DELAWARE |
77-0079387 |
|||
(State
or other jurisdiction of |
(I.R.S.
Employer |
|||
incorporation
or organization) |
Identification
No.) |
5201
Truxtun Avenue, Suite 300, Bakersfield, California |
93309-0640 |
(Address
of principal executive offices) |
(Zip
Code) |
. | |
Page
No | |
PART
I. Financial Information |
|
Item
1. Financial Statements |
|
3 | |
4 | |
4 | |
5 | |
6 | |
9 | |
16 | |
Item
4. Controls and Procedures |
17 |
PART
II. Other Information |
|
Item
1. Legal Proceedings |
18 |
18 | |
Item
3. Defaults Upon Senior Securities |
18 |
18 | |
Item
5. Other Information |
18 |
Item
6. Exhibits |
18 |
18 |
March
31, |
December
31, |
||||||
2005 |
2004 |
||||||
(Unaudited) |
|||||||
ASSETS |
|||||||
Current
Assets: |
|||||||
Cash
and cash equivalents |
$ |
18,150 |
$ |
16,690 |
|||
Short-term
investments available for sale |
659
|
659
|
|||||
Accounts
receivable |
45,127
|
34,621
|
|||||
Deferred
income taxes |
13,999
|
3,558
|
|||||
Fair
value of derivatives |
4,281
|
3,243
|
|||||
Prepaid
expenses and other |
2,265
|
2,230
|
|||||
Total
current assets |
84,481
|
61,001
|
|||||
Oil
and gas properties (successful efforts basis), buildings and equipment,
net |
462,407
|
338,706
|
|||||
Deposit
on potential property acquisitions |
3,322
|
10,221
|
|||||
Other
assets |
2,587
|
2,176
|
|||||
$ |
552,797 |
$ |
412,104 |
||||
LIABILITIES
AND SHAREHOLDERS' EQUITY |
|||||||
Current
liabilities: |
|||||||
Accounts
payable |
$ |
30,992 |
$ |
27,750 |
|||
Revenue
and royalties payable |
10,374
|
23,945
|
|||||
Accrued
liabilities |
7,680
|
6,132
|
|||||
Income
taxes payable |
2,124
|
1,067
|
|||||
Fair
value of derivatives |
34,458
|
5,947
|
|||||
Total
current liabilities |
85,628
|
64,841
|
|||||
Long-term
liabilities: |
|||||||
Deferred
income taxes |
51,783
|
47,963
|
|||||
Long-term
debt |
138,000
|
28,000
|
|||||
Abandonment
obligations |
9,369
|
8,214
|
|||||
Fair
value of derivatives |
2,770
|
- |
|||||
201,922
|
84,177
|
||||||
Shareholders'
equity: |
|||||||
Preferred
stock, $.01 par value; 2,000,000 shares authorized; no shares
outstanding |
- |
- |
|||||
Capital
stock, $.01 par value; |
|||||||
Class
A Common Stock, 50,000,000 shares authorized; 21,164,726 shares issued and
outstanding (21,060,420 in 2004) |
212
|
210
|
|||||
Class B Stock, 1,500,000 shares authorized; 898,892 shares issued and
outstanding (liquidation preference of $899) |
9
|
9
|
|||||
Capital
in excess of par value |
61,051
|
60,676
|
|||||
Accumulated
other comprehensive loss |
(19,066 |
) |
(987 |
) | |||
Retained
earnings |
223,041
|
203,178
|
|||||
Total
shareholders' equity |
265,247
|
263,086
|
|||||
$ |
552,797 |
$ |
412,104 |
2005 |
2004 |
||||||
Revenues: |
|||||||
Sales
of oil and gas |
$ |
75,391 |
$ |
45,205 |
|||
Sales
of electricity |
12,456 |
11,934 |
|||||
Interest
and other income, net |
148 |
203 |
|||||
87,995 |
57,342 |
||||||
Expenses: |
|||||||
Operating
costs - oil and gas production |
23,407 |
16,782 |
|||||
Operating
costs - electricity generation |
13,358 |
12,403 |
|||||
Exploration
costs |
561 |
- |
|||||
Depreciation,
depletion and amortization - oil and gas production |
8,527 |
6,354 |
|||||
Depreciation,
depletion and amortization - electricity generation |
772 |
855 |
|||||
General
and administrative |
4,820 |
7,344 |
|||||
Dry
hole, abandonment and impairment |
2,021 |
- |
|||||
Interest |
1,162 |
531 |
|||||
54,628 |
44,269 |
||||||
Income
before income taxes |
33,367 |
13,073 |
|||||
Provision
for income taxes |
10,862 |
2,709 |
|||||
Net
income |
$ |
22,505 |
$ |
10,364 |
|||
Basic
net income per share |
$ |
1.02 |
$ |
.48 |
|||
Diluted
net income per share |
$ |
1.00 |
$ |
.47 |
|||
Cash
dividends per share |
$ |
.12 |
$ |
.11 |
|||
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share |
21,981 |
21,817 |
|||||
Effect
of dilutive securities: |
|||||||
Stock
options |
433 |
215 |
|||||
Other |
56 |
51 |
|||||
Weighted
average number of shares of capital stock used to calculate diluted net
income per share |
22,470 |
22,083 |
2005 |
2004 |
||||||
Net
income |
$ |
22,505 |
$ |
10,364 |
|||
Unrealized
gains (losses) on derivatives, (net of income taxes of $12,165and $1,135
in 2005 and 2004, respectively) |
(18,831 |
) |
(1,703 |
) | |||
Reclassification
of unrealized losses on derivatives included in net income (net of income
taxes of ($501) and ($1,378) in 2005 and 2004,
respectively) |
752
|
2,067
|
|||||
Comprehensive
income |
$ |
4,426 |
$ |
10,728 |
2005 |
2004 |
||||||
Cash
flows from operating activities: |
|||||||
Net
income |
$ |
22,505 |
$ |
10,364 |
|||
Depreciation,
depletion and amortization |
9,299
|
7,209
|
|||||
Abandonment
costs |
(213 |
) |
(105 |
) | |||
Deferred
income taxes, net |
5,042
|
2,270
|
|||||
Stock-based
compensation expense |
376
|
3,240
|
|||||
Other,
net |
89
|
147
|
|||||
Increase
in current assets other than cash, cash equivalents and short-term
investments |
(10,541 |
) |
(4,490 |
) | |||
Increase
(decrease) in current liabilities |
(7,305 |
) |
931
|
||||
Net
cash provided by operating activities |
19,252
|
19,566
|
|||||
Cash
flows from investing activities: |
|||||||
Capital
expenditures, excluding property acquisitions |
(15,681 |
) |
(18,440 |
) | |||
Property
acquisitions |
(109,469 |
) |
- |
||||
Net
cash used in investing activities |
(125,150 |
) |
(18,440 |
) | |||
Cash
flows from financing activities: |
|||||||
Proceeds
from issuance of long-term debt |
116,000
|
- |
|||||
Payment
of long-term debt |
(6,000 |
) |
- |
||||
Dividends
paid |
(2,642 |
) |
(2,401 |
) | |||
Net
cash provided by (used in) financing activities |
107,358
|
(2,401 |
) | ||||
Net
increase (decrease) in cash and cash equivalents |
1,460
|
(1,275 |
) | ||||
Cash
and cash equivalents at beginning of year |
16,690
|
10,658
|
|||||
Cash
and cash equivalents at end of period |
$ |
18,150 |
$ |
9,383 |
|||
Supplemental
non-cash activity: |
|||||||
Increase
(decrease) in fair value of derivatives: |
|||||||
Current
(net of income taxes of $10,756 and $151 in 2005 and 2004,
respectively) |
$ |
(16,717 |
) |
$ |
(227 |
) | |
Non-current
(net of income taxes of $908 and ($394) in 2005 and 2004,
respectively) |
(1,362 |
) |
591
|
||||
Net
(decrease) increase to accumulated other comprehensive
income |
$ |
(18,079 |
) |
$ |
364 |
2005 |
2004 |
||||||
Beginning
balance at January 1 |
$ |
8,214 |
$ |
7,311 |
|||
Liabilities
incurred |
1,153
|
-
|
|||||
Liabilities
settled |
(213 |
) |
(105 |
) | |||
Accretion
expense |
215
|
163
|
|||||
Ending
balance at March 31 |
$ |
9,369 |
$ |
7,369 |
2004 |
||||
Operating
costs - oil and gas |
||||
As
previously reported |
$ |
18,020 |
||
As
revised |
16,782
|
|||
Difference |
$ |
1,238 |
||
Operating
costs - electricity generation |
||||
As
previously reported |
$ |
11,934 |
||
As
revised |
12,403
|
|||
Difference |
$ |
(469 |
) | |
DD&A
- oil and gas |
||||
As
previously reported |
$ |
7,209 |
||
As
revised |
6,354
|
|||
Difference |
$ |
855 |
||
DD&A
- electricity generation |
||||
As
previously reported |
$ |
- |
||
As
revised |
855
|
|||
Difference |
$ |
(855 |
) | |
G&A
expenses as previously reported |
$ |
6,575 |
||
As
revised |
7,344
|
|||
Difference |
$ |
(769 |
) |
Three
Months Ended |
|||||||
March
31, |
|||||||
2005 |
2004 |
||||||
Pro
forma: |
(in
thousands, except per share data) |
||||||
Revenue |
$ |
89,358 |
$ |
61,903 |
|||
Income
from operations |
|
40,016 |
|
22,223 |
|||
Net
income |
|
22,809 |
|
10,980 |
|||
Basic
earnings per share |
|
1.04 |
|
0.50 |
|||
Diluted
earnings per share |
1.02
|
0.50
|
Mar
31
2005 |
% |
Dec
31
2004 |
% |
Mar
31
2004 |
% | ||||||||||||||
Oil
and Gas |
|||||||||||||||||||
Oil
Production (Bbl/D) |
19,156
|
87
|
19,896
|
93
|
18,392
|
95
|
|||||||||||||
Natural
Gas Production (Mcf/D) |
17,347
|
13
|
9,084
|
7
|
6,019
|
5
|
|||||||||||||
Total
(BOE/D) |
22,047
|
100
|
21,410
|
100
|
19,395
|
100
|
|||||||||||||
Per
BOE: |
|||||||||||||||||||
Average
sales price before hedging |
$ |
40.89 |
$ |
39.54 |
$ |
28.26 |
|||||||||||||
Average
sales price after hedging |
37.81
|
34.62
|
25.58
|
||||||||||||||||
Oil,
per Bbl: |
|||||||||||||||||||
Average
WTI price |
$ |
49.85 |
$ |
48.28 |
$ |
35.15 |
|||||||||||||
Less: |
|||||||||||||||||||
Price
sensitive royalties |
3.12
|
3.18
|
2.38
|
||||||||||||||||
Gravity
differential |
5.22
|
5.88
|
4.95
|
||||||||||||||||
Crude
oil hedges |
3.54
|
5.29
|
2.78
|
||||||||||||||||
Average
sales price |
$ |
37.97 |
$ |
33.93 |
$ |
25.04 |
|||||||||||||
Gas,
per Mmbtu: |
|||||||||||||||||||
Average
Henry Hub price |
$ |
6.27 |
$ |
7.15 |
$ |
5.71 |
|||||||||||||
Less: |
|||||||||||||||||||
Location
differentials |
0.79
|
1.56
|
0.89
|
||||||||||||||||
Average
sales price |
$ |
5.48 |
$ |
5.59 |
$ |
4.82 |
|||||||||||||
Electricity |
|||||||||||||||||||
Electric
power produced - MWh/D |
2,117
|
2,148
|
2,167
|
||||||||||||||||
Electric
power sold - MWh/D |
1,918
|
1,944
|
1,956
|
||||||||||||||||
Average
sales price/MWh |
$ |
68.87 |
$ |
70.20 |
$ |
67.05 |
|||||||||||||
Fuel
gas cost/MMBtu (excluding transportation) |
$ |
5.74 |
$ |
5.98 |
$ |
5.09 |
Bbl |
One
stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or condensate. |
BOE |
Barrel
of oil equivalent, measured as 6,000 cubic feet of natural gas equal to
one barrel of crude oil. |
Btu |
British
thermal unit, which is the heat required to raise the temperature of a
one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit. |
Mcf |
One
thousand cubic feet. |
MWh |
One
million watts (megawatt)/hour. |
/D |
per
day. |
Amount
Per BOE |
Amount
(in thousands) |
||||||||||||||||||
Mar
31,
2005 |
Mar
31,
2004 |
%
Change |
Mar
31,
2005 |
Mar
31,
2004 |
%
Change |
||||||||||||||
Operating
costs |
$ |
11.80 |
$ |
9.51 |
24 |
% |
$ |
23,407 |
$ |
16,782 |
39 |
% | |||||||
DD&A |
4.30 |
3.60 |
19 |
% |
8,527 |
6,354 |
34 |
% | |||||||||||
G&A |
2.43 |
4.16 |
(42 |
)% |
4,820 |
7,344 |
(34 |
)% | |||||||||||
Interest
expense |
.59 |
.30 |
97 |
% |
1,162 |
531 |
119 |
% |
· |
Operating
costs for the first quarter of 2005, on a per BOE basis, increased 24% to
$11.80 in the first quarter of 2005 from $9.51 in the first quarter of
2004. The cost of the Company’s steaming operations on its heavy oil
properties represents a significant portion of the Company’s operating
costs and will vary depending on the cost of natural gas used as fuel and
the volume of steam injected during the period. Steam costs were higher in
the first quarter of 2005 compared to the first quarter of 2004 because
the cost of natural gas increased 13% to $5.74 per MMBtu in the first
quarter of 2005 from $5.09 per MMBtu in the first quarter of 2004 and the
volume of steam injected increased 10% to 70,440 barrels per day in the
first quarter of 2005 from 64,060 barrels per day in the first quarter of
2004. Steam injection was higher as the Company commenced several new
pilot projects and steam drives on its heavy-oil properties with peak oil
response not expected for six to twelve months. Also contributing to the
increase were increased cost of well servicing and other activities on the
Company’s properties. |
· |
DD&A
increased 19% to $4.30 per BOE in the first quarter of 2005 from $3.60 per
BOE in the first quarter of 2004 due to higher acquisitions, increased
capital investment and finding and development costs. Competition for
drilling rigs has increased dramatically over the last year and, thus, rig
rates are continuing to increase which has contributed to higher
development costs. |
· |
G&A
expense decreased 42% to $2.43 per BOE in the first quarter of 2005 from
$4.16 per BOE in the first quarter of 2004. The 2004 expenses included
significant non-recurring non-cash stock-based compensation
charges. |
· |
Interest
expense in the first quarter of 2005 was $.59 per BOE, up from $.30 per
BOE in the first quarter of 2004. The Company’s borrowings at March 31,
2004 were $50 million. The Company’s borrowings were reduced during the
latter half of 2004 to a level of $28 million at year-end. Interest
expense was higher in the first quarter of 2005 compared to 2004 because
the Company’s borrowings increased to $138 million during the first
quarter of 2005 primarily due to the Niobrara and Tri-State acquisitions.
|
Amount
Per BOE |
Amount
(in thousands) |
||||||||||||||||||
Mar
31,
2005 |
Dec
31,
2004 |
%
Change |
Mar
31,
2005 |
Dec
31,
2004 |
%
Change |
||||||||||||||
Operating
costs |
$ |
11.80 |
$ |
11.09 |
6 |
% |
$ |
23,407 |
$ |
21,847 |
7 |
% | |||||||
DD&A |
4.30 |
4.19 |
3 |
% |
8,527 |
8,256 |
3 |
% | |||||||||||
G&A |
2.43 |
2.82 |
(14 |
)% |
4,820 |
5,548 |
(13 |
)% | |||||||||||
Interest
expense |
.59 |
.23 |
157 |
% |
1,162 |
455 |
155 |
% |
· |
Operating
costs for the first quarter of 2005 of $11.80 per BOE increased 6% from
$11.09 per BOE in the quarter ended December 31, 2004. This increase was
primarily related to a $2.1 million increase in severance taxes resulting
from higher tax credits received in the fourth quarter of 2004 related to
drilling operations at Brundage Canyon. Based on current crude oil and
natural gas prices, the Company anticipates operating costs to average
between $11.75 and $12.75 per BOE for all of
2005. |
· |
DD&A
in the first quarter of 2005 of $4.30 per BOE increased slightly from
$4.19 per BOE in the fourth quarter of 2004 due primarily to acquisitions,
increased capital investment and higher finding and development costs. The
Company anticipates DD&A to average between $4.25 and $4.75 per BOE
for all of 2005. |
· |
G&A
expenses of $2.43 per BOE in the first quarter of 2005 decreased 14% from
$2.82 incurred in the fourth quarter of 2004. The Company anticipates
G&A to average between $1.75 and $2.25 per BOE in the full year of
2005. The Company expects G&A to trend lower during the year, on a per
barrel basis, due to higher production levels anticipated upon completion
of the Company’s extensive development activities planned for
2005. |
· |
Interest
expense of $.59 per BOE in the first quarter of 2005 increased from $.23
per BOE in the fourth quarter of 2004. The Company’s borrowings totaled
$28 million at December 31, 2004 and increased to $138 million at March
31, 2005.
The Company anticipates interest expense to stay in the $.45 to $.60 per
BOE range for all of 2005. |
Less
than |
1-3
|
3-5 |
More
than |
|||||||||||||
Contractual
Obligations |
Total |
1
year |
years |
years |
5
years |
|||||||||||
Long-term
debt |
$ |
138,000 |
$ |
- |
$ |
138,000 |
$ |
- |
$ |
- |
||||||
Abandonment
obligations |
9,369
|
304
|
922
|
1,166
|
6,977
|
|||||||||||
Operating
lease obligations |
1,396
|
621
|
676
|
99
|
-
|
|||||||||||
Drilling
obligation |
10,525
|
925
|
4,250
|
5,350
|
-
|
|||||||||||
Firm
natural gas |
||||||||||||||||
transportation
contract |
22,745
|
2,814
|
5,628
|
5,628
|
8,675
|
|||||||||||
Total |
$ |
182,035 |
$ |
4,664 |
$ |
149,476 |
$ |
12,243 |
$ |
15,652 |
March
31,
2005
NYMEX
Futures |
Impact
of percent change in futures prices
on
earnings |
|||||||||||||||
20% |
10% |
+10% |
+20% |
|||||||||||||
Average
WTI Price |
$ |
56.00 |
$ |
44.80 |
$ |
50.40 |
$ |
61.60 |
$ |
67.20 |
||||||
Crude
Oil gain/(loss) (in thousands) |
(38,013 |
) |
(8,119 |
) |
(23,066 |
) |
(52,959 |
) |
(67,906 |
) | ||||||
Average
HH Price |
7.93 |
6.35 |
7.14 |
8.73 |
9.52 |
|||||||||||
Natural
Gas gain/(loss) (in thousands) |
5,931 |
,071 |
4,984 |
6,808 |
7,720
|
|||||||||||
Net
pre-tax future cash payments (in thousands) |
(32,082 |
) |
(4,048 |
) |
(18,082 |
) |
(46,151 |
) |
(60,186 |
) |
Based on the Company’s hedges in place (swaps) associated with its natural gas sales volumes, a $1 increase in natural gas prices per MMBtu would reduce revenues by $ 1.6 million since the hedges are out-of-the money at March 31, 2005. Similarly, based on the Company’s hedges in place associated with its natural gas purchased volumes used in its steaming operations, if natural gas prices increased $1per MMBtu, the Company would collect an additional $2.8 million from its counterparties which would be reflected as a reduction to operating costs - oil & gas.
During 2004 and through early 2005, the differential between California heavy crude oil and WTI widened and averaged approximately $14.50 for the first quarter of 2005. While the Company is confident that it will be able to secure a contract for its California heavy crude oil in future periods, it is unlikely that the Company will be able to obtain terms similar to the current contract pricing in the existing agreement which is based upon the higher of the average of the local field posted prices plus a fixed premium, or WTI minus a fixed differential approximating $6.00 per barrel. This contract expires on December 31, 2005. In the first quarter of 2005, the Company estimates that its revenues benefited from this contract by approximately $11 million, and at a current differential of approximately $14.00 per barrel, the Company estimates that its revenues in 2005 will benefit from the contract by approximately $45 million.
Exhibit
No. |
Description
of Exhibit |
31.1 |
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002. * |
31.2 |
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002. * |
32.1 |
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* |
32.2 |
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* |
Date:
May 3, 2005 |
/s/
Robert F. Heinemann |
Robert
F. Heinemann | |
President
and Chief Executive Officer |
Date:
May 3, 2005 |
/s/
Ralph J. Goehring |
Ralph
J. Goehring | |
Executive
Vice President and | |
Chief
Financial Officer |