|
DELAWARE
|
|
77-0079387
|
|
|
(State
of incorporation or organization)
|
|
(I.R.S.
Employer Identification Number)
|
|
PART
I. FINANCIAL INFORMATION
|
|
Page
|
Item
1. Financial Statements
|
||
Unaudited
Condensed Balance Sheets at September 30, 2007 and December 31,
2006
|
3
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended
September
30, 2007 and 2006
|
4
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Three Month
Periods
Ended September 30, 2007 and 2006
|
4
|
|
Unaudited
Condensed Statements of Income for the Nine Month Periods Ended September
30, 2007 and 2006
|
5
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Nine Month Periods
Ended September 30, 2007 and 2006
|
5
|
|
Unaudited
Condensed Statements of Cash Flows for the Nine Month Periods Ended
September 30, 2007 and 2006
|
6
|
|
Notes
to Unaudited Condensed Financial Statements
|
7
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
11
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
22
|
|
Item
4. Controls and Procedures
|
24
|
|
PART
II.
OTHER
INFORMATION
|
||
Item
1. Legal Proceedings
|
24
|
|
Item
1A. Risk Factors
|
24
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
24
|
|
Item
3. Defaults Upon Senior Securities
|
24
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
24
|
|
Item
5. Other Information
|
24
|
|
Item
6. Exhibits
|
25
|
September
30, 2007
|
December
31, 2006
|
||||||
ASSETS
|
|||||||
Current
assets:
|
|||||||
Cash
and cash equivalents
|
|
$
|
191
|
$
|
416
|
|
|
Short-term
investments
|
|
|
660
|
|
665
|
|
|
Accounts
receivable
|
|
|
77,320
|
|
67,905
|
|
|
Deferred income taxes
|
|
|
14,989
|
|
-
|
|
|
Fair
value of derivatives
|
|
|
6,703
|
|
7,349
|
|
|
Assets held for sale
|
662
|
8,870
|
|||||
Prepaid expenses and other
|
|
|
13,581
|
|
13,604
|
|
|
Total
current assets
|
|
|
114,106
|
98,809
|
|
||
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,237,921
|
|
1,080,631
|
|
|
Fair
value of derivatives
|
1,048
|
2,356
|
|||||
Other
assets
|
|
|
15,526
|
|
17,201
|
|
|
|
|
$
|
1,368,601
|
$
|
1,198,997
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|||
Current
liabilities:
|
|
|
|
|
|||
Accounts
payable
|
|
$
|
94,287
|
$
|
69,914
|
|
|
Property acquisition payable
|
-
|
54,400
|
|||||
Revenue and royalties payable
|
|
|
36,103
|
|
45,845
|
|
|
Accrued
liabilities
|
|
|
26,051
|
|
20,415
|
|
|
Line of credit
|
4,500
|
16,000
|
|||||
Fair value of derivatives
|
|
|
42,799
|
|
8,084
|
|
|
Other
current liabilities
|
|
|
1,335
|
|
745
|
|
|
Total current liabilities
|
|
|
205,075
|
|
215,403
|
|
|
Long-term
liabilities:
|
|
|
|
|
|||
Deferred
income taxes
|
|
|
143,320
|
|
103,515
|
|
|
Long-term debt
|
|
|
435,000
|
|
390,000
|
|
|
Abandonment
obligation
|
|
|
32,386
|
|
26,135
|
|
|
Other long-term liabilities
|
9,371
|
1,437
|
|||||
Fair value of derivatives
|
|
|
46,329
|
|
34,807
|
|
|
|
|
|
666,406
|
|
555,894
|
|
|
Shareholders'
equity:
|
|
|
|
|
|||
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
-
|
|
|
Capital stock, $.01 par value:
|
|
|
|
|
|||
Class
A Common Stock, 100,000,000 shares authorized; 42,329,886 shares
issued
and outstanding (42,098,551 in 2006)
|
|
|
423
|
|
421
|
|
|
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares
issued and outstanding (liquidation preference of
$899)
|
|
|
18
|
|
18
|
|
|
Capital
in excess of par value
|
|
|
60,449
|
|
50,166
|
|
|
Accumulated
other comprehensive loss
|
|
|
(48,410
|
)
|
|
(19,977
|
)
|
Retained
earnings
|
|
|
484,640
|
|
397,072
|
|
|
Total
shareholders' equity
|
|
|
497,120
|
|
427,700
|
|
|
|
|
$
|
1,368,601
|
$
|
1,198,997
|
|
Three
months ended September 30,
|
|||||||||||||
2007
|
2006
|
||||||||||||
REVENUES
AND OTHER INCOME ITEMS
|
|||||||||||||
Sales of oil and gas
|
$
|
118,733
|
$
|
116,168
|
|||||||||
Sales of electricity
|
12,241
|
12,592
|
|||||||||||
Gain on sale of assets
|
|
1,418
|
|
-
|
|
||||||||
Interest and other income, net
|
|
1,108
|
|
603
|
|
||||||||
|
|
|
133,500
|
|
129,363
|
|
|||||||
EXPENSES
|
|
|
|
|
|||||||||
Operating
costs – oil and gas production
|
|
|
33,995
|
|
30,950
|
|
|||||||
Operating costs – electricity generation
|
|
|
9,760
|
|
11,198
|
|
|||||||
Production
taxes
|
4,344
|
5,286
|
|||||||||||
Depreciation,
depletion & amortization - oil and gas production
|
|
|
23,356
|
|
17,974
|
|
|||||||
Depreciation, depletion & amortization - electricity
generation
|
|
|
938
|
|
825
|
|
|||||||
General
and administrative
|
|
|
9,333
|
|
9,419
|
|
|||||||
Interest
|
|
|
4,326
|
|
2,707
|
|
|||||||
Dry
hole, abandonment, impairment and exploration
|
|
|
5,175
|
|
527
|
||||||||
|
|
|
91,227
|
|
78,886
|
|
|||||||
Income
before income taxes
|
|
|
42,273
|
|
50,477
|
|
|||||||
Provision
for income taxes
|
|
|
15,418
|
|
19,103
|
|
|||||||
|
|
|
|
|
|||||||||
Net
income
|
|
$
|
26,855
|
|
$
|
31,374
|
|
||||||
|
|
|
|
|
|
||||||||
Basic
net income per share
|
|
$
|
.61
|
|
$
|
.71
|
|
||||||
|
|
|
|
|
|
||||||||
Diluted
net income per share
|
|
$
|
.60
|
|
$
|
.70
|
|
||||||
|
|
|
|
|
|
||||||||
Dividends
per share
|
|
$
|
.075
|
|
$
|
.095
|
|
||||||
|
|
|
|
|
|
||||||||
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
44,112
|
|
|
43,907
|
|
||||||
Effect
of dilutive securities:
|
|
|
|
|
|
||||||||
Equity
based compensation
|
|
|
772
|
|
|
654
|
|
||||||
Director deferred compensation
|
|
|
118
|
|
|
104
|
|
||||||
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
45,002
|
|
|
44,665
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Unaudited
Condensed Statements of Comprehensive Income
|
|
||||||||||||
Three
Month Periods Ended September 30, 2007 and 2006
|
|||||||||||||
(In
Thousands)
|
|||||||||||||
Net
income
|
$
|
26,855
|
$
|
31,374
|
|||||||||
Unrealized
gains (losses) on derivatives, net of income taxes of ($7,027)
and
$28,188, respectively
|
(10,541
|
)
|
42,282
|
||||||||||
Reclassification
of realized (gains) losses included in net income, net of income
taxes of
$1,411 and ($1,178), respectively
|
|
2,116
|
|
(1,767
|
)
|
||||||||
Comprehensive
income
|
|
$
|
18,430
|
|
$
|
71,889
|
Nine
months ended September 30,
|
|||||||||||||
2007
|
2006
|
||||||||||||
REVENUES
AND OTHER INCOME ITEMS
|
|||||||||||||
Sales of oil and gas
|
$
|
333,933
|
$
|
328,742
|
|||||||||
Sales of electricity
|
|
40,704
|
|
39,476
|
|
||||||||
Gain on sale of assets
|
51,816
|
-
|
|||||||||||
Interest and other income, net
|
|
3,754
|
|
1,898
|
|
||||||||
|
|
|
430,207
|
|
370,116
|
|
|||||||
EXPENSES
|
|
|
|
|
|||||||||
Operating
costs – oil and gas production
|
|
|
103,330
|
|
83,763
|
|
|||||||
Operating costs – electricity generation
|
|
|
35,014
|
|
36,155
|
|
|||||||
Production
taxes
|
12,297
|
11,891
|
|||||||||||
Depreciation,
depletion & amortization - oil and gas production
|
|
|
65,478
|
|
47,333
|
|
|||||||
Depreciation, depletion & amortization - electricity
generation
|
|
|
2,661
|
|
2,526
|
|
|||||||
General
and administrative
|
|
|
29,291
|
|
25,610
|
|
|||||||
Interest
|
|
|
13,593
|
|
6,745
|
|
|||||||
Commodity
derivatives
|
-
|
(736
|
)
|
||||||||||
Dry
hole, abandonment, impairment and exploration
|
|
|
9,342
|
|
11,070
|
||||||||
|
|
|
271,006
|
|
224,357
|
|
|||||||
Income
before income taxes
|
|
|
159,201
|
|
145,759
|
|
|||||||
Provision
for income taxes
|
|
|
61,534
|
|
56,930
|
|
|||||||
|
|
|
|
|
|||||||||
Net
income
|
|
$
|
97,667
|
|
$
|
88,829
|
|
||||||
|
|
|
|
|
|
||||||||
Basic
net income per share
|
|
$
|
2.22
|
|
$
|
2.02
|
|
||||||
|
|
|
|
|
|
||||||||
Diluted
net income per share
|
|
$
|
2.18
|
|
$
|
1.98
|
|
||||||
|
|
|
|
|
|
||||||||
Dividends
per share
|
|
$
|
.225
|
|
$
|
.225
|
|
||||||
|
|
|
|
|
|
||||||||
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
44,020
|
|
|
43,982
|
|
||||||
Effect
of dilutive securities:
|
|
|
|
|
|
||||||||
Equity
based compensation
|
|
|
701
|
|
|
792
|
|
||||||
Director deferred compensation
|
|
|
115
|
|
|
101
|
|
||||||
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
44,836
|
|
|
44,875
|
|
||||||
|
|
|
|
|
|
|
|
||||||
Unaudited Condensed Statements of Comprehensive
Income
|
|
||||||||||||
Nine
Month Periods Ended September 30, 2007 and 2006
|
|||||||||||||
(In
Thousands)
|
|||||||||||||
Net
income
|
$
|
97,667
|
$
|
88,829
|
|||||||||
Unrealized
gains (losses) on derivatives, net of income taxes of ($19,484)
and
$1,223, respectively
|
(29,226
|
)
|
1,834
|
||||||||||
Reclassification
of realized (gains) losses included in net income, net of income
taxes of
$529 and ($3,534), respectively
|
|
793
|
|
(5,301
|
)
|
||||||||
Comprehensive
income
|
|
$
|
69,234
|
|
$
|
85,362
|
Nine
months ended September 30,
|
||||||||||
2007
|
2006
|
|||||||||
Cash
flows from operating activities:
|
||||||||||
Net income
|
$
|
97,667
|
$
|
88,829
|
||||||
Depreciation, depletion and amortization
|
68,139
|
49,858
|
||||||||
Dry
hole and impairment
|
8,725
|
6,965
|
||||||||
Commodity derivatives
|
804
|
(264
|
)
|
|||||||
Stock-based compensation expense
|
5,437
|
3,563
|
||||||||
Deferred
income taxes
|
53,162
|
44,410
|
||||||||
Gain
on sale of oil and gas properties
|
(51,816
|
)
|
-
|
|||||||
Other,
net
|
750
|
1,749
|
||||||||
Cash paid for abandonment
|
(660
|
)
|
(569
|
)
|
||||||
Increase in current assets other than cash, cash equivalents and
short-term investments
|
(10,785
|
)
|
(17,996
|
)
|
||||||
Increase
in current liabilities other than book overdraft, line of credit,
property
acquisition payable and fair value of derivatives
|
13,116
|
8,600
|
||||||||
Net
cash provided by operating activities
|
184,539
|
185,145
|
||||||||
Cash
flows from investing activities:
|
|
|||||||||
Exploration and development of oil and gas
properties
|
|
(206,240
|
)
|
(185,773
|
)
|
|||||
Property
acquisitions
|
|
(56,167
|
)
|
(210,126
|
)
|
|||||
Additions to vehicles, drilling rigs and other fixed
assets
|
(2,944
|
)
|
(18,302
|
)
|
||||||
Proceeds from sale of asset
|
68,432
|
-
|
||||||||
Capitalized interest and other
|
(13,160
|
)
|
(5,600
|
)
|
||||||
Net
cash used in investing activities
|
|
(210,079
|
)
|
(419,801
|
)
|
|||||
Cash
flows from financing activities:
|
|
|
|
|||||||
Proceeds
from issuance of line of credit
|
285,150
|
241,750
|
||||||||
Payment
of line of credit
|
(296,650
|
)
|
(232,750
|
)
|
||||||
Proceeds
from issuance of long-term debt
|
|
179,300
|
324,700
|
|||||||
Payment of long-term debt
|
|
(134,300
|
)
|
(90,700
|
)
|
|||||
Dividends
paid
|
|
(10,036
|
)
|
(9,889
|
)
|
|||||
Change in book overdraft
|
(2,995
|
)
|
10,196
|
|||||||
Repurchase of shares of common stock
|
-
|
(15,766
|
)
|
|||||||
Proceeds from stock option exercises
|
3,051
|
2,559
|
||||||||
Excess tax benefit and other
|
1,795
|
2,918
|
||||||||
Net
cash provided by financing activities
|
|
25,315
|
233,018
|
|||||||
|
|
|||||||||
Net
decrease in cash and cash equivalents
|
|
(225
|
)
|
(1,638
|
)
|
|||||
Cash
and cash equivalents at beginning of year
|
|
416
|
1,990
|
|||||||
Cash
and cash equivalents at end of period
|
$
|
191
|
$
|
352
|
||||||
Supplemental
non-cash activity:
|
|
|
||||||||
Increase (decrease) in fair value of derivatives:
|
|
|
||||||||
Current
(net of income taxes of ($13,820) and $1,491,
respectively)
|
$
|
(20,731
|
)
|
$
|
2,237
|
|||||
Non-current
(net of income taxes of ($5,135) and ($3,803),
respectively)
|
(7,702
|
)
|
(5,704
|
)
|
||||||
Net
decrease to accumulated other comprehensive income
|
$
|
(28,433
|
)
|
$
|
(3,467
|
)
|
1.
|
General
|
2.
|
Recent
Accounting
Developments
|
2.
|
Recent
Accounting Developments
(Cont’d)
|
3.
|
Hedging
|
·
|
oil
swaps for 1,000 Bbl/D at $64.55 from July 2007 through December
2007
|
·
|
oil
swaps for 260 Bbl/D at $74 for calendar year
2008
|
·
|
oil
swaps for 240 Bbl/D at $71.50 for calendar year
2009
|
·
|
oil
collars for 1,000 Bbl/D at $60 floor and $75 ceiling prices for
calendar
year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $65.15 floor and $75 ceiling prices
for
calendar year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $65.50 floor and $78.50 ceiling prices
for
calendar year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $70 floor and $75.85 ceiling prices
from July
to December 2007
|
·
|
oil
collars for 1,000 Bbl/D at $70 floor and $76.70 ceiling prices
for
calendar year 2008
|
4.
|
Asset
Retirement
Obligations
|
4.
|
Asset
Retirement Obligations
(Cont’d)
|
|
|
|
|||||
Beginning
balance at January 1
|
|
$
|
26,135
|
||||
Liabilities
incurred
|
|
|
2,769
|
||||
Liabilities
settled
|
|
|
(1,601
|
)
|
|||
Revisions
in estimated liabilities
|
3,272
|
||||||
Accretion
expense
|
|
|
1,811
|
||||
|
|
|
|||||
Ending
balance at September 30
|
|
$
|
32,386
|
5.
|
Income
Taxes
|
Jurisdiction:
|
Tax
Years Subject to Exam:
|
Federal
|
2003
– 2006
|
California
|
2002
– 2006
|
Colorado
|
2002
– 2006
|
Utah
|
2003
– 2006
|
6.
|
Long-term
and Short-term Obligations
|
6.
|
Long-term
and Short-term Obligations
(Cont’d)
|
7.
|
Contingencies
and Commitments
|
8.
|
Asset
Sales and Impairment
|
8.
|
Asset
Sales and Impairment
(Cont’d)
|
9.
|
Subsequent
Event
|
·
|
Developing
our existing resource base
|
·
|
Acquiring
additional assets with significant growth
potential
|
·
|
Utilizing
joint ventures with respected partners to enter new
basins
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
·
|
Increased
production at North Midway-Sunset diatomite to an average 1,100 Bbl/D
in
the quarter through modification of our steam cycling practices and
well
fracturing techniques
|
·
|
Achieved
a record production at Poso Creek to an average 2,400 Bbl/D in the
quarter
|
·
|
Drilled
14 infill horizontal wells at South Midway-Sunset targeting oil pays
closer to the oil-water contact; performance is meeting
expectations
|
·
|
Accelerated
Pan Fee and Ethel D development by drilling 15 additional infill
wells
|
·
|
Accomplished
a 15 day drilling record on a Piceance mesa well as we are realizing
our
goal of reducing our drilling costs; we drilled 21 gross (7 net)
Piceance
wells
|
·
|
Completed
and tied into gathering systems 15 gross (8 net) Piceance basin operated
wells which increased Piceance net production to 11.5 MMcf/D, up
40% from
the second quarter 2007
|
·
|
Companywide
production is projected to approximate 28,000 BOE/D in the fourth
quarter
of 2007 with a projected 2007 year end exit rate of 28,200
BOE/D
|
·
|
Drilling
the next 50 well expansion on our North Midway-Sunset diatomite asset;
this activity will continue into early 2008 and the projected 2007
year
end exit rate is 1,250 Bbl/D
|
·
|
Accelerating
Poso Creek infill drilling by an additional 13 wells and expected
2007
year end exit rate is 2,600 Bbl/D
|
·
|
Continuing
to focus on reducing drilling costs of our operated Piceance mesa
wells
and we expect to complete 12 gross (6 net) Piceance wells while targeting
fourth quarter average net production in Piceance of 15
MMcf/D
|
·
|
Proceeding
with plans as announced on forming a master limited
partnership
|
|
|
September
30, 2007
(3Q07)
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06 Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
||||
Sales
of oil
|
$
|
100.1
|
$
|
97.9
|
2%
|
$
|
94.4
|
6%
|
||
Sales
of gas
|
18.6
|
18.3
|
2%
|
19.0
|
(2%)
|
|||||
Total
sales of oil and gas
|
$
|
118.7
|
$
|
116.2
|
2%
|
$
|
113.4
|
5%
|
||
Sales
of electricity
|
12.3
|
|
12.6
|
(2%)
|
13.9
|
(12%)
|
||||
Gain
on sale of assets
|
1.4
|
|
-
|
n/a
|
50.4
|
(97%)
|
||||
Interest
and other income, net
|
1.1
|
|
.6
|
83%
|
1.5
|
(27%)
|
||||
Total
revenues and other income
|
$
|
133.5
|
|
$
|
129.4
|
3%
|
$
|
179.2
|
(26%)
|
|
Net
income
|
$
|
26.9
|
|
$
|
31.4
|
(14%)
|
$
|
52.0
|
(48%)
|
|
Net
income per share (diluted)
|
$
|
.60
|
$
|
.70
|
(14%)
|
$
|
1.16
|
(48%)
|
September
30, 2007
|
%
|
September
30, 2006
|
%
|
June
30, 2007
|
%
|
|||||
Oil
and Gas
|
||||||||||
Heavy
Oil Production (Bbl/D)
|
15,806
|
59
|
16,076
|
61
|
16,129
|
59
|
||||
Light
Oil Production (Bbl/D)
|
3,675
|
14
|
4,118
|
16
|
4,034
|
15
|
||||
Total
Oil Production (Bbl/D)
|
|
19,481
|
73
|
20,194
|
76
|
20,163
|
74
|
|||
Natural
Gas Production (Mcf/D)
|
|
44,346
|
27
|
37,374
|
24
|
42,193
|
26
|
|||
Total
(BOE/D)
|
|
|
26,873
|
100
|
|
26,423
|
100
|
|
27,195
|
100
|
|
|
|
|
|
|
|||||
Per
BOE:
|
|
|
|
|
|
|||||
Average
sales price before hedging
|
|
$
|
49.35
|
$
|
50.33
|
$
|
44.72
|
|||
Average
sales price after hedging
|
|
|
47.93
|
|
47.28
|
|
45.43
|
|||
|
|
|
|
|
||||||
Oil,
per Bbl:
|
||||||||||
Average
WTI price
|
$
|
75.15
|
$
|
70.54
|
$
|
65.02
|
||||
Price
sensitive royalties
|
(5.50
|
)
|
(5.21
|
)
|
(4.20
|
)
|
||||
Quality
differential and other
|
(9.56
|
)
|
(8.76
|
)
|
(9.24
|
)
|
||||
Crude
oil hedges
|
(4.37
|
)
|
(3.99
|
)
|
(.52
|
)
|
||||
Average
oil sales price after hedging
|
$
|
55.72
|
$
|
52.58
|
$
|
51.06
|
||||
Natural
gas price:
|
||||||||||
Average
Henry Hub price per MMBtu
|
$
|
6.24
|
$
|
6.18
|
$
|
7.65
|
||||
Conversion
to Mcf
|
.31
|
.31
|
.39
|
|||||||
Natural
gas hedges
|
1.07
|
(.02
|
)
|
.71
|
||||||
Location,
quality differentials and other
|
(3.06
|
)
|
(1.36
|
)
|
(3.89
|
)
|
||||
Average
gas sales price after hedging
|
$
|
4.56
|
$
|
5.11
|
$
|
4.86
|
September
30, 2007
|
%
|
September
30, 2006
|
%
|
|||||||
Oil
and Gas
|
||||||||||
Heavy
Oil Production (Bbl/D)
|
16,019
|
60
|
15,681
|
63
|
||||||
Light
Oil Production (Bbl/D)
|
3,655
|
14
|
3,823
|
15
|
||||||
Total
Oil Production (Bbl/D)
|
|
19,674
|
74
|
19,504
|
78
|
|||||
Natural
Gas Production (Mcf/D)
|
|
41,109
|
26
|
32,348
|
22
|
|||||
Total
(BOE/D)
|
|
|
26,525
|
100
|
|
24,896
|
100
|
|||
|
|
|
|
|
|
|||||
Per
BOE:
|
|
|
|
|
|
|||||
Average
sales price before hedging
|
|
$
|
45.98
|
$
|
50.81
|
|||||
Average
sales price after hedging
|
|
|
45.82
|
|
48.33
|
|||||
|
|
|
|
|||||||
Oil,
per Bbl:
|
||||||||||
Average
WTI price
|
$
|
66.22
|
$
|
68.26
|
||||||
Price
sensitive royalties
|
(4.48
|
)
|
(5.41
|
)
|
||||||
Quality
differential and other
|
(9.26
|
)
|
(7.87
|
)
|
||||||
Crude
oil hedges
|
(1.61
|
)
|
(3.17
|
)
|
||||||
Average
oil sales price after hedging
|
$
|
50.87
|
$
|
51.81
|
||||||
Natural
gas price:
|
||||||||||
Average
Henry Hub price per MMBtu
|
$
|
7.02
|
$
|
6.89
|
||||||
Conversion
to Mcf
|
.36
|
.34
|
||||||||
Natural
gas hedges
|
.67
|
-
|
||||||||
Location,
quality differentials and other
|
(2.85
|
)
|
(1.28
|
)
|
||||||
Average
gas sales price after hedging
|
$
|
5.20
|
$
|
5.95
|
Gas
Basis Differential. Natural gas prices in the Rockies
continue to be volatile due to various factors, including takeaway
pipeline capacity, supply volumes, and regional demand issues. We
expect
the basis differential between Henry Hub (HH) and Colorado Interstate
Gas
(CIG) to narrow upon the startup of the Rockies Express Pipeline
(REX)
which is anticipated in early 2008. We have contracted 10,000 MMBtu/D
on
this pipeline to provide firm transport for a portion of our Piceance
gas
production. The CIG basis differential per MMBtu, based upon
first-of-month values, averaged $3.55 below HH and ranged from $2.68
to
$4.37 below HH in the third quarter. Although related to CIG, the
actual
basin price varies. Gas from the Piceance basin was slightly below
the CIG
price while Uinta basin gas sold for approximately $.40 below CIG
pricing.
DJ Basin gas is priced using one of two indices. Approximately two-thirds
of the pricing of our DJ natural gas is tied to the Panhandle Eastern
Pipeline (PEPL) index and the remaining volumes to the CIG. For that
portion of the production with firm transportation on either the
Cheyenne
Plains Pipeline or the KMIGT pipeline, pricing is based upon the
PEPL
index which averaged approximately $.86 below the HH index before
the cost
of transportation is considered. The remainder of the DJ Basin gas
is sold
slightly above the CIG index price.
|
September
30, 2007
|
September
30, 2006
|
June
30, 2007
|
||||||||
Electricity
|
||||||||||
Revenues
(in millions)
|
$
|
12.3
|
$
|
12.6
|
$
|
13.9
|
||||
Operating
costs (in millions)
|
$
|
9.8
|
$
|
11.2
|
$
|
11.1
|
||||
Electric
power produced - MWh/D
|
|
|
2,257
|
|
|
2,100
|
|
|
2,060
|
|
Electric
power sold - MWh/D
|
|
|
2,077
|
|
|
1,895
|
|
|
1,819
|
|
Average
sales price/MWh
|
|
$
|
71.28
|
|
$
|
79.42
|
|
$
|
84.13
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
4.84
|
|
$
|
6.14
|
|
$
|
6.46
|
|
Amount
per BOE
|
Amount
(in thousands)
|
||||||||||||||||||
|
|
September
30, 2007
|
September
30, 2006
|
June
30, 2007
|
|
September
30, 2007
|
September
30, 2006
|
June
30, 2007
|
|||||||||||
Operating
costs – oil and gas production
|
$
|
13.75
|
$
|
12.73
|
$
|
14.44
|
$
|
33,995
|
$
|
30,950
|
$
|
35,725
|
|||||||
Production
taxes
|
1.76
|
2.17
|
1.67
|
4,344
|
5,286
|
4,139
|
|||||||||||||
DD&A
– oil and gas production
|
|
9.45
|
|
7.39
|
9.45
|
23,356
|
|
17,974
|
|
23,397
|
|||||||||
G&A
|
|
3.78
|
|
3.87
|
|
3.90
|
9,333
|
|
9,419
|
|
9,651
|
||||||||
Interest
expense
|
|
1.75
|
1.11
|
|
2.01
|
4,326
|
|
2,707
|
|
4,976
|
|||||||||
Total
|
|
$
|
30.49
|
$
|
27.27
|
|
$
|
31.47
|
$
|
75,354
|
|
$
|
66,336
|
|
$
|
77,888
|
|
·
|
Operating
costs: Operating costs per BOE in the third quarter of 2007 were
8% higher
than the third quarter of 2006 primarily due to increases in contract
labor, well servicing, chemicals and compression and gathering costs,
partially offset by lower steam costs and used on-lease electricity
costs.
Operating costs per BOE were 5% lower in the third quarter of 2007
as
compared to the second quarter of 2007 due to lower steam costs and
used
on-lease electricity costs. The cost of our steam and
electricity used on-lease on our heavy oil properties in
California has decreased in the third quarter of 2007 due to lower
cost of
natural gas used as fuel, partially offset by a higher volume of
steam
injected. The following table presents steam
information:
|
September
30, 2007
(3Q07)
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06
Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
|
Average
volume of steam injected (Bbl/D)
|
88,711
|
86,556
|
2%
|
84,032
|
3%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
4.84
|
$
6.14
|
(21%)
|
$
6.46
|
(25%)
|
·
|
Production
taxes: Overall, our production taxes have decreased compared to 2006
due
to lower tax rates and lower assessed values for some of our oil
and
natural gas assets. Severance taxes, which are prevalent in Utah
and
Colorado, are directly related to the cost of the field sales price
of the
commodity. In California and Utah, our production is burdened with
ad
valorem taxes on proved reserves. Colorado has an ad valorem
tax which is based on field commodity prices. We expect
production taxes, in general, to correlate with the underlying commodity
price.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE were 28% higher in the three
months ended September 30, 2007 compared to the same period in the
prior
year due to an increase in capital spending over the last year and
particularly more extensive development in fields with higher drilling
costs and leasehold acquisition
costs.
|
·
|
General
and administrative: G&A per BOE decreased by 2% in the third quarter
of 2007 compared to the third quarter of 2006 due to higher production
in
2007. G&A per BOE was 3% lower in the third quarter of 2007 as
compared to the second quarter of 2007 due to lower compensation
related
costs and consulting expenses, partially offset by higher legal and
accounting expenses related to business development
activities.
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was approximately
$440 million at September 30, 2007 compared to approximately
$330 million and $475 million at September 30, 2006 and June 30,
2007, respectively. Our average borrowings increased since September
30,
2006 as a result of our capital expenditure program and due to payments
of
$153 million to purchase the North Parachute Ranch property located
in the
Piceance basin. Beginning in 2006, a certain portion of our interest
cost
related to our Piceance basin acquisition and joint venture has been
capitalized into the basis of the assets, and we anticipate a portion
will
continue to be capitalized until the remainder of our probable reserves
has been recategorized to proved developed reserves. For the quarter
ended
September 30, 2007, $4.8 million has been capitalized and we expect
to
capitalize approximately $18 million of interest cost during the
full year
of 2007.
|
|
|
Anticipated
range
|
|
Nine
months ended
|
|
Nine
months ended
|
||||
|
|
In
2007 per
BOE
|
|
September
30, 2007
|
September
30, 2006
|
|||||
Operating
costs-oil and gas production (1)
|
$
|
14.00
to 15.00
|
|
$
|
14.27
|
$
|
12.32
|
|||
Production
taxes
|
1.50
to 2.00
|
1.70
|
1.75
|
|||||||
DD&A
– oil and gas production
|
|
|
8.50
to 9.50
|
|
9.04
|
6.96
|
||||
G&A
|
|
|
3.75
to 4.25
|
|
4.05
|
3.77
|
||||
Interest
expense
|
|
|
1.50
to 2.00
|
|
1.88
|
.99
|
||||
Total
|
|
$
|
29.25
to 32.75
|
|
$
|
30.94
|
$
|
25.79
|
·
|
Operating
costs: Operating costs per BOE in the nine months ended September
30, 2007
were 16% higher than the comparable period in 2006 primarily due
to
approximately 15% greater steam levels in 2007 compared to 2006
levels.
|
·
|
Production
taxes: Overall, our production taxes have decreased slightly compared
to
2006 due to lower tax rates and lower assessed values for some of
our oil
and natural gas assets.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE were 30% higher in the nine
months ended September 30, 2007 compared to the same period in the
prior
year due to an increase in capital spending over the last year and
particularly more extensive development in fields with higher drilling
costs and leasehold acquisition
costs.
|
·
|
General
and administrative: G&A per BOE increased by 7% in the nine months
ended September 30, 2007 compared to the same period in the prior
year due
to additional staffing and higher overall compensation costs associated
with our growth activities.
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was approximately
$440 million at September 30, 2007 compared to approximately
$330 million at September 30, 2006, respectively. Our average
borrowings increased since September 30, 2006 primarily due to
acquisitions.
|
|
|
Anticipated
range
|
|
|
||||||
|
|
in
2008 per BOE
|
|
|||||||
Operating
costs-oil and gas production (1)
|
$
|
15.50
to 16.50
|
|
|||||||
Production
taxes
|
1.50
to 2.00
|
|||||||||
DD&A
|
|
|
9.00
to 10.00
|
|
||||||
G&A
|
|
|
3.75
to 4.25
|
|
||||||
Interest
expense
|
|
|
1.50
to 2.00
|
|
||||||
Total
|
|
$
|
31.25
to 34.75
|
|
Three
months ended September 30, 2007
|
Nine
months ended September 30, 2007
|
|||||||||
Gross Wells
|
Net
Wells
|
Gross
Wells
|
Net
Wells
|
|||||||
South
Midway-Sunset
|
22
|
22
|
46
|
46
|
||||||
North
Midway-Sunset (including diatomite)
|
5
|
|
5
|
16
|
16
|
|
||||
Socal
|
11
|
|
11
|
78
|
78
|
|
||||
Piceance
|
21
|
7
|
70
|
20
|
||||||
Uinta
|
8
|
|
8
|
36
|
34
|
|
||||
DJ
|
32
|
30
|
100
|
65
|
||||||
Totals
|
99
|
|
83
|
346
|
259
|
September
30, 2007
(3Q07)
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06
Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
|
Average
production (BOE/D)
|
26,873
|
26,423
|
2%
|
27,195
|
(1%)
|
Average
oil and gas sales prices, per BOE after hedging
|
$
47.93
|
$
47.28
|
1%
|
$
45.43
|
5%
|
Net
cash provided by operating activities
|
$
93
|
$
101
|
(8%)
|
$
80
|
16%
|
Working
capital
|
$
(91)
|
$
(175)
|
(48%)
|
$
(49)
|
86%
|
Sales
of oil and gas
|
$
119
|
$
116
|
3%
|
$
113
|
5%
|
Total
debt
|
$
440
|
$
330
|
32%
|
$
475
|
(8%)
|
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
$
63
|
$
148
|
(60%)
|
$
131
|
(55%)
|
Dividends
paid
|
$
3.4
|
$
4.2
|
(19%)
|
$
3.4
|
-%
|
Total
|
2007
|
2008
|
2009
|
2010
|
2011
|
Thereafter
|
|||||||||
Total
debt and interest
|
|
$
|
673.5
|
$
|
36.6
|
$
|
31.8
|
$
|
31.8
|
$
|
31.8
|
$
|
259.1
|
$
|
282.4
|
Abandonment
obligations
|
|
|
32.3
|
|
.7
|
|
.9
|
|
1.0
|
|
1.0
|
|
1.0
|
|
27.7
|
Operating
lease obligations
|
|
|
12.8
|
|
.4
|
|
1.7
|
|
1.4
|
|
1.4
|
|
1.4
|
|
6.5
|
Drilling
and rig obligations
|
|
|
89.9
|
|
9.6
|
|
30.6
|
|
42.8
|
|
6.9
|
|
-
|
|
-
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|||||||
transportation
contracts
|
|
|
70.2
|
|
1.2
|
|
7.6
|
|
8.5
|
|
8.7
|
|
8.7
|
|
35.5
|
Total
|
|
$
|
878.7
|
$
|
48.5
|
$
|
72.6
|
$
|
85.5
|
$
|
49.8
|
$
|
270.2
|
$
|
352.1
|
|
Item
3.
Quantitative
and Qualitative
Disclosures About Market
Risk
|
Average
|
Average
|
|||||||||
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Floor/Ceiling
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Prices
|
Crude
Oil Sales
(NYMEX
WTI)
|
|
|
|
|
|
Natural
Gas Sales
(NYMEX
HH)
|
|
|
|
|
Collars
|
|
Collars
|
||||||||
4th
Quarter
2007
|
1,000
|
$70.00
/ $75.85
|
|
4th
Quarter
2007
|
15,000
|
$8.00
/ $11.39
|
||||
4th
Quarter
2007
|
8,000
|
$47.50
/ $70.00
|
1st
Quarter
2008
|
16,000
|
$8.00
/ $15.65
|
|||||
Full
year 2008
|
10,000
|
$47.50
/ $70.00
|
2nd
Quarter
2008
|
17,000
|
$7.50
/ $8.40
|
|||||
Full
year 2008
|
1,000
|
$70.00
/ $76.70
|
|
3rd
Quarter
2008
|
19,000
|
$7.50
/ $8.50
|
||||
Full
year 2009
|
10,000
|
$47.50
/ $70.00
|
|
4th
Quarter
2008
|
21,000
|
$8.00
/ $9.50
|
||||
Full
year 2010
|
1,000
|
$60.00
/ $80.00
|
|
|||||||
Full
year 2010
|
1,000
|
$55.00
/ $76.20
|
|
|||||||
Full
year 2010
|
1,000
|
$55.00
/ $77.75
|
|
|||||||
Full
year 2010
|
1,000
|
$55.00
/ $77.70
|
|
|||||||
Full
year 2010
|
1,000
|
$55.00
/ $83.10
|
|
|||||||
Full
year 2010
|
1,000
|
$60.00
/ $75.00
|
||||||||
Full
year 2010
|
1,000
|
$65.15
/ $75.00
|
|
|
|
|
||||
Full
year 2010
|
1,000
|
$65.50
/ $78.50
|
||||||||
Natural
Gas Sales (NYMEX HH TO CIG)
|
||||||||||
Swaps
|
Price
|
|
Basis
Swaps
|
|
|
|
Price
|
|||
4th
Quarter
2007
|
1,000
|
$64.55
|
|
October
2007
|
15,000
|
$1.63
|
||||
4th
Quarter
2007
|
2,000
|
$60.00
|
November
& December 2007
|
15,000
|
$1.71
|
|||||
Full
year 2008
|
260
|
$74.00
|
1st
Quarter
2008
|
16,000
|
$1.74
|
|||||
Full
year 2009
|
240
|
$71.50
|
2nd
Quarter
2008
|
17,000
|
$1.43
|
|||||
3rd
Quarter
2008
|
19,000
|
$1.40
|
||||||||
4th
Quarter
2008
|
21,000
|
$1.46
|
Impact
of percent change in futures prices
|
||||||||||||||||
September
30, 2007
|
on
pretax future cash (payments) and receipts
|
|||||||||||||||
NYMEX
Futures
|
-20%
|
-10%
|
+
10%
|
+
20%
|
||||||||||||
Average
WTI Futures Price (2007 – 2010)
|
$
|
74.79
|
$
|
59.83
|
$
|
67.31
|
$
|
82.27
|
$
|
89.74
|
||||||
Average
HH Futures Price (2007 – 2008)
|
|
7.76
|
6.21
|
|
|
6.99
|
|
8.54
|
9.32
|
|||||||
Crude
Oil gain/(loss) (in millions)
|
|
$
|
(53.2
|
)
|
$
|
12.2
|
$
|
(4.3
|
)
|
$
|
(127.1
|
)
|
$
|
(214.7
|
)
|
|
Natural
Gas gain/(loss) (in millions)
|
4.4
|
15.4
|
9.2
|
3.3
|
(.5
|
)
|
||||||||||
Total
|
|