
Current
|
Current
derivative assets
|
—
|
1,047
|
||||||
Total
derivatives not designated as hedging instruments
|
—
|
1,047
|
|||||||
Total
derivative assets
|
$
|
108,523
|
$
|
57,395
|
Derivative
Liabilities
|
||||||||
Fair
Value
|
||||||||
March
31,
|
December
31,
|
|||||||
Balance
Sheet Location
|
2009
|
2008
|
||||||
Derivatives
designated as hedging instruments
|
(In
thousands)
|
|||||||
Interest
rate swaps:
|
||||||||
Current
|
Current
portion of derivative liabilities
|
$
|
804
|
$
|
736
|
|||
Long-term
|
Other
long-term derivative liabilities
|
1,675
|
1,780
|
|||||
Commodity
derivatives:
|
||||||||
Current
|
Current
portion of derivative liabilities
|
713
|
745
|
|||||
Long-term
|
Other
long-term derivative liabilities
|
235
|
—
|
|||||
Total
derivatives designated as hedging instruments
|
3,427
|
3,261
|
||||||
Derivatives
not designated as hedging instruments
|
||||||||
Commodity
derivatives (basis swaps):
|
||||||||
Current
|
Current
portion of derivative liabilities
|
876
|
—
|
|||||
Total
derivatives not designated as hedging instruments
|
876
|
—
|
||||||
Total
derivative liabilities
|
$
|
4,303
|
$
|
3,261
|
Derivatives
in Cash Flow Hedging Relationships
|
Amount of Gain or (Loss) Recognized in OCI on Derivative (Effective Portion) (1) | |||||||
2009
|
2008
|
|||||||
(In
thousands)
|
||||||||
Interest
rate swaps
|
$
|
(1,555
|
)
|
$
|
(954
|
)
|
||
Commodity
derivatives
|
67,318
|
(20,553
|
)
|
|||||
Total
|
$
|
65,763
|
$
|
(21,507
|
)
|
Derivative
Instrument
|
Location
of Gain or (Loss) Reclassified from Accumulated OCI into Income &
Location of Gain or (Loss) Recognized in Income
|
Amount of Gain or
(Loss) Reclassified from Accumulated OCI into Income (1)
|
Amount of Gain or
(Loss) Recognized in Income (2)
|
||||||||||||
2009
|
2008
|
2009
|
2008
|
||||||||||||
(In
thousands)
|
|||||||||||||||
Commodity
derivatives
|
Oil
and natural gas revenue
|
$
|
26,589
|
$
|
(112
|
)
|
$
|
(44
|
)
|
$
|
—
|
||||
Commodity
derivatives
|
Gas
gathering and processing revenue
|
—
|
(119
|
)
|
—
|
—
|
|||||||||
Commodity
derivatives
|
Gas
gathering and processing operating costs
|
—
|
182
|
—
|
—
|
||||||||||
Interest
rate swaps
|
Interest,
net
|
(188
|
)
|
51
|
—
|
—
|
|||||||||
Total
|
$
|
26,401
|
$
|
2
|
$
|
(44
|
)
|
$
|
—
|
Derivatives
Not Designated as Hedging Instruments
|
Location
of Gain or (Loss) Recognized in Income on Derivative
|
Amount
of Gain or (Loss) Recognized in Income on Derivative
|
|||||||
2009
|
2008
|
||||||||
(In
thousands)
|
|||||||||
Commodity
derivatives (basis swaps)
|
Oil
and natural gas revenue
|
$
|
(1,108
|
)
|
$
|
—
|
|||
Total
|
$
|
(1,108
|
)
|
$
|
—
|
·
|
Level
1 - unadjusted quoted prices in active markets for identical assets and
liabilities.
|
·
|
Level
2 - significant observable pricing inputs other than quoted prices
included within level 1 that are either directly or indirectly observable
as of the reporting date. Essentially, inputs (variables used
in the pricing models) that are derived principally from or corroborated
by observable market data.
|
·
|
Level
3 - generally unobservable inputs which are developed based on the best
information available and may include our own internal
data.
|
March 31, 2009
|
|||||||||||||
Level
1
|
Level
2
|
Level
3
|
Total
|
||||||||||
(In
thousands)
|
|||||||||||||
Financial
assets (liabilities):
|
|||||||||||||
Interest
rate swaps
|
$
|
—
|
$
|
—
|
$
|
(2,479
|
)
|
$
|
(2,479
|
)
|
|||
Commodity
derivatives
|
$
|
—
|
$
|
(2,714
|
)
|
$
|
109,413
|
$
|
106,699
|
Net
Derivatives
|
||||||||
For
the Three Months Ended
March
31, 2009
|
||||||||
Interest
Rate Swaps
|
Commodity
Swaps and Collars
|
|||||||
(In
thousands)
|
||||||||
Beginning
of period
|
$
|
(2,516
|
)
|
$
|
58,508
|
|||
Total
gains or losses (realized and unrealized):
|
||||||||
Included
in earnings (1)
|
(188
|
)
|
23,878
|
|||||
Included
in other comprehensive income (loss)
|
37
|
52,873
|
||||||
Purchases,
issuance and settlements
|
188
|
(25,846
|
)
|
|||||
End
of period
|
$
|
(2,479
|
)
|
$
|
109,413
|
|||
Total
gains (losses) for the period included in earnings
|
||||||||
attributable
to the change in unrealized gain (loss)
|
||||||||
relating
to assets still held as of March 31, 2009
|
$
|
—
|
$
|
(1,968
|
)
|
(1)
|
Interest
rate swaps and commodity sales swaps and collars are reported in the
condensed consolidated statements of operations in interest, net and
revenues, respectively.
|
Three
Months Ended
|
|||||||
March
31,
|
|||||||
2009
|
2008
|
||||||
(In
thousands)
|
|||||||
Revenues:
|
|||||||
Contract
drilling
|
$
|
91,324
|
$
|
163,914
|
|||
Elimination
of inter-segment revenue
|
2,625
|
16,667
|
|||||
Contract
drilling net of
|
|||||||
inter-segment
revenue
|
88,699
|
147,247
|
|||||
Oil
and natural gas
|
88,904
|
130,002
|
|||||
Gas
gathering and processing
|
30,656
|
56,559
|
|||||
Elimination
of inter-segment revenue
|
8,513
|
12,336
|
|||||
Gas
gathering and processing
|
|||||||
net
of inter-segment revenue
|
22,143
|
44,223
|
|||||
Other
|
1,316
|
(110
|
)
|
||||
Total
revenues
|
$
|
201,062
|
$
|
321,362
|
|||
Operating
income (loss) (1):
|
|||||||
Contract
drilling
|
$
|
25,750
|
$
|
57,422
|
|||
Oil
and natural gas (2)
|
(255,159
|
)
|
66,686
|
||||
Gas
gathering and processing
|
(2,595
|
)
|
5,670
|
||||
Total
operating income (loss)
|
(232,004
|
)
|
129,778
|
||||
General
and administrative expense
|
(6,089
|
)
|
(6,525
|
)
|
|||
Interest
expense, net
|
(477
|
)
|
(820
|
)
|
|||
Other
income - net
|
1,316
|
(110
|
)
|
||||
Income
(loss) before income taxes
|
$
|
(237,254
|
)
|
$
|
122,323
|
(1)
|
Operating
income (loss) is total operating revenues less operating expenses,
depreciation, depletion, amortization and impairment and does not include
non-operating revenues, general corporate expenses, interest expense or
income taxes.
|
(2) | In March 2009, we had an impairment of oil and natural gas properties of $281.2 million pre-tax ($175.1 million net of tax) due to low commodity prices at the end of the first quarter 2009. |
• General
|
• Business
Outlook
|
• Executive
Summary
|
• Financial
Condition and Liquidity
|
• New
Accounting Pronouncements
|
• Results
of Operations
|
• Contract Drilling –
carried out by our subsidiary Unit Drilling Company and its subsidiaries.
This segment contracts to drill onshore oil and natural gas wells for
others and for our own account.
|
• Oil and Natural Gas –
carried out by our subsidiary Unit Petroleum Company. This segment
explores, develops, acquires and produces oil and natural gas properties
for our own account.
|
• Gas Gathering and Processing
(Mid-Stream) – carried out by
our subsidiary Superior Pipeline Company, L.L.C. and its subsidiaries.
This segment buys, sells, gathers, processes and treats natural gas for
third parties and for our own
account.
|
Date
|
Gas Spot Price Henry Hub
($
per MMBtu)
|
Crude
Oil WTI-Cushing, OK
($
per Bbl)
|
||||
July
1, 2008
|
$
|
13.19
|
$
|
140.99
|
||
August
1, 2008
|
$
|
9.26
|
$
|
125.10
|
||
September
1, 2008
|
$
|
8.24
|
$
|
115.48
|
||
October
1, 2008
|
$
|
7.17
|
$
|
98.55
|
||
November
1, 2008
|
$
|
6.20
|
$
|
67.81
|
||
December
1, 2008
|
$
|
6.44
|
$
|
49.28
|
||
January
1, 2009
|
$
|
5.63
|
$
|
44.61
|
||
February
1, 2009
|
$
|
4.77
|
$
|
41.70
|
||
March
1, 2009
|
$
|
4.04
|
$
|
44.76
|
||
April
1, 2009
|
$
|
3.58
|
$
|
48.39
|
||
May
1, 2009
|
$
|
3.25
|
$
|
53.20
|
Period
|
Average
Rigs in Use
|
Average
Dayrates
|
|||||
July
2008
|
108.8
|
$
|
18,276
|
||||
August
2008
|
111.2
|
$
|
18,624
|
||||
September
2008
|
112.1
|
$
|
19,044
|
||||
October
2008
|
111.5
|
$
|
19,229
|
||||
November
2008
|
97.8
|
$
|
19,426
|
||||
December
2008
|
81.0
|
$
|
19,352
|
||||
January
2009
|
63.8
|
$
|
18,993
|
||||
February
2009
|
52.2
|
$
|
18,414
|
||||
March
2009
|
42.2
|
$
|
18,356
|
(1)
|
(1)
|
These
average dayrates in March 2009 include 18 term contracts, of which four
will roll off and one is up for renewal during the second quarter of 2009,
two are up for renewal during the third quarter of 2009, six are up for
renewal during the fourth quarter of 2009 and the remaining five are up
for renewal beyond 2009.
|
·
|
In
March 2009, we incurred a non-cash ceiling test write down of our oil and
natural gas properties of $281.2 million pre-tax ($175.1 million net of
tax) as a result of a decline in commodity prices as compared to those
existing at year end 2008.
|
·
|
As
a result of lower commodity prices combined with service costs that remain
relatively high, we have reduced the number of gross wells we plan to
drill in 2009 by approximately 50% from the number of gross wells drilled
in 2008.
|
·
|
In
late 2008, as a result of the significant decline in commodity prices and
the resulting drop in demand for our drilling rigs, we stored a 1,500
horsepower diesel electric drilling rig that was scheduled to be placed
into service in North Dakota during the first quarter of 2009. The
mobilization has been delayed pending final negotiation with our customer.
In addition, after discussions with our customers, we postponed the
construction of eight additional drilling rigs we had previously
anticipated building and instead substituted drilling rigs we already
owned. As a result of existing contractual obligations, we
expect to take delivery of a new drilling rig during the fourth quarter of
2009.
|
·
|
Due
to declining commodity prices of oil and natural gas, several of our
drilling rig customers have significantly reduced their drilling budgets
for 2009, resulting in a significant reduction in the average utilization
of our drilling rig fleet. Our average utilization rate was 81%
for the nine months ended September 30, 2008, 61% for the month of
December 2008 and 32% for the month of March 2009. We currently expect
this rate to continue to be depressed throughout
2009.
|
·
|
We
have reduced our total 2009 estimated capital expenditures for all three
of our business segments by approximately 60% compared to 2008, excluding
acquisitions, in order to focus keeping our capital expenditures within
anticipated internally generated cash flow.
|
·
|
Reduced
prices for ethane resulted in curtailment of certain liquids production
early in the first quarter of 2009.
|
• the
demand for and the dayrates we receive for our drilling
rigs;
|
• the
quantity of natural gas, oil and NGLs we produce;
|
• the
prices we receive for our natural gas production and, to a lesser extent,
the prices we receive for our oil and NGL production;
and
|
• the
margins we obtain from our natural gas gathering and processing
contracts.
|
March
31,
|
%
|
||||||||||
2009
|
2008
|
Change
|
(2)
|
||||||||
(In
thousands except percentages)
|
|||||||||||
Working
capital
|
$
|
103,001
|
$
|
36,095
|
185
|
%
|
|||||
Long-term
debt
|
$
|
163,500
|
$
|
116,600
|
40
|
%
|
|||||
Shareholders’
equity (1)
|
$
|
1,528,917
|
$
|
1,496,981
|
2
|
%
|
|||||
Ratio
of long-term debt to total capitalization (1)
|
10
|
%
|
7
|
%
|
43
|
%
|
|||||
Net
income (loss) (1)
|
$
|
(147,493
|
)
|
$
|
77,064
|
NM
|
%
|
||||
Net
cash provided by operating activities
|
$
|
172,890
|
$
|
158,790
|
9
|
%
|
|||||
Net
cash used in investing activities
|
$
|
(112,034
|
)
|
$
|
(158,768
|
)
|
(29
|
)%
|
|||
Net
cash used in financing activities
|
$
|
(60,428
|
)
|
$
|
(250
|
)
|
NM
|
%
|
(1)
|
In
March 2009, we incurred a non-cash ceiling test write down of our oil and
natural gas properties of $281.2 million pre-tax ($175.1 million net of
tax) due to low commodity prices at quarter-end. The write down impacted
our 2009 shareholders’ equity, ratio of long-term debt to total
capitalization and net income. There was no impact on our
compliance with the covenants contained in our Credit
Facility.
|
(2)
|
NM
– A percentage calculation is not meaningful due to a zero-value
denominator or a percentage change greater than
200.
|
Three
Months Ended March 31,
|
%
|
|||||||||
2009
|
2008
|
Change
|
||||||||
Contract
Drilling:
|
||||||||||
Average
number of our drilling rigs in use during
|
||||||||||
the
period
|
52.8
|
100.6
|
(48
|
)%
|
||||||
Total
number of drilling rigs owned at the end
|
||||||||||
of
the period
|
131
|
129
|
2
|
%
|
||||||
Average
dayrate
|
$
|
18,638
|
$
|
17,997
|
4
|
%
|
||||
Oil
and Natural Gas:
|
||||||||||
Oil
production (MBbls)
|
343
|
292
|
17
|
%
|
||||||
Natural
gas liquids production (MBbls)
|
393
|
306
|
28
|
%
|
||||||
Natural
gas production (MMcf)
|
11,862
|
11,161
|
6
|
%
|
||||||
Average
oil price per barrel received
|
$
|
50.51
|
$
|
93.32
|
(46
|
)%
|
||||
Average
oil price per barrel received excluding hedges
|
$
|
38.52
|
$
|
96.25
|
(60
|
)%
|
||||
Average
NGL price per barrel received
|
$
|
18.69
|
$
|
52.04
|
(64
|
)%
|
||||
Average
NGL price per barrel received excluding hedges
|
$
|
18.69
|
$
|
51.49
|
(64
|
)%
|
||||
Average
natural gas price per mcf received
|
$
|
5.44
|
$
|
7.65
|
(29
|
)%
|
||||
Average
natural gas price per mcf received excluding hedges
|
$
|
3.48
|
$
|
7.60
|
(54
|
)%
|
||||
Mid-Stream:
|
||||||||||
Gas
gathered—MMBtu/day
|
192,320
|
200,697
|
(4
|
)%
|
||||||
Gas
processed—MMBtu/day
|
72,650
|
59,797
|
21
|
%
|
||||||
Gas
liquids sold — gallons/day
|
218,762
|
183,924
|
19
|
%
|
||||||
Number
of natural gas gathering systems
|
37
|
36
|
3
|
%
|
||||||
Number
of processing plants
|
9
|
8
|
13
|
%
|
Lender
|
Participation
Interest
|
|
Bank
of Oklahoma, N.A.
|
18.75%
|
|
Bank
of America, N.A.
|
18.75%
|
|
BMO
Capital Markets Financing, Inc.
|
18.75%
|
|
Compass
Bank
|
17.50%
|
|
Comerica
Bank
|
08.75%
|
|
Fortis
Capital Corp.
|
08.75%
|
|
Calyon
New York Branch
|
08.75%
|
|
100.00%
|
|
|
• the
payment of dividends (other than stock dividends) during any fiscal year
in excess of 25% of our
|
consolidated net income for the preceding fiscal
year;
|
• the
incurrence of additional debt with certain very limited exceptions;
and
|
• the
creation or existence of mortgages or liens, other than those in the
ordinary course of business, on any
|
of our properties, except in favor of our
lenders.
|
|
|
• a
consolidated net worth of at least $900.0
million;
|
• a
current ratio (as defined in the Credit Facility) of not less than 1 to 1;
and
|
• a
leverage ratio of long-term debt to consolidated EBITDA (as defined in the
Credit Facility) for the
|
most recently ended rolling four fiscal quarters of no greater than 3.50
to 1.0.
|
Term
|
Amount
|
Fixed
Rate
|
Floating
Rate
|
|||
December
2007 – May 2012
|
$ 15,000,000
|
4.53%
|
3
month LIBOR
|
|||
December
2007 – May 2012
|
$ 15,000,000
|
4.16%
|
3
month LIBOR
|
Payments
Due by Period
|
|||||||||||||||||
Less
Than
|
2-3
|
4-5
|
After
|
||||||||||||||
Total
|
1
Year
|
Years
|
Years
|
5
Years
|
|||||||||||||
(In
thousands)
|
|||||||||||||||||
Bank
debt (1)
|
$
|
180,227
|
$
|
5,314
|
$
|
10,627
|
$
|
164,286
|
$
|
—
|
|||||||
Retirement
agreements (2)
|
37
|
37
|
—
|
—
|
—
|
||||||||||||
Operating
leases (3)
|
2,331
|
1,746
|
585
|
—
|
—
|
||||||||||||
Drill
pipe, drilling components and
|
|||||||||||||||||
equipment
purchases (4)
|
51,396
|
36,580
|
14,816
|
—
|
—
|
||||||||||||
Total
contractual obligations
|
$
|
233,991
|
$
|
43,677
|
$
|
26,028
|
$
|
164,286
|
$
|
—
|
(1)
|
See
previous discussion in MD&A regarding our Credit Facility. This
obligation is presented in accordance with the terms of the Credit
Facility and includes interest calculated using our March 31, 2009
interest rate of 3.2% which includes the effect of the interest rate
swaps.
|
(2)
|
In
the second quarter of 2001, we recorded $1.3 million in additional
employee benefit expenses for the present value of a separation agreement
made in connection with the retirement of King Kirchner from his position
as chief executive officer. The liability associated with this expense,
including accrued interest, is paid in monthly payments which started in
July 2003 and continues through June
2009.
|
(3)
|
We
lease office space or yards in Tulsa, Oklahoma; Canadian and Houston,
Texas; Englewood and Denver, Colorado; Pinedale, Wyoming; and Pittsburgh,
Pennsylvania under the terms of operating leases expiring through January,
2012. Additionally, we have several equipment leases and lease space on
short-term commitments to stack excess drilling rig equipment and
production inventory.
|
(4)
|
For
the next twelve months, we have committed to purchase approximately $36.6
million of new drilling rig components, drill pipe, drill collars and
related equipment. Beyond March 2010, we have committed to purchase
approximately $14.8 million of new drill pipe and drill
collars.
|
Estimated Amount of Commitment
Expiration Per Period
|
||||||||||||||||
Less
|
||||||||||||||||
Total
|
Than
1
|
2-3
|
4-5
|
After
5
|
||||||||||||
Other
Commitments
|
Accrued
|
Year
|
Years
|
Years
|
Years
|
|||||||||||
(In
thousands)
|
||||||||||||||||
Deferred
compensation plan (1)
|
$
|
2,047
|
Unknown
|
Unknown
|
Unknown
|
Unknown
|
||||||||||
Separation
benefit plans (2)
|
$
|
6,157
|
$
|
1,304
|
Unknown
|
Unknown
|
Unknown
|
|||||||||
Derivative
liabilities – commodity hedges
|
$
|
1,824
|
$
|
1,589
|
$
|
235
|
$
|
—
|
$
|
—
|
||||||
Derivative
liabilities – interest rate swaps
|
$
|
2,479
|
$
|
804
|
$
|
1,608
|
$
|
67
|
$
|
—
|
||||||
Plugging
liability (3)
|
$
|
50,598
|
$
|
1,135
|
$
|
12,750
|
$
|
3,183
|
$
|
33,530
|
||||||
Gas
balancing liability (4)
|
$
|
3,364
|
Unknown
|
Unknown
|
Unknown
|
Unknown
|
||||||||||
Repurchase
obligations (5)
|
$
|
—
|
Unknown
|
Unknown
|
Unknown
|
Unknown
|
||||||||||
Workers’
compensation liability (6)
|
$
|
23,059
|
$
|
8,924
|
$
|
3,857
|
$
|
1,234
|
$
|
9,044
|
(1)
|
We
provide a salary deferral plan which allows participants to defer the
recognition of salary for income tax purposes until actual distribution of
benefits, which occurs at either termination of employment, death or
certain defined unforeseeable emergency hardships. We recognize payroll
expense and record a liability, included in other long-term liabilities in
our Condensed Consolidated Balance Sheet, at the time of
deferral.
|
(2)
|
Effective
January 1, 1997, we adopted a separation benefit plan (“Separation Plan”).
The Separation Plan allows eligible employees whose employment with us is
involuntarily terminated or, in the case of an employee who has completed
20 years of service, voluntarily or involuntarily terminated, to receive
benefits equivalent to four weeks salary for every whole year of service
completed with the company up to a maximum of 104 weeks. To receive
payments the recipient must waive any claims against us in exchange for
receiving the separation benefits. On October 28, 1997, we adopted a
Separation Benefit Plan for Senior Management (“Senior Plan”). The Senior
Plan provides certain officers and key executives of the company with
benefits generally equivalent to the Separation Plan. The Compensation
Committee of the Board of Directors has absolute discretion in the
selection of the individuals covered in this plan. On May 5, 2004 we also
adopted the Special Separation Benefit Plan (“Special Plan”). This plan is
identical to the Separation Benefit Plan with the exception that the
benefits under the plan vest on the earliest of a participant’s reaching
the age of 65 or serving 20 years with the company. On December 31, 2008,
all these plans were amended to bring the plans into compliance with
Section 409A of the Internal Revenue Code of 1986, as
amended. At March 31, 2009, there were 35 eligible employees to
participate in the Special Plan.
|
(3)
|
When
a well is drilled or acquired, under Financial Accounting Standards No.
143 (FAS 143), “Accounting for Asset Retirement Obligations,” we have
recorded the fair value of liabilities associated with the retirement of
long-lived assets (mainly plugging and abandonment costs for our depleted
wells).
|
(4)
|
We
have recorded a liability for those properties we believe do not have
sufficient oil, NGLs and natural gas reserves to allow the under-produced
owners to recover their under-production from future production
volumes.
|
(5)
|
We
formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy
Income Limited Partnership along with private limited partnerships (the
“Partnerships”) with certain qualified employees, officers and directors
from 1984 through 2008, with a subsidiary of ours serving as general
partner. The Partnerships were formed for the purpose of conducting oil
and natural gas acquisition, drilling and development operations and
serving as co-general partner with us in any additional limited
partnerships formed during that year. The Partnerships participated on a
proportionate basis with us in most drilling operations and most producing
property acquisitions commenced by us for our own account during the
period from the formation of the Partnership through December 31 of that
year. These partnership agreements require, on the election of a limited
partner, that we repurchase the limited partner’s interest at amounts to
be determined by appraisal in the future. Such repurchases in any one year
are limited to 20% of the units outstanding. We made repurchases of
$241,000 in 2008, and did not have any repurchases in 2009 or
2007.
|
(6)
|
We
have recorded a liability for future estimated payments related to
workers’ compensation claims primarily associated with our contract
drilling segment.
|
Term
|
Amount
|
Fixed
Rate
|
Floating
Rate
|
Fair
Value Asset (Liability)
|
||||
($
in thousands)
|
||||||||
December
2007 – May 2012
|
$ 15,000
|
4.53%
|
3
month LIBOR
|
$ (1,326)
|
||||
December
2007 – May 2012
|
$ 15,000
|
4.16%
|
3
month LIBOR
|
(1,153)
|
||||
$ (2,479)
|
April
– December 2009
|
January
– December 2010
|
||||||
Daily
oil production
|
66
|
%
|
39
|
%
|
|||
Daily
natural gas production
|
70
|
%
|
48
|
%
|
2009
|
2008
|
||||||
Increases
(decreases) in:
|
(In
thousands)
|
||||||
Oil
and natural gas revenue:
|
|||||||
Realized
gains (losses) on oil and natural gas derivatives
|
$
|
27,405
|
$
|
(112
|
)
|
||
Unrealized
losses on ineffectiveness of cash flow hedges
|
(44
|
)
|
—
|
||||
Unrealized
losses on non-qualifying oil and natural gas derivatives
|
(1,924
|
)
|
—
|
||||
Total
increase on oil and natural gas revenues due to
derivatives
|
25,437
|
(112
|
)
|
||||
Gas
gathering and processing revenue (all realized gains
(losses))
|
—
|
(119
|
)
|
||||
Gas
gathering and processing operating costs (all realized (gains)
losses)
|
—
|
(182
|
)
|
||||
Impact
on pre-tax earnings
|
$
|
25,437
|
$
|
(49
|
)
|
Quarter
Ended March 31,
|
Percent
|
|||||||||
2009
|
2008
|
Change
|
(1)
|
|||||||
Total
revenue
|
$
|
201,062,000
|
$
|
321,362,000
|
(37
|
)%
|
||||
Net
income (loss)
|
$
|
(147,493,000
|
)
|
$
|
77,064,000
|
NM
|
%
|
|||
Contract
Drilling:
|
||||||||||
Revenue
|
$
|
88,699,000
|
$
|
147,247,000
|
(40
|
)%
|
||||
Operating
costs excluding depreciation
|
$
|
50,330,000
|
$
|
74,461,000
|
(32
|
)%
|
||||
Percentage
of revenue from daywork contracts
|
100
|
%
|
100
|
%
|
—
|
%
|
||||
Average
number of drilling rigs in use
|
52.8
|
100.6
|
(48
|
)%
|
||||||
Average
dayrate on daywork contracts
|
$
|
18,638
|
$
|
17,997
|
4
|
%
|
||||
Depreciation
|
$
|
12,619,000
|
$
|
15,364,000
|
(18
|
)%
|
||||
Oil
and Natural Gas:
|
||||||||||
Revenue
|
$
|
88,904,000
|
$
|
130,002,000
|
(32
|
)%
|
||||
Operating
costs excluding depreciation, depletion,
|
||||||||||
amortization
and impairment
|
$
|
24,816,000
|
$
|
27,601,000
|
(10
|
)%
|
||||
Average
oil price (Bbl)
|
$
|
50.51
|
$
|
93.32
|
(46
|
)%
|
||||
Average
NGL price (Bbl)
|
$
|
18.69
|
$
|
52.04
|
(64
|
)%
|
||||
Average
natural gas price (Mcf)
|
$
|
5.44
|
$
|
7.65
|
(29
|
)%
|
||||
Oil
production (Bbl)
|
343,000
|
292,000
|
17
|
%
|
||||||
NGL
production (Bbl)
|
393,000
|
306,000
|
28
|
%
|
||||||
Natural
gas production (Mcf)
|
11,862,000
|
11,161,000
|
6
|
%
|
||||||
Depreciation,
depletion and amortization
|
||||||||||
rate
(Mcfe)
|
$
|
2.32
|
$
|
2.41
|
(4
|
)%
|
||||
Depreciation,
depletion and amortization
|
$
|
38,006,000
|
$
|
35,715,000
|
6
|
%
|
||||
Impairment
of oil and natural gas properties
|
$
|
281,241,000
|
$
|
—
|
NM
|
%
|
||||
Mid-Stream
Operations:
|
||||||||||
Revenue
|
$
|
22,143,000
|
$
|
44,223,000
|
(50
|
)%
|
||||
Operating
costs excluding depreciation
|
||||||||||
and
amortization
|
$
|
20,677,000
|
$
|
35,072,000
|
(41
|
)%
|
||||
Depreciation
and amortization
|
$
|
4,061,000
|
$
|
3,481,000
|
17
|
%
|
||||
Gas
gathered—MMBtu/day
|
192,320
|
200,697
|
(4
|
)%
|
||||||
Gas
processed—MMBtu/day
|
72,650
|
59,797
|
21
|
%
|
||||||
Gas
liquids sold—gallons/day
|
218,762
|
183,924
|
19
|
%
|
||||||
General
and administrative expense
|
$
|
6,089,000
|
$
|
6,525,000
|
(7
|
)%
|
||||
Interest
expense, net
|
$
|
477,000
|
$
|
820,000
|
(42
|
)%
|
||||
Income
tax expense (benefit)
|
$
|
(89,761,000
|
)
|
$
|
45,259,000
|
NM
|
%
|
|||
Average
interest rate
|
4.0
|
%
|
5.4
|
%
|
(26
|
)%
|
||||
Average
long-term debt outstanding
|
$
|
195,774,000
|
$
|
137,995,000
|
42
|
%
|
(1)
|
NM
– A percentage calculation is not meaningful due to a zero-value
denominator or a percentage change greater than
200.
|
•
|
the
amount and nature of our future capital expenditures and how we expect to
fund our capital expenditures;
|
||
•
|
the
amount of wells to be drilled or reworked;
|
||
•
|
prices
for oil and natural gas;
|
||
•
|
demand
for oil and natural gas;
|
||
•
|
our
exploration prospects;
|
||
•
|
estimates
of our proved oil and natural gas reserves;
|
||
•
|
oil
and natural gas reserve potential;
|
||
•
|
development
and infill drilling potential;
|
||
•
|
our
drilling prospects;
|
||
•
|
expansion
and other development trends of the oil and natural gas
industry;
|
||
•
|
our
business strategy;
|
||
•
|
production
of oil and natural gas reserves;
|
||
•
|
growth
potential for our mid-stream operations;
|
||
•
|
gathering
systems and processing plants we plan to construct or
acquire;
|
||
•
|
volumes
and prices for natural gas gathered and processed;
|
||
•
|
expansion
and growth of our business and operations;
|
||
•
|
demand
for our drilling rigs and drilling rig rates; and
|
||
•
|
our
belief that the final outcome of our legal proceedings will not materially
affect our financial results.
|
•
|
the
risk factors discussed in this report and in the documents we incorporate
by reference;
|
||
•
|
general
economic, market or business conditions;
|
||
•
|
the
nature or lack of business opportunities that we
pursue;
|
||
•
|
demand
for our land drilling services;
|
||
•
|
changes
in laws or regulations;
|
||
•
|
the
time period associated with the current decrease in commodity prices;
and
|
||
•
|
other
factors, most of which are beyond our
control.
|
Term
|
Commodity
|
Hedged
Volume
|
Weighted
Average Fixed Price for Swaps
|
Hedged
Market
|
||||
Apr’09
– Dec’09
|
Crude
oil - collar
|
500
Bbl/day
|
$100.00
put & $156.25 call
|
WTI
– NYMEX
|
||||
Apr’09
– Dec’09
|
Crude
oil – swap
|
2,000
Bbl/day
|
$51.87
|
WTI
– NYMEX
|
||||
Apr’09
– Dec’09
|
Natural
gas - collar
|
10,000
MMBtu/day
|
$
8.22 put & $10.80 call
|
IF –
NYMEX (HH)
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
7.01
|
IF –
Tenn Zone 0
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
6.32
|
IF –
CEGT
|
||||
Apr’09
– Dec’09
|
Natural
gas – swap
|
25,000
MMBtu/day
|
$
5.57
|
IF –
PEPL
|
||||
Jan’10
– Dec’10
|
Crude
oil – swap
|
500
Bbl/day
|
$64.45
|
WTI
– NYMEX
|
||||
Jan’10
– Dec’10
|
Crude
oil – swap
|
1,000
Bbl/day
|
$59.81
|
WTI
– NYMEX
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
15,000
MMBtu/day
|
$
7.20
|
IF –
NYMEX (HH)
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
20,000
MMBtu/day
|
$
6.89
|
IF –
Tenn Zone 0
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
30,000
MMBtu/day
|
$
6.12
|
IF –
CEGT
|
||||
Jan’10
– Dec’10
|
Natural
gas – swap
|
20,000
MMBtu/day
|
$
5.67
|
IF –
PEPL
|
||||
Jan’10
– Dec’10
|
Natural
gas – basis differential swap
|
10,000
MMBtu/day
|
($0.79)
|
PEPL
– NYMEX
|
Period
|
(a)
Total
Number
of
Shares
Purchased
(1)
|
(b)
Average
Price
Paid
Per
Share(2)
|
(c)
Total
Number
of
Shares
Purchased
As
Part of
Publicly
Announced
Plans
or
Programs
(1)
|
(d)
Maximum
Number
(or
Approximate
Dollar Value)
of
Shares
That
May
Yet
Be
Purchased
Under
the
Plans
or
Programs
|
||||||||
January 1,
2009 to January 31, 2009
|
|
19,470
|
|
$
|
29.66
|
|
19,470
|
|
—
|
|||
February 1,
2009 to February 28, 2009
|
|
—
|
|
—
|
|
—
|
|
—
|
||||
March 1,
2009 to March 31, 2009
|
|
—
|
|
—
|
|
—
|
|
—
|
||||
|
|
|
|
|||||||||
Total
|
|
19,470
|
|
$
|
29.66
|
|
19,470
|
|
—
|
|||
(1)
|
The
shares were repurchased to remit withholding of taxes on the value of
stock distributed with the January 1, 2009 and January 5, 2009 vesting
distribution for grants previously made from our “Unit Corporation Stock
and Incentive Compensation Plan” adopted May 3, 2006.
|
(2)
|
The
price paid per common share represents the closing sales price of a share
of our common stock as reported by the NYSE on the day that the stock was
acquired by us.
|
15
|
Letter
re: Unaudited Interim Financial Information.
|
|
31.1
|
Certification
of Chief Executive Officer under Rule 13a – 14(a) of
the
|
|
Exchange
Act.
|
||
31.2
|
Certification
of Chief Financial Officer under Rule 13a – 14(a) of
the
|
|
Exchange
Act.
|
||
32
|
Certification
of Chief Executive Officer and Chief Financial Officer
under
|
|
Rule
13a – 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as
adopted
|
||
under
Section 906 of the Sarbanes-Oxley Act of
2002.
|
Unit
Corporation
|
||
Date: May
5, 2009
|
By: /s/ Larry D.
Pinkston
|
|
LARRY
D. PINKSTON
|
||
Chief
Executive Officer and Director
|
||
Date: May
5, 2009
|
By: /s/ David T.
Merrill
|
|
DAVID
T. MERRILL
|
||
Chief
Financial Officer and
|
||
Treasurer
|