BERRY PETROLEUM COMPANY FORM 10-Q FOR THE THIRD QUARTER ENDED 09-30-06
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
x
Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act
of 1934
For
the
quarterly period ended
September 30, 2006
oTransition
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
transition period from __to
___
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
|
DELAWARE
|
|
77-0079387
|
|
|
(State
of incorporation or organization)
|
|
(I.R.S.
Employer Identification Number)
|
|
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code: (661)
616-3900
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. YES
x
NO
o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filerx Accelerated
filero Non-accelerated
filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES
o
NO
x
As
of
October 23, 2006, the registrant had 42,038,426 shares of Class A Common Stock
($.01 par value) outstanding. The registrant also had 1,797,784 shares of Class
B Stock ($.01 par value) outstanding on October 23, 2006 all of which is held
by
an affiliate of the registrant.
BERRY
PETROLEUM COMPANY
THIRD
QUARTER 2006 FORM 10-Q
TABLE
OF CONTENTS
PART
I.
FINANCIAL
INFORMATION
|
|
Page
|
|
|
|
|
Item
1. Financial Statements
|
|
|
|
|
|
Unaudited
Condensed Balance Sheets at September 30, 2006 and December 31,
2005
|
3
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended
September
30, 2006 and 2005
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Three Month
Periods
Ended September 30, 2006 and 2005
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Nine Month Periods Ended September
30, 2006 and 2005
|
5
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Nine Month Periods
Ended September 30, 2006 and 2005
|
5
|
|
|
|
|
Unaudited
Condensed Statements of Cash Flows for the Nine Month Periods Ended
September 30, 2006 and 2005
|
6
|
|
|
|
|
Notes
to Unaudited Condensed Financial Statements
|
7
|
|
|
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
13
|
|
|
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
22
|
|
|
|
|
Item
4. Controls and Procedures
|
23
|
|
|
|
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
|
26
|
|
|
|
|
Item
3. Defaults Upon Senior Securities
|
26
|
|
|
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
26
|
|
|
|
|
Item
5. Other Information
|
26
|
|
|
|
|
Item
6. Exhibits
|
27
|
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
|
September
30, 2006
|
|
|
December
31, 2005
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
352
|
|
$
|
1,990
|
|
Short-term
investments available for sale
|
|
|
663
|
|
|
661
|
|
Accounts
receivable
|
|
|
66,963
|
|
|
59,672
|
|
Deferred
income taxes
|
|
|
525
|
|
|
4,547
|
|
Fair
value of derivatives
|
|
|
5,710
|
|
|
3,618
|
|
Income
taxes receivable
|
|
|
7,638
|
|
|
-
|
|
Prepaid
expenses and other
|
|
|
9,806
|
|
|
4,398
|
|
Total
current assets
|
|
|
91,657
|
|
|
74,886
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,033,222
|
|
|
552,984
|
|
Long-term
deferred income taxes
|
|
|
-
|
|
|
1,600
|
|
Fair
value of derivatives
|
|
|
2,782
|
|
|
-
|
|
Other
assets
|
|
|
12,615
|
|
|
5,581
|
|
|
|
$
|
1,140,276
|
|
$
|
635,051
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
73,540
|
|
$
|
57,783
|
|
Property
acquisition payable
|
|
|
102,000
|
|
|
-
|
|
Revenue
and royalties payable
|
|
|
39,505
|
|
|
34,920
|
|
Accrued
liabilities
|
|
|
17,895
|
|
|
8,805
|
|
Line
of credit
|
|
|
20,500
|
|
|
11,500
|
|
Income
taxes payable
|
|
|
-
|
|
|
1,237
|
|
Fair
value of derivatives
|
|
|
12,802
|
|
|
15,398
|
|
Deferred
income taxes
|
|
|
366
|
|
|
-
|
|
Total
current liabilities
|
|
|
266,608
|
|
|
129,643
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
91,915
|
|
|
55,804
|
|
Long-term
debt
|
|
|
309,000
|
|
|
75,000
|
|
Abandonment
obligation
|
|
|
25,897
|
|
|
10,675
|
|
Unearned
revenue
|
|
|
1,741
|
|
|
866
|
|
Fair
value of derivatives
|
|
|
41,837
|
|
|
28,853
|
|
|
|
|
470,390
|
|
|
171,198
|
|
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; 42,104,176 shares
issued
and outstanding (21,157,155 on a pre-split basis in 2005)
|
|
|
421
|
|
|
211
|
|
Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and
outstanding (liquidation preference of $1,798) (898,892 on a pre-split
basis in 2005)
|
|
|
18
|
|
|
9
|
|
Capital
in excess of par value
|
|
|
49,441
|
|
|
56,064
|
|
Accumulated
other comprehensive loss
|
|
|
(27,847
|
)
|
|
(24,380
|
)
|
Retained
earnings
|
|
|
381,245
|
|
|
302,306
|
|
Total
shareholders' equity
|
|
|
403,278
|
|
|
334,210
|
|
|
|
$
|
1,140,276
|
|
$
|
635,051
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Three
Month Periods Ended September 30, 2006 and 2005
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
Three
months ended September 30,
|
|
|
|
|
|
|
|
2006
|
|
|
2005
(1)
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas
|
|
|
|
|
$
|
116,168
|
|
$
|
96,439
|
|
Sales
of electricity
|
|
|
|
|
|
12,592
|
|
|
12,933
|
|
Interest
and other income, net
|
|
|
|
|
|
603
|
|
|
612
|
|
|
|
|
|
|
|
129,363
|
|
|
109,984
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
30,950
|
|
|
24,270
|
|
Operating
costs - electricity generation
|
|
|
|
|
|
11,198
|
|
|
12,316
|
|
Production
taxes
|
|
|
|
|
|
5,286
|
|
|
3,874
|
|
Exploration
costs
|
|
|
|
|
|
344
|
|
|
749
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
17,974
|
|
|
8,602
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
|
|
|
825
|
|
|
1,042
|
|
General
and administrative
|
|
|
|
|
|
9,419
|
|
|
5,965
|
|
Interest
|
|
|
|
|
|
2,707
|
|
|
1,598
|
|
Dry
hole, abandonment and impairment
|
|
|
|
|
|
183
|
|
|
2,803
|
|
|
|
|
|
|
|
78,886
|
|
|
61,219
|
|
Income
before income taxes
|
|
|
|
|
|
50,477
|
|
|
48,765
|
|
Provision
for income taxes
|
|
|
|
|
|
19,103
|
|
|
14,546
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
31,374
|
|
$
|
34,219
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
$
|
.71
|
|
$
|
.78
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
$
|
.70
|
|
$
|
.76
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
per share
|
|
|
|
|
$
|
.095
|
|
$
|
.115
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share)
|
|
|
|
|
|
43,907
|
|
|
44,136
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
654
|
|
|
804
|
|
Director
deferred compensation
|
|
|
|
|
|
104
|
|
|
118
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
|
|
|
44,665
|
|
|
45,058
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
Three
Month Periods Ended September 30, 2006 and
2005
|
(In
Thousands)
|
Net
income
|
|
|
|
|
$
|
31,374
|
|
$
|
34,219
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of $28,188 and
($11,090), respectively
|
|
|
|
|
|
42,282
|
|
|
(16,635
|
)
|
Reclassification
of realized losses included in net income net of income taxes of
($1,178)
and ($2,568), respectively
|
|
|
|
|
|
(1,767
|
)
|
|
(3,852
|
)
|
Comprehensive
income
|
|
|
|
|
$
|
71,889
|
|
$
|
13,732
|
|
The
accompanying notes are an integral part of these financial
statements.
(1)
The
2005 per share and share amounts have been restated to give retroactive effect
to the two-for-one stock split that became effective on May 17, 2006. See Note
2.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Nine
Month Periods Ended September 30, 2006 and 2005
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
Nine
months ended September 30,
|
|
|
|
|
|
|
|
2006
|
|
|
2005
(1)
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas
|
|
|
|
|
$
|
328,742
|
|
$
|
252,635
|
|
Sales
of electricity
|
|
|
|
|
|
39,476
|
|
|
36,903
|
|
Interest
and other income, net
|
|
|
|
|
|
1,898
|
|
|
1,130
|
|
|
|
|
|
|
|
370,116
|
|
|
290,668
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
83,763
|
|
|
69,356
|
|
Operating
costs - electricity generation
|
|
|
|
|
|
36,155
|
|
|
36,596
|
|
Production
taxes
|
|
|
|
|
|
11,891
|
|
|
8,569
|
|
Exploration
costs
|
|
|
|
|
|
4,105
|
|
|
1,535
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
47,333
|
|
|
26,417
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
|
|
|
2,526
|
|
|
2,826
|
|
General
and administrative
|
|
|
|
|
|
25,610
|
|
|
15,988
|
|
Interest
|
|
|
|
|
|
6,745
|
|
|
4,502
|
|
Commodity
derivatives
|
|
|
|
|
|
(736
|
)
|
|
-
|
|
Dry
hole, abandonment and impairment
|
|
|
|
|
|
6,965
|
|
|
5,425
|
|
|
|
|
|
|
|
224,357
|
|
|
171,214
|
|
Income
before income taxes
|
|
|
|
|
|
145,759
|
|
|
119,454
|
|
Provision
for income taxes
|
|
|
|
|
|
56,930
|
|
|
37,470
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
88,829
|
|
$
|
81,984
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
$
|
2.02
|
|
$
|
1.86
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
$
|
1.98
|
|
$
|
1.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
per share
|
|
|
|
|
$
|
.225
|
|
$
|
.235
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share)
|
|
|
|
|
|
43,982
|
|
|
44,078
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
792
|
|
|
786
|
|
Director
deferred compensation
|
|
|
|
|
|
101
|
|
|
114
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
|
|
|
44,875
|
|
|
44,978
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
Nine
Month Periods Ended September 30, 2006 and
2005
|
(In
Thousands)
|
Net
income
|
|
|
|
|
$
|
88,829
|
|
$
|
81,984
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of $1,223 and
($26,407), respectively
|
|
|
|
|
|
1,834
|
|
|
(39,611
|
)
|
Reclassification
of realized losses included in net income net of income taxes of
($3,534)
and ($811), respectively
|
|
|
|
|
|
(5,301
|
)
|
|
(1,216
|
)
|
Comprehensive
income
|
|
|
|
|
$
|
85,362
|
|
$
|
41,157
|
|
The
accompanying notes are an integral part of these financial
statements.
(1)
The
2005 per share and share amounts have been restated to give retroactive effect
to the two-for-one stock split that became effective on May 17, 2006. See Note
2.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Nine
Month Periods Ended September 30, 2006 and 2005
(In
Thousands)
|
|
|
|
|
|
Nine
months ended September 30,
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
88,829
|
|
$
|
81,984
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
49,858
|
|
|
29,243
|
|
Dry
hole, abandonment and impairment
|
|
|
|
|
|
7,864
|
|
|
2,298
|
|
Commodity
derivatives
|
|
|
|
|
|
(264
|
)
|
|
-
|
|
Stock-based
compensation expense
|
|
|
|
|
|
3,563
|
|
|
404
|
|
Deferred
income taxes, net
|
|
|
|
|
|
44,410
|
|
|
16,939
|
|
Other,
net
|
|
|
|
|
|
281
|
|
|
106
|
|
(Increase)
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
|
|
|
(17,996
|
)
|
|
(28,310
|
)
|
Increase
in current liabilities other than book overdraft, line of credit,
property
acquisition payable and fair value of derivatives
|
|
|
|
|
|
8,600
|
|
|
19,623
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
185,145
|
|
|
122,287
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Development
and exploration of oil and gas properties
|
|
|
|
|
|
(185,773
|
)
|
|
(83,848
|
)
|
Property
acquisitions
|
|
|
|
|
|
(215,726
|
)
|
|
(105,828
|
)
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
|
|
|
(18,302
|
)
|
|
(7,215
|
)
|
Net
cash used in investing activities
|
|
|
|
|
|
(419,801
|
)
|
|
(196,891
|
)
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of line of credit
|
|
|
|
|
|
241,750
|
|
|
-
|
|
Payment
of line of credit
|
|
|
|
|
|
(232,750
|
)
|
|
-
|
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
324,700
|
|
|
116,000
|
|
Payment
of long-term debt
|
|
|
|
|
|
(90,700
|
)
|
|
(44,000
|
)
|
Dividends
paid
|
|
|
|
|
|
(9,889
|
)
|
|
(10,362
|
)
|
Debt
issuance cost
|
|
|
|
|
|
(322
|
)
|
|
(809)
|
|
Increase
in book overdraft
|
|
|
|
|
|
10,196
|
|
|
7,718
|
|
Excess
tax benefit
|
|
|
|
|
|
3,240
|
|
|
-
|
|
Stock
option exercises
|
|
|
|
|
|
2,559
|
|
|
-
|
|
Repurchase
of shares of common stock
|
|
|
|
|
|
(15,766
|
)
|
|
(2,206
|
)
|
Net
cash provided by financing activities
|
|
|
|
|
|
233,018
|
|
|
66,341
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
|
|
|
(1,638
|
)
|
|
(8,263
|
)
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
1,990
|
|
|
16,690
|
|
Cash
and cash equivalents at end of period
|
|
|
|
|
$
|
352
|
|
$
|
8,427
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of ($1,491) and ($11,309),
respectively)
|
|
|
|
|
$
|
2,237
|
|
$
|
16,964
|
|
Non-current
(net of income taxes of $3,803 and ($15,909),
respectively)
|
|
|
|
|
|
(5,704
|
)
|
|
23,863
|
|
Net
(decrease) increase to accumulated other comprehensive
income
|
|
|
|
|
$
|
(3,467
|
)
|
$
|
40,827
|
|
Supplemental
non-cash financing activity:
|
|
|
|
|
|
|
|
|
|
|
Property
acquired under deferred payment schedule
|
|
|
|
|
$
|
102,000
|
|
$
|
-
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
1. General
All
adjustments which are, in the opinion of Management, necessary for a fair
statement of Berry Petroleum Company’s (the “Company”) financial position at
September 30, 2006 and December 31, 2005 and results of operations for the
three and nine month periods ended September 30, 2006 and 2005 and cash flows
for the nine month periods ended September 30, 2006 and 2005 have been included.
All such adjustments are of a normal recurring nature. The results of operations
and cash flows are not necessarily indicative of the results for a full
year.
The
accompanying unaudited condensed financial statements have been prepared on
a
basis consistent with the accounting principles and policies reflected in the
December 31, 2005 financial statements. The December 31, 2005 Form 10-K,
March 31, 2006 Form 10-Q and June 30, 2006 Form 10-Q should be read in
conjunction herewith. The year-end condensed balance sheet was derived from
audited financial statements, but does not include all disclosures required
by
accounting principles generally accepted in the United States of America. In
the
second quarter 2006, the Company dissolved its subsidiary, Piceance Operating
Company LLC.
The
Company’s cash management process provides for the daily funding of checks as
they are presented to the bank. Included in accounts payable at September 30,
2006 and September 30, 2005 is $12.1 million and $7.7 million, respectively,
representing outstanding checks in excess of the bank balance (book
overdraft).
2. Stock
Split
On
March
1, 2006, the Company’s Board of Directors approved a two-for-one stock split to
shareholders of record on May 17, 2006, subject to obtaining shareholder
approval of an increase in the Company’s authorized shares. On May 17, 2006 the
Company’s shareholders approved the authorized share increase and on June 2,
2006 each shareholder received one additional share for each share in the
shareholder's possession on May 17, 2006. This did not change the proportionate
interest a shareholder maintained in the Company on that date. All historical
shares, equity awards and per share amounts have been restated for the
two-for-one stock split.
3. Recent
Accounting Developments
In
September 2006, Statement of Financial Accounting Standards (SFAS) No. 157,
Fair
Value Measurements was
issued by the Financial Accounting Standards Board (FASB). This statement
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. SFAS No. 157 will become
effective for the Company’s fiscal year beginning after November 15, 2007,
and the Company is currently assessing the potential impact of this Statement
on
its financial statements.
In
September 2006, Staff Accounting Bulletin (“SAB”) No. 108,
Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements.
Registrants must quantify the impact on current period financial statements
of
correcting all misstatements, including both those occurring in the current
period and the effect of reversing those that have accumulated from prior
periods. This SAB will be applied beginning with the first fiscal year ending
after November 15, 2006. The adoption of SAB No. 108 should have
no effect to the financial position and result of operations of the Company.
In
June
2006, the FASB issued Interpretation (FIN) No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109.
FIN 48
prescribes a recognition threshold and measurement attribute for the financial
statement recognition and measurement of a tax position taken or expected to
be
taken in a tax return, and provides guidance on derecognition, classification,
interest and penalties, accounting in interim periods, disclosure, and
transition. This Interpretation is effective for fiscal years beginning after
December 15, 2006. The Company is currently assessing the potential impact
of this Interpretation on its financial statements.
In
February 2006, SFAS No. 155, Accounting
for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133
and 140 was
issued. This Statement resolves issues addressed in Statement 133 Implementation
Issue No. D1, Application
of Statement 133 to Beneficial Interests in Securitized Financial
Assets.
SFAS
No. 155 will become effective for the Company’s fiscal year beginning after
September 15, 2006 and while the Company anticipates no impact on its financial
statements based on its existing derivatives, the Company may experience a
financial impact depending on the nature and extent of any new derivative
instruments entered into after the effective date of SFAS No.
155.
4. Share-Based
Compensation
In
December 2004, SFAS No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. This standard requires an issuer
to measure the cost of employee services received in exchange for an award
of
equity instruments based on the grant-date fair value of the award. In April
2005, the SEC issued a rule that SFAS No. 123(R) would be effective for annual
reporting periods beginning on or after June 15, 2005. As a result, the Company
adopted this statement beginning January 1, 2006. The Company previously adopted
the fair value recognition provisions of SFAS No. 123, Accounting
for Stock-Based Compensation.
Accordingly, the adoption of SFAS No. 123(R) using the modified prospective
method, did not have a material impact on the Company’s condensed financial
statements for the three or nine months ended September 30, 2006.
Equity
Compensation Plans
The
2005
Equity Incentive Plan (the 2005 Plan), approved by the shareholders in May
2005,
provides for granting of equity compensation up to an aggregate of 2,900,000
shares of Common Stock. All equity grants are at market value on the date of
grant and at the discretion of the Compensation Committee or the Board of
Directors. The term of each employee grant did not exceed ten years from the
grant date and vesting has generally been at 25% per year for 4 years or 100%
after 3 years. The 2005 Plan also allows for grants to non-employee Directors.
During 2005, each of the non-employee Directors received 10,000 options at
the
market value on the date of grant. The options granted to the non-employee
Directors vest immediately. The Company generally uses a broker for issuing
new
shares upon option exercise.
Stock
Options
Effective
January 1, 2004, the Company voluntarily adopted the fair value method of
accounting for its stock option plans as prescribed by SFAS No. 123,
Accounting
for Stock-Based Compensation,
which
was the predecessor to SFAS No. 123(R).
The
modified prospective method was selected as described in SFAS No. 148,
Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, the Company recognized stock option compensation expense as if
it
had applied the fair value method to account for unvested stock options from
its
original effective date.
The
fair
value of each option award is estimated on the date of grant using the
Black-Scholes option pricing model that uses the assumptions noted in the
following table. Expected volatilities are based on the historical volatility
of
the Company's stock. The Company uses historical data to estimate option
exercises and employee terminations within the valuation model; separate groups
of employees that have similar historical exercise behavior are considered
separately for valuation purposes. The expected term of options granted is
based
on historical exercise behavior and represents the period of time that options
granted are expected to be outstanding; the range given below results from
certain groups of employees exhibiting different exercise behavior. The risk
free rate for periods within the contractual life of the option is based on
U.S.
Treasury rates in effect at the time of grant.
|
September
30, 2006
|
Expected
volatility
|
32%
- 33%
|
Weighted-average
volatility
|
32%
|
Expected
dividends
|
.9%
|
Expected
term (in years)
|
5.3
|
Risk-free
rate
|
4.7%
|
The
following is a summary of stock option activity for the nine months ended
September 30, 2006:
|
|
|
Options
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Life Remaining
|
|
Balance
outstanding, January 1
|
|
|
3,110,826
|
|
$
|
16.76
|
|
|
|
|
Granted
|
|
|
106,000
|
|
|
34.33
|
|
|
|
|
Exercised
|
|
|
(455,890
|
)
|
|
10.57
|
|
|
|
|
Canceled/expired
|
|
|
(307,750
|
)
|
|
18.64
|
|
|
|
|
Balance
outstanding, September 30
|
|
|
2,453,186
|
|
|
18.43
|
|
|
7.6
years
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at September 30
|
|
|
1,082,935
|
|
$
|
13.51
|
|
|
6.3
years
|
|
4. Share-Based
Compensation (Continued)
Restricted
Stock Units
Under
the
2005 Equity, the Company began a long-term incentive program whereby restricted
stock units (RSUs) are available for grant to certain employees. Granted RSUs
generally
vest at either 25% per year over 4 years or 100% after 3 years. At September
30,
2006, all RSUs are unvested and none are exercisable. Unearned compensation
under the restricted stock award plan is amortized over the vesting period.
The
Company pays cash compensation on the RSUs in an equivalent amount of actual
dividends paid on a per share basis of the Company’s outstanding common
stock.
The
following is a summary of RSU activity for the nine months ended September
30,
2006 as follows:
|
|
|
RSUs
|
|
|
Weighted
Average Intrinsic Value at Grant Date
|
|
|
Weighted
Average Contractual Life Remaining
|
|
Balance
outstanding, January 1
|
|
|
141,900
|
|
$
|
30.65
|
|
|
|
|
Granted
|
|
|
219,580
|
|
|
31.52
|
|
|
|
|
Converted
|
|
|
-
|
|
|
-
|
|
|
|
|
Canceled/expired
|
|
|
(20,800
|
)
|
|
30.65
|
|
|
|
|
Balance
outstanding, September 30
|
|
|
340,680
|
|
$
|
31.22
|
|
|
3.2
years
|
|
Other
share-based compensation data
|
|
Stock
Options
|
|
RSUs
|
|
|
Nine
months ended
|
|
Nine
months ended
|
|
|
September
30, 2006
|
|
September
30, 2005
|
|
September
30, 2006
|
|
September
30, 2005
|
Weighted-average
grant date fair value
|
|
$
11.96
|
|
$
6.12
|
|
$
31.52
|
|
$
-
|
Total
intrinsic value of options exercised (in millions)
|
|
10.3
|
|
11.9
|
|
-
|
|
-
|
Total
intrinsic value of options/RSUs outstanding (in millions)
|
|
54.4
|
|
51.2
|
|
9.6
|
|
-
|
Total
intrinsic value of options exercisable (in millions)
|
|
15.9
|
|
21.8
|
|
-
|
|
-
|
Total
compensation cost recognized into income (in millions)
|
|
2.0
|
|
1.7
|
|
1.3
|
|
-
|
The
total
compensation cost related to nonvested awards not yet recognized on September
30, 2006 is $14.9 million and the weighted average period over which this cost
is expected to be recognized is 3 years. The tax benefit realized from stock
options exercised during the three and nine months ended September 30, 2006
is
$.4 million and $3.7 million, respectively.
5. Derivatives
The
Company entered into derivative contracts (natural gas swaps and collar
contracts) on March 1, 2006 that did not qualify for hedge accounting under
SFAS
133 because the price index for the location in the derivative instrument did
not correlate closely with the item being hedged. These contracts were recorded
in the first quarter of 2006 at their fair value on the balance sheet and the
Company recognized an unrealized net loss of approximately $4.8 million on
the
income statement under the caption “Commodity derivatives.” The Company entered
into natural gas basis swaps on the same volumes and maturity dates as the
previous hedges in May, 2006 which allowed for these derivatives to be
designated as cash flow hedges going forward, causing an unrealized net gain
of
$5.6 million was recognized in the second quarter of 2006. The difference of
$.8
million was recorded in other comprehensive income at the date the hedges were
designated.
Additionally,
on June 8, 2006 and July 10, 2006 the Company entered into five year interest
rate swaps for a fixed rate of approximately 5.5% on $100 million of the
Company’s outstanding borrowings under its credit facility for five years. These
interest rate swaps have been designated as cash flow hedges.
The
related cash flow impact of all of the Company’s derivative activities are
reflected as cash flows from operating activities.
5. Derivatives
(Continued)
At
September 30, 2006, the Company’s net fair value of derivatives liability was
$46.1 million as compared to $112.7 million at June 30, 2006 and $87.3 million
at March 31, 2006. Based on NYMEX strip pricing as of September 30, 2006, the
Company expects to make hedge payments under the existing derivatives of
$3.5 million during the next twelve months. Accumulated other comprehensive
loss consisted of $27.8 million, net of tax, of unrealized losses from the
Company's crude oil and natural gas swaps and collars that qualified for hedge
accounting treatment at September 30, 2006. Deferred net losses recorded in
Accumulated other comprehensive loss at September 30, 2006 and subsequent
marked-to-market changes in the underlying hedging contracts are expected to
be
reclassified to earnings over the life of these contracts.
6. Revisions
to the Classification of Production Taxes
Certain
amounts in the condensed income statements for the three and nine months ended
September 30, 2005 have been reclassified to conform to the 2006 presentation.
In connection with the preparation of the 2005 financial statements, the Company
reclassified production taxes out of operating costs-oil and gas into a separate
line. This reclassification had no impact on net income or net cash provided
by
operating activities and did not effect previously reported total revenues,
total operating expenses, net income or net cash provided by operating
activities.
Accordingly,
the Company has revised prior classifications for the three and nine months
ended September 30, 2005 as follows (in thousands):
|
|
Three
months ended
|
|
|
Nine
months ended
|
|
|
|
September
30, 2005
|
|
|
September
30, 2005
|
|
Operating
costs - oil and gas
|
|
|
|
|
|
|
As
previously reported
|
$
|
28,144
|
|
$
|
77,925
|
|
As
revised
|
|
24,270
|
|
|
69,356
|
|
Difference
|
$
|
(3,874
|
)
|
$
|
(8,569
|
)
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
|
|
|
|
As
previously reported
|
$
|
-
|
|
$
|
-
|
|
As
revised
|
|
3,874
|
|
|
8,569
|
|
Difference
|
$
|
3,874
|
|
$
|
8,569
|
|
7. Dry
Hole, Abandonment and Impairment
The
amount reflected on the Company’s income statement under the dry hole,
abandonment and impairment line item consists primarily of $.2 million for
two
wells that were drilled on the Company’s Tri-State prospect that were determined
non-commercial in the third quarter of 2006. For the nine months ended September
30, 2006 the Company incurred $7 million in dry hole, abandonment and impairment
which primarily relates to two
Coyote Flats, Utah wells for $5.2 million and the
Company’s 25% share in an exploration well located in the Lake Canyon project
area of the Uinta basin drilled for approximately $1.6 million net to Berry’s
interest.
8. Income
Taxes
The
Company’s effective tax rate was 38% and 39% for the third quarter and the first
nine months of 2006 compared to 30% and 31% for the third quarter and first
nine
months of 2005. The effective tax rates were lower in 2005 due to the Company’s
investment in projects that qualified for enhanced oil recovery (EOR) tax
credits. The federal and state EOR tax credits are fully phased out in 2006
due
to the 2005 average U.S. wellhead crude oil price exceeding the allowable EOR
tax credit ceiling price of $44.48 per barrel. The Company’s combined federal
and state statutory tax rate is 40%.
9. Credit
Facility
In
April
2006, the Company completed a new unsecured five-year bank credit agreement
(the
Agreement) with a banking syndicate and extended the term by one year to July
2011. The Agreement is a revolving credit facility for up to $750 million and
replaces the previous $500 million facility. The current borrowing base was
established at $500 million, as compared to the previous $350 million. This
transaction was accounted for in accordance with Emerging Issues Task Force,
(EITF) 98-14, Debtor’s Accounting for Changes in Line-of-Credit or
Revolving-Debt Arrangements.
9. Credit
Facility (Continued)
The
total
outstanding debt under the credit facility’s borrowing base and line of credit
was $330 million at September 30, 2006, leaving $170 million in borrowing
capacity available. Interest on amounts borrowed is charged at LIBOR plus a
margin of 1.00% to 1.75% or the prime rate, with margins on the various rate
options based on the ratio of credit outstanding to the borrowing base. The
Company is required under the Agreement to pay a commitment fee of .25% to
.375%
on the unused portion of the credit facility.
The
weighted average interest rate on outstanding borrowings at September 30, 2006
was 6.5%. The Agreement contains restrictive covenants which, among other
things, require the Company to maintain a certain debt to EBITDA ratio and
a
minimum current ratio, as defined. The Company was in compliance with all
covenants as of September 30, 2006.
10.
Leases
Receivable
The
Company entered into two separate three year lease agreements on two company
owned drilling rigs. Each agreement has a three year purchase option in favor
of
the lessee. The agreements were signed in the third and second quarters of
2005
and 2006, respectively. The total net investment in these rigs is approximately
$8.9 million at September 30, 2006. Both agreements are accounted for as direct
financing leases as defined by SFAS No. 13,
Accounting for Leases.
Net
investment in both leases are included in the balance sheet as other assets
and
as of September 30, 2006 are as follows (in thousands):
Net
minimum lease payments receivable |
$
11,830 |
Unearned
income
|
(2,963)
|
Net
investment in direct financing lease
|
$
8,867
|
As
of
September 30, 2006, estimated future minimum lease payments, including the
purchase option, to be received are as follows (in thousands):
2006
|
|
$257
|
2007
|
|
1,276
|
2008
|
|
4,545
|
2009
|
|
5,752
|
Total
|
|
$11,830
|
11. Contingencies
The
Company has accrued environmental liabilities for all sites, including sites
in
which governmental agencies have designated the Company as a potentially
responsible party, where it is probable that a loss will be incurred and the
minimum cost or amount of loss can be reasonably estimated. However, because
of
the uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be higher than the liability
currently accrued. Amounts currently accrued are not significant to the
financial position of the Company and Management believes, based upon current
site assessments, that the ultimate resolution of these matters will not require
substantial additional accruals. The Company is involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of
its
business. In the opinion of Management, the resolution of these matters will
not
have a material effect on the Company’s financial position, results of
operations or liquidity.
12. Joint
Venture
On
June
7, 2006 the Company entered into an agreement with a party to jointly develop
the North Parachute Ranch property in the Grand Valley field of the Piceance
basin of western Colorado. The Company estimates it will pay up to $153 million
to fund the drilling of 90 natural gas wells on the joint venture partner’s
acreage. The maximum amount of cost charged to the Company will not exceed
$1.7
million per well. In exchange for the Company’s payments of up to $153 million,
the Company will earn a 5% working interest on each of the 90 well bores and
a
net working interest of 95% (79% net revenue interest) in 4,300 gross acres
located elsewhere on the property.
On
July
7, 2006, the Company paid $51 million, which was the first installment of the
total $153 million and thereby earned the assignment of the 4,300 gross acres.
On November 1, 2006, the Company paid the second installment of approximately
$50 million. The Company plans to pay the third installment on May 1, 2007.
Prior to 2010 the Company is required to drill 120 wells, bearing 95% of the
cost, on its 4,300 gross acres and if not met, then the Company is required
to
pay $.2 million for each well less than 120 drilled. Additionally, if the
Company has not drilled at least one well by mid-2011 in each 160 acre tract
within the 4,300 gross acres, then that specific undrilled 160 acre tract shall
be reassigned to the joint venture partner. At the date of the agreement there
were no operating activities from these gas assets.
13. Acquisition
On
February 28, 2006, the Company closed on an agreement with a private seller
to
acquire a 50% working interest in natural gas assets in the Piceance basin
of
western Colorado for approximately $159 million. The acquisition was funded
under the Company's existing credit facility. The Company purchased 100% of
Piceance Operating Company LLC (which owned a 50% working interest in the
acquired assets). The total purchase price was allocated as follows: $30 million
to proved reserves and $129 million to unproved properties. Allocation was
made
based on fair value. The operating activities of these oil and gas assets are
insignificant compared to Berry's historical operations and therefore are
omitted from disclosure. Piceance
Operating Company LLC was dissolved subsequent to the acquisition.
14. Subsequent
Event
On
October 24, 2006, the Company issued $200 million of 8.25% senior subordinated
notes due 2016 in a public offering. The deferred costs of approximately $5
million associated with the issuance of debt will be amortized over the ten
year
life of the bonds. The net proceeds from the offering were used to 1) repay
approximately $145 million of current borrowings under the bank credit facility,
which were $170 million as of October 24, 2006 after the application of
this payment and 2) approximately $50 million was used to finance the November
1, 2006 installment under the joint venture agreement to develop properties
in
the Piceance basin.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
General.
The
following discussion provides information on the results of operations for
each
of the three and nine month periods ended September 30, 2006 and 2005 and our
financial condition, liquidity and capital resources as of September 30, 2006.
The financial statements and the notes thereto contain detailed information
that
should be referred to in conjunction with this discussion.
The
profitability of our operations in any particular accounting period will be
directly related to the realized prices of oil, gas and electricity sold, the
type and volume of oil and gas produced and electricity generated and the
results of development, exploitation, acquisition, exploration and hedging
activities. The realized prices for natural gas and electricity will fluctuate
from one period to another due to regional market conditions and other factors,
while oil prices will be predominantly influenced by world supply and demand.
The aggregate amount of oil and gas produced may fluctuate based on the success
of development and exploitation of oil and gas reserves pursuant to current
reservoir management. The cost of natural gas used in our steaming operations
and electrical generation, production rates, labor, equipment costs, maintenance
expenses, and production taxes are expected to be the principal influences
on
operating costs. Accordingly, our results of operations may fluctuate from
period to period based on the foregoing principal factors, among
others.
Corporate
Strategy.
Our
objective is to increase the value of our business through consistent growth
in
our production and reserves, both through the drill-bit and acquisitions. We
strive to operate our properties in an efficient manner to maximize the cash
flow and earnings of our assets. The strategies to accomplish these goals
include:
|
·
|
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
|
Notable
Third Quarter Items.
|
·
|
Achieved
record production which averaged 26,423 BOE/D, up 12% from the third
quarter of 2005 and up 7% from the second quarter of
2006
|
|
·
|
Achieved
production of approximately 5,800 Mcf/D in the Piceance
basin
|
|
·
|
Drilled
four appraisal wells on our Lake Canyon acreage which are testing
at
commercial rates
|
|
·
|
Increased
our 2006 capital budget to $275 million to accelerate
growth
|
|
·
|
Increased
our regular quarterly dividend by 15% to $.075 per share ($.30 annually)
and paid a special dividend of $.02 per
share
|
|
·
|
Executed
new crude oil sales contracts for Brundage Canyon oil
production
|
|
·
|
Announced
our 2006 year-end reserve target of 146 million
BOE
|
|
·
|
Achieved
over $1 billion in total assets as reflected in the balance sheet
of the
Company
|
Notable
Items and Expectations for the Remainder of 2006.
|
·
|
Announced
full scale development of our California diatomite asset with a 100
well
drilling program scheduled for 2007
|
|
·
|
Begin
drilling in the Ashley Forest located in the southern portion of
our
Brundage Canyon property
|
|
·
|
Issued
$200 million of ten year 8.25% senior subordinated notes on October
24,
2006
|
|
·
|
Expect
to determine a capital budget for 2007 in the $250 million to $275
million
range
|
Overview
of the Third Quarter.
Our
third quarter was our strongest quarter of the year when viewed excluding the
impact of commodity derivatives in the prior quarters. We had a significant
increase in average daily production of approximately 7% over the second
quarter, which is a result of our drilling program and increased steam on
various California heavy oil properties. Our average realized prices were down
by 5% from the second quarter reflecting a weakening commodity price
environment.
View
to the Fourth Quarter.
Our 2006
drilling program continues to drive our production growth into the fourth
quarter. We are expecting our production in the fourth quarter to increase
to
average over 28,000 BOE/D. We expect minimal impacts from our hedging in the
fourth quarter, but do expect lower realized prices from our Uinta basin crude
oil sales as the differential continues to widen. Operationally, we are focused
on executing our drilling program on our assets in the Piceance basin and our
diatomite resource in California and preparing for a sizable capital program
in
2007.
Joint
Venture. See
Note
12 to the unaudited condensed financial statements.
Results
of Operations. The
following companywide results are in thousands (except per share data) for
the
three months ended:
|
|
September
30, 2006
|
|
September
30, 2005
|
Change
|
June
30, 2006
|
Change
|
Sales
of oil
|
|
$
|
97,918
|
|
$
|
81,791
|
20%
|
$
|
94,965
|
3%
|
Sales
of gas
|
|
|
18,250
|
|
|
14,648
|
25%
|
|
15,676
|
16%
|
Total
sales of oil and gas
|
|
$
|
116,168
|
|
$
|
96,439
|
20%
|
$
|
110,641
|
5%
|
Sales
of electricity
|
|
|
12,592
|
|
|
12,933
|
(3%)
|
|
11,715
|
7%
|
Interest
and other income, net
|
|
|
603
|
|
|
612
|
(1%)
|
|
803
|
(25%)
|
Total
revenues and other income
|
|
$
|
129,363
|
|
$
|
109,984
|
18%
|
$
|
123,159
|
5%
|
Net
income
|
|
$
|
31,374
|
|
$
|
34,219
|
(8%)
|
$
|
34,203
|
(8%)
|
Net
income per share (diluted)
|
|
$
|
.70
|
|
$
|
.76
|
(8%)
|
$
|
.76
|
(8%)
|
Our
revenues may vary significantly from period to period as a result of changes
in
commodity prices and/or production volumes. Improvements in production volume
are due to acquisitions and sizable capital investments.
Improvement in prices during 2006 compared to 2005 are due to a tighter supply
and demand balance and the nervousness of the market about possible supply
disruptions. Both oil and gas prices weakened during the third quarter of 2006
as compared to the second quarter of 2006.
Our
production for the quarter ended September 30, 2006 was 26,423 BOE/D, which
was
up 12% from the third quarter of 2005, and an increase of 7% from the second
quarter of 2006. Production averaged almost 16,200 BOE/D and 10,200 BOE/D from
California and the Rockies, respectively. Our production increased by almost
1,700 BOE/D in the third quarter over the second quarter of 2006 due primarily
to additional drilling and good response from our new steamfloods. Our
production for the nine months ended September 30, 2006 was 24,896 BOE/D, which
was up 9% from the same period last year. We are forecasting average production
of between 25,500 BOE/D and 25,800 BOE/D for 2006, with well timing and
completions being the largest varying factors.
In
the
third quarter of 2006, we incurred total combined charges of $.5 million for
two
dry holes on our Tri-State (DJ basin) acreage and in exploration costs which
consists of our geological and geophysical costs associated with our Tri-State
acreage. We project our total exploration expense for 2006 to be approximately
$5 million.
In
the
first quarter ended March 31, 2006, we took a charge for the change in fair
market value of our natural gas derivatives put in place to protect our Piceance
basin acquisition future cash flows. These gas derivatives did not qualify
for
hedge accounting under SFAS 133 because
the price index in the derivative instrument did not correlate closely with
the
item being hedged. The
pre-tax charge in the first quarter was $4.8 million which represented the
change in fair market value over the life of the contract, which resulted from
an increase in natural gas prices from the date of the derivative to March
31,
2006. On
May
31, 2006, the Company entered into basis swaps with natural gas volumes to
match
the volumes on the Company’s NYMEX Henry Hub collars that were placed on March
1, 2006 and designated these swaps and collars as cash flow hedges, causing
an
unrealized net gain of $5.6 million to be recognized in the second quarter
of
2006. The difference of $.8 million was recorded in other comprehensive income
at the date the hedges were designated. Subsequent to May 31, 2006 changes
in
the marked-to-market fair values are reflected in Other Comprehensive
Income.
Operating
data.
The
following table is for the three months ended:
|
|
|
September
30, 2006
|
%
|
|
September
30, 2005
|
%
|
|
June
30, 2006
|
%
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,076
|
61
|
|
16,701
|
71
|
|
15,532
|
63
|
Light
Oil Production (Bbl/D)
|
|
|
4,118
|
16
|
|
3,308
|
14
|
|
4,061
|
16
|
Total
Oil Production (Bbl/D)
|
|
|
20,194
|
76
|
|
20,009
|
85
|
|
19,593
|
79
|
Natural
Gas Production (Mcf/D)
|
|
|
37,374
|
24
|
|
21,829
|
15
|
|
31,047
|
21
|
Total
(BOE/D)
|
|
|
26,423
|
100
|
|
23,647
|
100
|
|
24,768
|
100
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
50.33
|
|
$
|
51.34
|
|
$
|
52.46
|
|
Average
sales price after hedging
|
|
|
47.28
|
|
|
44.25
|
|
|
49.75
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
70.54
|
|
$
|
63.31
|
|
$
|
70.72
|
|
Price
sensitive royalties
|
|
|
(5.21)
|
|
|
(5.68)
|
|
|
(5.66)
|
|
Quality
differential
|
|
|
(8.76)
|
|
|
(4.94)
|
|
|
(8.49)
|
|
Crude
oil hedges
|
|
|
(3.99)
|
|
|
(8.35)
|
|
|
(3.38)
|
|
Average
oil sales price after hedging
|
|
$
|
52.58
|
|
$
|
44.34
|
|
$
|
53.19
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas,
per MMBtu:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price
|
|
$
|
6.18
|
|
$
|
6.97
|
|
$
|
6.65
|
|
Natural
gas hedges
|
|
|
(.02)
|
|
|
.02
|
|
|
-
|
|
Location
and quality differentials
|
|
|
(1.32)
|
|
|
(.85)
|
|
|
(1.06)
|
|
Average
gas sales price after hedging
|
|
$
|
4.84
|
|
$
|
6.14
|
|
$
|
5.59
|
|
The
following table is for the nine months ended:
|
|
|
September
30, 2006
|
%
|
|
September
30, 2005
|
%
|
|
|
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
15,681
|
63
|
|
16,086
|
71
|
|
|
|
Light
Oil Production (Bbl/D)
|
|
|
3,823
|
15
|
|
3,301
|
14
|
|
|
|
Total
Oil Production (Bbl/D)
|
|
|
19,504
|
78
|
|
19,387
|
85
|
|
|
|
Natural
Gas Production (Mcf/D)
|
|
|
32,348
|
22
|
|
20,438
|
15
|
|
|
|
Total
(BOE/D)
|
|
|
24,896
|
100
|
|
22,793
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
50.81
|
|
$
|
45.38
|
|
|
|
|
Average
sales price after hedging
|
|
|
48.33
|
|
|
40.48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
68.26
|
|
$
|
55.61
|
|
|
|
|
Price
sensitive royalties
|
|
|
(5.41)
|
|
|
(4.22)
|
|
|
|
|
Quality
differential
|
|
|
(7.87)
|
|
|
(5.18)
|
|
|
|
|
Crude
oil hedges
|
|
|
(3.17)
|
|
|
(5.78)
|
|
|
|
|
Average
oil sales price after hedging
|
|
$
|
51.81
|
|
$
|
40.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas,
per MMBtu:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price
|
|
$
|
6.91
|
|
$
|
6.62
|
|
|
|
|
Natural
gas hedges
|
|
|
-
|
|
|
(.02)
|
|
|
|
|
Location
and quality differentials
|
|
|
(1.30)
|
|
|
(.78)
|
|
|
|
|
Average
gas sales price after hedging
|
|
$
|
5.61
|
|
$
|
5.82
|
|
|
|
|
|
Oil
Contracts. On
November 21, 2005, we entered into a new crude oil sales contract
for our
California production for deliveries beginning February 1, 2006 and
ending
January 31, 2010. The per barrel price, calculated on a monthly basis
and
blended across the various producing locations, is the higher of
1) the
WTI NYMEX crude oil price less a fixed differential approximating
$8.15,
or 2) heavy oil field postings plus a premium of approximately
$1.35.
Our
weighted average realized sales price for our Utah crude oil as of
October
1, 2006 under our contracts is approximately $14.50 per barrel below
WTI,
with certain volumes tied to field posting. In some cases, our realized
price is further reduced by transportation charges. From October
1, 2003
through April 30, 2006, we sold our Utah crude oil at approximately
$2 per
barrel below WTI; and from May 1, 2006 through September 30, 2006,
we sold
the majority of our Utah crude oil at approximately $9 per barrel
below
WTI. Due to this lower pricing and based on sales of 4,600 Bbl/D
gross, we
estimate our revenues will be lower by approximately $4 million in
the
fourth quarter of 2006, as compared to the third quarter of 2006.
If this
pricing continues throughout 2007 and on the same volumes, we estimate
our
2007 revenues will be lower by approximately $15 million versus our
expected 2006 revenues. Field postings are currently at approximately
$12
to $13 below WTI. We are working on a longer term sales contract
for our
crude oil, which has a high paraffinic content, and may adjust our
future
capital expenditures in the Uinta basin due to the actual or expected
change in our realized price.
|
Hedging.
See
Note
5 to the unaudited condensed financial statements and Item 3. Quantitative
and
Qualitative Disclosures about Market Risk.
Electricity. We
consume natural gas as fuel to operate our three cogeneration facilities which
are intended to provide an efficient and secure long-term supply of steam
necessary for the economic production of heavy oil. Revenue and operating costs
in the three months ended September 30, 2006 were down from the three months
ended September 30, 2005 due to 6% lower electricity prices and 21% lower
natural gas prices, respectively. Conversely, revenue and operating costs in
the
three months ended September 30, 2006 were up from the three months ended June
30, 2006 due to 17% higher electricity prices and 3% higher natural gas prices,
respectively. The following table is for the three months ended:
|
|
|
September
30, 2006
|
|
|
September
30, 2005
|
|
|
June
30, 2006
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
12.6
|
|
$
|
12.9
|
|
$
|
11.7
|
|
Operating
costs (in millions)
|
|
$
|
11.2
|
|
$
|
12.3
|
|
$
|
10.6
|
|
Electric
power produced - MWh/D
|
|
|
2,100
|
|
|
2,025
|
|
|
2,023
|
|
Electric
power sold - MWh/D
|
|
|
1,895
|
|
|
1,830
|
|
|
1,827
|
|
Average
sales price/MWh
|
|
$
|
79.42
|
|
$
|
84.89
|
|
$
|
67.88
|
|
Fuel
gas cost/MMBtu (excluding transportation)
|
|
$
|
5.69
|
|
$
|
7.16
|
|
$
|
5.55
|
|
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
The
following table presents information about our operating expenses for each
of
the three month periods ended:
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
|
|
September
30, 2006
|
|
September
30, 2005
|
|
June
30, 2006
|
|
September
30, 2006
|
|
September
30, 2005
|
|
June
30, 2006
|
|
Operating
costs - oil and gas production
|
|
$
|
12.73
|
|
$
|
11.16
|
|
$
|
12.01
|
|
$
|
30,950
|
|
$
|
24,270
|
|
$
|
27,074
|
|
Production
taxes
|
|
|
2.17
|
|
|
1.78
|
|
|
1.50
|
|
|
5,286
|
|
|
3,874
|
|
|
3,373
|
|
DD&A
- oil and gas production
|
|
|
7.39
|
|
|
3.95
|
|
|
7.22
|
|
|
17,974
|
|
|
8,602
|
|
|
16,263
|
|
G&A
|
|
|
3.87
|
|
|
2.74
|
|
|
3.49
|
|
|
9,419
|
|
|
5,965
|
|
|
7,877
|
|
Interest
expense
|
|
|
1.11
|
|
|
.73
|
|
|
1.09
|
|
|
2,707
|
|
|
1,598
|
|
|
2,460
|
|
Total
|
|
$
|
27.27
|
|
$
|
20.36
|
|
$
|
25.31
|
|
$
|
66,336
|
|
$
|
44,309
|
|
$
|
57,047
|
|
Our
total
operating costs, production taxes, G&A and interest expenses for the three
months ended September 30, 2006, stated on a unit-of-production basis, increased
34% over the three months ended September 30, 2005 and increased 8% over the
three months ended June 30, 2006. The changes were primarily related to the
following items:
|
·
|
Operating
costs: Operating costs per BOE in the third quarter of 2006 were
14%
higher than the third quarter of 2005 due to the net effect of a
higher
volume of steam used offset by lower costs to produce steam. During
the
third quarter of 2006 we installed additional steam generators in
California related to various thermally enhanced oil projects. As
a result
of the increased steam injection, our crude oil production on these
properties has continued to increase. Similarly, operating costs per
BOE were 6% higher in the third quarter of 2006 as compared to the
second
quarter of 2006, primarily due to the 11% increase in average volume
of
steam injected in that time period. The cost of our steaming operations
on
our heavy oil properties in California vary depending on the cost
of
natural gas used as fuel and the volume of steam injected. The following
table presents steam information:
|
|
September
30, 2006
|
September
30, 2005
|
Change
|
June
30, 2006
|
Change
|
Average
volume of steam injected (Bbl/D)
|
86,556
|
68,299
|
27%
|
78,322
|
11%
|
Fuel
gas cost/MMBtu
|
$5.69
|
$7.16
|
(21%)
|
$5.55
|
3%
|
As
we
remain in a strong commodity price environment, we anticipate that cost
pressures within our industry may continue due to greater field activity and
rising service costs in general. Natural gas prices impact our cost structure
in
California by approximately $1.60 per California BOE for each $1.00 change
in
natural gas price.
|
·
|
Production
taxes: Our production taxes have increased over the last year as
the value
of our oil and natural gas has increased. Severance taxes, which
are
prevalent in Utah and Colorado, are directly related to the cost
of the
field sales price of the commodity and in California, our production
is
burdened with ad valorem taxes on our total proved reserves. In the
third
quarter of 2006, our production taxes were higher by 22% over the
third
quarter of 2005 and 45% higher than the second quarter of 2006. This
is
primarily due to significantly increased California and Colorado
production taxes from higher assessed values on our properties, increased
production and higher investment in mineral interests. We expect
production taxes to track the commodity price generally. California
Proposition 87, “The Clean Energy Initiative” was not passed by California
voters on November 7, 2006 and thus, no new production taxes are
expected.
|
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE in the three months
ended September 30, 2006 due to several sizable acquisitions, more
extensive development in higher cost fields and cost pressures in
our
labor and capital investments. As these costs increase, our DD&A rates
per BOE will also increase.
|
|
·
|
General
and administrative: Approximately two-thirds of our G&A is
compensation or compensation related costs. To remain competitive
in
workforce compensation and attract the talent needed to achieve our
growth
goals, the Company’s compensation costs increased in 2006. G&A
increased per BOE in the three months ended September 30, 2006 compared
to
the three months ended June 30, 2006 due to increased compensation
costs
and increased contributions in the third quarter to fund the opposition
of
Proposition 87 in California.
|
|
·
|
Interest
expense: Our outstanding borrowings, including our line of credit,
were
$330 million at September 30, 2006 and $273 million at June 30, 2006.
Average borrowings in 2006 increased as a result of our Piceance
basin
acquisitions during 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 during 2006 and 2007 until our probable reserves have
been
recategorized to proved reserves. As of September 30, 2006, $5.6
million
had been capitalized and we expect to capitalize between $8 million
and
$10 million of interest cost during the full year of 2006.
|
Estimated
2006 and Actual Nine Months Ended September 30, 2006 Oil and Gas Operating,
G&A and Interest Expenses.
|
|
Anticipated
range
|
|
Nine
months ended
|
|
|
|
|
|
in
2006 per BOE
|
|
September
30, 2006
|
|
|
|
Operating
costs-oil and gas production
|
|
$
|
11.75
to 13.25
|
|
$
|
12.32
|
|
|
|
|
Production
taxes
|
|
|
1.65
to 1.85
|
|
|
1.75
|
|
|
|
|
DD&A
|
|
|
6.50
to 7.50
|
|
|
6.96
|
|
|
|
|
G&A
|
|
|
3.60
to 3.80
|
|
|
3.77
|
|
|
|
|
Interest
expense
|
|
|
.90
to 1.30
|
|
|
.99
|
|
|
|
|
Total
|
|
$
|
24.40
to 27.70
|
|
$
|
25.79
|
|
|
|
|
Estimated
2007 Capital Budget, Production Volume, and Oil and Gas Operating, G&A and
Interest Expenses.
We
are in
the process of determining our 2007 capital budget. Our capital expenditures
should be close to our internally generated cash flow for the year targeting
approximately $250 million to $275 million. Our cash flow is primarily
determined by our realized commodity sales prices, and production volume. With
the implementation of this capital budget, we estimate double digit growth
in
our production volume in 2007 which targets a minimum of 28,000 BOE/D. Based
on
WTI of $60 and NYMEX Henry Hub (HH) of $7.50 MMBtu, we expect our expenses
to be
within the following ranges:
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2007 per BOE
|
|
|
|
|
|
Operating
costs-oil and gas production
|
|
$
|
14.00
to 15.00 |
|
|
|
|
|
|
|
Production
taxes
|
|
|
1.75
to 2.25 |
|
|
|
|
|
|
|
DD&A
|
|
|
7.50
to 8.50
|
|
|
|
|
|
|
|
G&A
|
|
|
3.25
to 3.75
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
1.00
to 2.00
|
|
|
|
|
|
|
|
Total
|
|
$
|
27.50
to 31.50 |
|
|
|
|
|
|
|
Income
Taxes.
See Note
8 to the unaudited condensed financial statements. Our effective tax rate will
be higher in 2006 as compared to 2005 due to the phase-out of the EOR tax credit
in 2006. We experienced an effective tax rate in the third quarter of 38% and
39% for the nine months ended September 30, 2006, which is in line with our
projections. We expect our effective tax rate for all of 2006 will be
approximately 39%.
Development,
Exploitation and Exploration Activity.
We
drilled 155 gross (127 net) wells during the third quarter of 2006, realizing
a
gross success rate of 99 percent. Excluding any future acquisitions, our
approved 2006 capital budget is $275 million. As of September 30, 2006, we
have
nine rigs drilling on our properties under long term contracts, one of which
we
own. We have several more rigs scheduled to begin in late 2006/early 2007,
including one other rig we own, which is being refurbished.
Piceance
Basin
In
the
third quarter of 2006, we drilled or started six additional wells, four on
the
Garden Gulch property and two on the North Parachute Ranch property. A total
of
16 wells were drilled in the first nine months of 2006. We have contracts for
five rigs as of September 30, 2006. The Garden Gulch acreage now has 20 wells
producing and we anticipate production from the North Parachute Ranch property
late in the fourth quarter. Average net production in the third quarter 2006
was
approximately 5,800 Mcf/D, up from 3,400 Mcf/D in the second quarter of
2006.
Uinta
Basin
Brundage
Canyon: In the third quarter we drilled 25 wells with 100% success rate. For
the
third quarter, daily net production averaged approximately 6,400 BOE/D. We
are
proceeding to drill our next Ashley Forest well in the fourth quarter of 2006.
Lake
Canyon: In
the
third quarter we drilled four shallow Green River wells that are all productive.
Initial gross production from these four wells averaged 140 BOE/D each which
is
consistent with the results of our Brundage Canyon wells. We are in the
permitting process for an additional 32 wells which are intended to continue
exploratory and development drilling on the eastern portion of our Lake Canyon
acreage. The timing to begin the drilling of these wells is the second quarter
2007. Based on the success of their first Wasatch well, our industry partner
is
planning to drill two additional Wasatch wells in the fourth quarter of 2006.
Coyote
Flats:
We have
three successful appraisal Ferron gas wells on the east side of the Scofield
reservoir which have each tested flow rates exceeding 900 Mcf/D. We have
renegotiated the farm out obligation terms with our industry partner to earn
a
50% interest in the project without drilling the remaining Emery coalbed methane
wells. Berry's earning obligation will be satisfied by installing a
gathering system, compression and 13 mile gas pipeline to connect the three
previously announced Ferron gas discoveries to sales
pipelines. Construction is underway and first sales are anticipated by the
end of 2006.
Denver-Julesburg
Basin
In
our
Tri-State area, we drilled 69 wells in the third quarter of 2006. Our net
production averaged 16.2 MMcf/D. In the third quarter, Berry installed
additional compression, gas gathering pipelines and high pressure pipelines
that
expand the capacity and connections to new markets on the Cheyenne Plains
Lateral system. In our Kansas Tri-State prospect we have drilled and completed
a
successful exploratory well that is an extension to our Prairie Star production
in Cheyenne County, Kansas and have drilled two dry holes in the third quarter.
We continue to permit new locations in Kansas and plan to drill several new
locations in the fourth quarter of 2006.
San
Joaquin Valley Basin
Midway-Sunset:
Production, excluding diatomite, increased 300 Bbl/D to 11,700
Bbl/D in the third quarter versus the second
quarter. Production increased as a result of accelerating the
development of our Ethel D and Pan properties and from returning a number
of horizontal wells to production after an aggressive cyclic steam program
during the first half of 2006. During the first three quarters of 2006, we
drilled infill producers and added steam generation capacity. We plan to
drill an additional 10 to 15 infill producers on these properties during the
fourth quarter of 2006.
Poso
Creek: Production from our Poso Creek property continues to increase as a
result of thermal redevelopment. Production has increased steadily
throughout the year from approximately 500 Bbl/D to over 1,200 Bbl/D
currently. Additional steam generation capacity was added during the third
quarter and we plan to drill 20 infill producers during the fourth quarter
of
2006.
Diatomite:
On November 1, 2006, we announced our plans to commence
development of our Midway-Sunset diatomite oil project in California based
on
the performance of a two-year pilot program. We believe the project will be
a
significant asset for our California operations and for Berry. The project
will
add material production and reserves to the Company as a part of our growth
strategy. Over the next four years, we will invest an additional $210 million
in
capital to drill 520 shallow development wells in the fairway of the asset
and
add steam generation and processing facilities. We expect this development
will
increase production to 7,000 Bbl/D by 2010. As we develop the fairway, we will
also appraise the potential of recovering additional reserves in the outer
portions of our acreage in subsequent development phases.
We
began
our diatomite pilot with 13 wells in 2004 and have expanded the project. Current
production is over 500 Bbl/D and the steam to oil ratio in the core of our
pilot
area has declined to six-to-one. Achieving this level of performance has been
key to moving ahead with a development plan. We believe that the fairway
contains 55% of the oil resource and has reservoir properties similar to the
pilot. This will enable a repeatable development like those used in our other
California assets. We will expand the project in 2007 and will spend about
$50
million of capital for 100 wells and associated facilities targeting an average
daily production of 1,000 Bbl/D for the year.
Drilling
Activity. The
following table sets forth certain information regarding drilling activities
for
the three and nine months ended September 30, 2006:
|
|
|
Three
months ended September 30, 2006
|
|
Nine
months ended September 30, 2006
|
|
|
|
|
Gross
Wells
|
|
|
Net
Wells
|
|
|
Net
Workovers
|
|
Gross
Wells
|
|
|
Net
Wells
|
|
|
Net
Workovers
|
|
Midway-Sunset
(1)
|
|
|
40
|
|
|
39.6
|
|
|
2.0
|
|
84
|
|
|
83.1
|
|
|
16.9
|
|
Poso
Creek
|
|
|
4
|
|
|
4.0
|
|
|
6.0
|
|
22
|
|
|
22.0
|
|
|
8.0
|
|
Placerita
|
|
|
7
|
|
|
7.0
|
|
|
-
|
|
7
|
|
|
7.0
|
|
|
6.0
|
|
Brundage
Canyon
|
|
|
25
|
|
|
25.0
|
|
|
-
|
|
82
|
|
|
82.0
|
|
|
14.0
|
|
Lake
Canyon
|
|
|
4
|
|
|
2.0
|
|
|
-
|
|
5
|
|
|
2.3
|
|
|
1.0
|
|
Coyote
Flats (2)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
2
|
|
|
2.0
|
|
|
.5
|
|
Tri-State
(3)
|
|
|
69
|
|
|
46.2
|
|
|
35.0
|
|
184
|
|
|
83.0
|
|
|
62.7
|
|
Piceance
|
|
|
6
|
|
|
3.0
|
|
|
-
|
|
16
|
|
|
8.0
|
|
|
-
|
|
Bakken
(4)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
4
|
|
|
.3
|
|
|
-
|
|
Totals
|
|
|
155
|
|
|
126.8
|
|
|
43.0
|
|
406
|
|
|
289.7
|
|
|
109.1
|
|
|
(1)
|
Includes
1 gross well (1 net well) that was a dry hole in the second quarter
of
2006.
|
|
(2)
|
Includes
2 gross wells that were dry holes in first quarter 2006. Acreage
ownership
is earned upon fulfilling certain
obligations.
|
|
(3)
|
Includes
1 gross well (.3 net well) that was a dry hole in the first quarter
2006
and 2 gross wells (1.3 net wells) that were dry holes in the third
quarter
of 2006.
|
|
(4)
|
Includes
1 gross well (.06 net well) that was a dry hole in the first quarter
2006.
|
Rocky
Mountain and Mid-Continent Region Drilling Rigs.
During
2005 and 2006, we purchased three drilling rigs. These rigs are leased to a
drilling company under three year contracts and carry purchase options available
to the drilling company, two of which are accounted for as lease receivables
in
Note 10. Owning these rigs allows us to successfully meet a portion of our
drilling needs in both the Uinta and Piceance basins over the next several
years. We have several more rigs we do not own contracted to begin drilling
in
late 2006/early 2007.
Financial
Condition, Liquidity and Capital Resources. Substantial
capital is required to replace and grow reserves. We achieve reserve replacement
and growth primarily through successful development and exploration drilling
and
the acquisition of properties. Fluctuations in commodity prices have been the
primary reason for short-term changes in our cash flow from operating
activities. The net long-term growth in our cash flow from operating activities
is the result of growth in production as affected by period to period
fluctuations in commodity prices. In the second quarter of 2006, we revised
our
five year unsecured credit facility to increase our maximum credit amount under
the facility to $750 million and increased our current borrowing base to $500
million. As of September 30, 2006, we have total borrowings under the facility
and line of credit of $330 million. On October 24, 2006, we completed the sale
of $200 million of ten year 8.25% senior subordinated notes and paid down our
borrowings under our facility by $141 million and our credit facility and line
of credit availability as of November 1, 2006 was $311 million.
Capital
Expenditures. We
establish a capital budget for each calendar year based on our development
opportunities and the expected cash flow from operations for that year. We
may
revise our capital budget during the year as a result of acquisitions and/or
drilling outcomes. Excess cash generated from operations is expected to be
applied toward acquisitions, debt reduction or other corporate purposes.
Excluding
acquisitions, our approved capital budget for 2006 is $275 million. For 2006,
we
plan to invest approximately $190 million, or 69% of the approved capital
budget, in our Rocky Mountain and Mid-Continent region assets, and $85 million,
or 31%, in our California assets. Approximately half of the capital budget
is
focused on converting probable and possible reserves into proved reserves and
on
our appraisal and exploratory projects, while the other half is for the
development of our proved reserves and facility costs. Capital expenditures,
excluding acquisitions, are primarily funded out of internally generated cash
flow.
Dividends.
In 2006,
we increased the dividend for the fourth consecutive year and the current
quarterly dividend is $.075 per share. We also paid a special dividend of $.02
per share in September of 2006.
Working
Capital and Cash Flows. Cash
flow
from operations is dependent upon the price of crude oil and natural gas and
our
ability to increase production and manage costs.
Our
working capital balance fluctuates as a result of the amount of borrowings
and
the timing of repayments under our credit arrangements. We use our long-term
borrowings under our credit facility primarily to fund property acquisitions.
Generally, we use excess cash to pay down borrowings under our credit facility.
As a result, we often have a working capital deficit or a relatively small
amount of positive working capital.
The
table
below compares financial condition, liquidity and capital resources changes
for
the three month periods ended (in millions, except for production and average
prices):
|
September
30, 2006
|
September
30, 2005
|
Change
|
June
30, 2006
|
Change
|
Production
(BOE/D)
|
26,423
|
23,647
|
12%
|
24,768
|
7%
|
Average
oil and gas sales prices, per BOE after hedging
|
$
47.28
|
$
44.25
|
7%
|
$
49.75
|
(5%)
|
Net
cash provided by operating activities
|
$
101
|
$
56
|
80%
|
$
59
|
71%
|
Working
capital, excluding line of credit
|
$
(154)
|
$
(27)
|
(470%)
|
$
(38)
|
(303%)
|
Sales
of oil and gas
|
$
116
|
$
96
|
21%
|
$
111
|
5%
|
Long-term
debt, including line of credit
|
$
330
|
$
100
|
230%
|
$
273
|
21%
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
148
|
$32.7
|
353%
|
$
65
|
128%
|
Dividends
paid
|
$
4.2
|
$
5.1
|
(18%)
|
$
2.9
|
45%
|
Contractual
Obligations. Berry's
contractual obligations as of September 30, 2006 are due in the years ended
December 31, as follows (in thousands):
Contractual
Obligations
|
|
|
Total
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
Long-term
debt and interest
|
|
$
|
404,404
|
$
|
5,021
|
$
|
20,085
|
$
|
20,085
|
$
|
20,085
|
$
|
20,085
|
$
|
319,043
|
Abandonment
obligations
|
|
|
25,897
|
|
640
|
|
740
|
|
942
|
|
991
|
|
991
|
|
21,593
|
Property
acquisition payable
|
|
|
102,000
|
|
51,000
|
|
51,000
|
|
-
|
|
-
|
|
-
|
|
-
|
Operating
lease obligations
|
|
|
10,836
|
|
340
|
|
1,420
|
|
1,370
|
|
1,178
|
|
956
|
|
5,572
|
Drilling
and rig obligations
|
|
|
115,592
|
|
10,236
|
|
40,806
|
|
24,496
|
|
40,054
|
|
-
|
|
-
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
transportation contracts
|
|
|
72,642
|
|
1,192
|
|
4,574
|
|
7,304
|
|
8,217
|
|
8,379
|
|
42,976
|
Total
|
|
$
|
731,371
|
$
|
68,429
|
$
|
118,625
|
$
|
54,197
|
$
|
70,525
|
$
|
30,411
|
$
|
389,184
|
Long-term
debt and interest
-
Long-term debt and related quarterly interest on the long-term debt borrowings
can be paid before its maturity date without significant penalty.
Operating
leases -
We
lease
corporate and field offices in California , Colorado and Texas.
Drilling
obligation
-
We
intend
to participate in the drilling of over 16 gross wells on our Lake Canyon
prospect over the next four years, and our minimum obligation under our
exploration and development agreement is $9.6 million. Also included above,
our
June 2006 joint venture agreement in the Piceance basin states that we must
have
120 wells drilled by 2010 to avoid penalties of $24 million.
Drilling
rig obligation
- We are
obligated in operating lease agreements for the use of multiple drilling rigs.
Firm
natural gas transportation
-
We
have
one firm transportation contract which provides us additional flexibility in
securing our natural gas supply and allows us to potentially benefit from lower
natural gas prices in the Rocky Mountains compared to natural gas prices in
California. We also have several long term gas transportation contracts
which provide us with physical access to interstate pipelines to move gas from
our producing areas to markets.
Item
3. Quantitative
and Qualitative Disclosures About Market Risk
As
discussed in Note 5 to the unaudited condensed financial statements, to minimize
the effect of a downturn in oil and gas prices and protect our profitability
and
the economics of our development plans, from time to time we enter into crude
oil and natural gas hedge contracts. The terms of contracts depend on various
factors, including Management’s view of future crude oil and natural gas prices,
acquisition economics on purchased assets and our future financial commitments.
This price hedging program is designed to moderate the effects of a severe
crude
oil and natural gas price downturn while allowing us to participate in the
upside. In California, we benefit from lower natural gas pricing and elsewhere,
we benefit from higher natural gas pricing. We have hedged, and may hedge in
the
future, both natural gas purchases and sales as determined appropriate by
Management. Management regularly monitors the crude oil and natural gas markets
and our financial commitments to determine if, when, and at what level some
form
of crude oil and/or natural gas hedging or other price protection is appropriate
in accordance with Board established policy.
Currently,
our hedges are in the form of swaps and collars. However, we may use a variety
of hedge instruments in the future to hedge WTI or the index gas price. We
have
crude oil sales contracts in place which are priced based on a correlation
to
WTI. Natural gas (for cogeneration and conventional steaming operations) is
purchased at the SoCal border price and we sell our produced gas in Colorado
and
Utah at the Colorado Interstate Gas (CIG) and Questar index prices,
respectively.
The
following table summarizes our hedge position as of September 30,
2006:
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Average
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Price
|
Crude
Oil Sales
(NYMEX
WTI)
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO CIG)
|
|
|
|
|
Collars
|
|
|
|
|
|
Basis
Swaps
|
|
|
|
|
4th
Quarter 2006
|
|
10,000
|
|
$47.50
/ $70
|
|
4th
Quarter 2006 Average
|
|
8,000
|
|
1.45
|
Full
year 2007
|
|
10,000
|
|
$47.50
/ $70
|
|
2007
Average
|
|
13,500
|
|
1.65
|
Full
year 2008
|
|
10,000
|
|
$47.50
/ $70
|
|
2008
Average
|
|
18,250
|
|
1.50
|
Full
year 2009
|
|
10,000
|
|
$47.50
/ $70
|
|
|
|
|
|
|
Full
year 2010
|
|
1,000
|
|
$60
/ $80
|
|
Natural
Gas Sales
(NYMEX
HH)
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
|
Floor/Ceiling
Prices
|
|
|
|
|
|
|
4th
Quarter 2006
|
|
8,000
|
|
$8.00
/ $9.72
|
|
|
|
|
|
|
1st
Quarter 2007
|
|
12,000
|
|
$8.00
/ $16.70
|
|
|
|
|
|
|
2nd
Quarter 2007
|
|
13,000
|
|
$8.00
/ $8.82
|
|
|
|
|
|
|
3rd
Quarter 2007
|
|
14,000
|
|
$8.00
/ $9.10
|
|
|
|
|
|
|
4th
Quarter 2007
|
|
15,000
|
|
$8.00
/ $11.39
|
|
|
|
|
|
|
1st
Quarter 2008
|
|
16,000
|
|
$8.00
/ $15.65
|
|
|
|
|
|
|
2nd
Quarter 2008
|
|
17,000
|
|
$7.50
/ $8.40
|
|
|
|
|
|
|
3rd
Quarter 2008
|
|
19,000
|
|
$7.50
/ $8.50
|
|
|
|
|
|
|
4th
Quarter 2008
|
|
21,000
|
|
$8.00
/ $9.50
|
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below $47.50 per barrel while still
participating in any oil price increase up to $70 per barrel on these volumes
and 2) if gas prices decline below approximately $8 per MMBtu. These hedges
improve our financial flexibility by locking in significant revenues and cash
flow upon a substantial decline in crude oil or natural gas prices. It also
allows us to develop our long-lived assets and pursue exploitation opportunities
with greater confidence in the projected economic outcomes and allows us to
borrow a higher amount under the credit facility.
The
use
of hedging transactions also involves the risk that the counterparties will
be
unable to meet the financial terms of such transactions. With respect to our
hedging activities, we utilize multiple counterparties on our hedges and monitor
each counterparty’s credit rating. We also attempt to minimize credit exposure
to counterparties through diversification.
Based
on
NYMEX futures prices as of September 30, 2006, (WTI $67.24; HH $7.59), we would
expect to make pre-tax future cash payments or to receive payments over the
remaining term of our crude oil and natural gas hedges in place as
follows:
|
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|
|
|
September
30, 2006
|
|
|
on
earnings
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Price
|
|
$
|
67.24
|
|
$
|
53.79
|
|
$
|
60.52
|
|
$
|
73.97
|
|
$
|
80.69
|
|
Crude
Oil gain/(loss) (in millions)
|
|
|
-
|
|
|
2.8
|
|
|
.2
|
|
|
(53.2
|
)
|
|
(133.1
|
)
|
Average
HH Price
|
|
|
7.59
|
|
|
6.07
|
|
|
6.83
|
|
|
8.35
|
|
|
9.11
|
|
Natural
Gas gain/(loss) (in millions)
|
|
|
2.6
|
|
|
19.1
|
|
|
9.8
|
|
|
(.5
|
)
|
|
(2.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
1.8
|
|
$
|
2.7
|
|
$
|
2.2
|
|
$
|
1.2
|
|
$
|
(4.5
|
)
|
2007
|
|
|
1.8
|
|
|
8.9
|
|
|
5.1
|
|
|
(16.2
|
)
|
|
(41.0
|
)
|
2008
|
|
|
(1.1
|
)
|
|
7.6
|
|
|
2.4
|
|
|
(22.8
|
)
|
|
(50.0
|
)
|
2009
|
|
|
.1
|
|
|
-
|
|
|
-
|
|
|
(15.9
|
)
|
|
(40.4
|
)
|
2010
|
|
|
-
|
|
|
2.7
|
|
|
.3
|
|
|
-
|
|
|
-
|
|
Total
|
|
$
|
2.6
|
|
$
|
21.9
|
|
$
|
10.0
|
|
$
|
(53.7
|
)
|
$
|
(135.9
|
)
|
Interest
Rates.
Our
exposure to changes in interest rates results primarily from long-term debt.
On
October 24, 2006, the Company issued $200 million of 8.25% senior subordinated
notes due 2016 in a public offering. Total
long-term debt outstanding under our credit facility at October 24, 2006 was
$170 million. Interest on amounts borrowed is charged at LIBOR plus 1.0% to
1.75%, with the exception of the $100 million of principal for which we have
hedges in place to fix the interest rate at 5.5% plus the credit facility’s
margin. Based on these borrowings, a 1% change in interest rates would have
a
$.7 million impact on interest expense on an annual basis.
Item
4. Controls and Procedures
As
of
September 30, 2006, we have carried out an evaluation under the supervision
of,
and with the participation of Management, including the Chief Executive Officer
and Chief Financial Officer, of the effectiveness of the design and operation
of
our disclosure controls and procedures pursuant to Rule 13a-15 under the
Securities and Exchange Act of 1934, as amended.
Based
on
their evaluation as of September 30, 2006, the Chief Executive Officer and
Chief
Financial Officer have concluded that our disclosure controls and procedures
(as
defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act
of
1934) are effective to ensure that the information required to be disclosed
in
the reports that we file or submit under the Securities Exchange Act of 1934
is
recorded, processed, summarized and reported within the time periods specified
in SEC rules and forms.
There
was
no change in our internal control over financial reporting during the most
recently completed calendar quarter that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
Forward
Looking Statements
“Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-Q that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “estimate,”
“will,” “intend,” “continue,” “target,” “expect,” “achieve,” “strategy,”
“future,” “may,” “goal(s),” or other comparable words or phrases or the negative
of those words, and other words of similar meaning indicate forward-looking
statements and important factors which could affect actual results.
Forward-looking statements are made based on Management’s current expectations
and beliefs concerning future developments and their potential effects upon
Berry Petroleum Company. These items are discussed at length in Part I, Item
1A
on page 16 of Berry’s Form 10-K filed with the Securities and Exchange
Commission, under the heading “Other Factors Affecting the Company’s Business
and Financial Results” in the section titled “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and all material
changes are updated in Part II, Item 1A within this 10Q.
PART
II. OTHER INFORMATION
Item
1. Legal Proceedings
None.
Item
1A. Risk Factors
Material
changes from the 2005 Form 10-K are as follows:
A
widening of commodity differentials may adversely impact our revenues and per
barrel economics.
Both
our
produced crude oil and natural gas are subject to pricing in the local markets
where the production occurs. It is customary that such products are priced
based
on local or regional supply and demand factors. California heavy crude oil
sells
at a discount to WTI, the U.S. benchmark crude oil, primarily due to the
additional cost to refine gasoline or light product out of a barrel of heavy
crude. In addition, our weighted average realized sales price for our Utah
crude
oil as of October 1, 2006 under our contracts is approximately $14.50 per barrel
below WTI with certain volumes tied to field posting, and, in some cases, our
realized price is further reduced by transportation charges. Natural gas field
prices are normally priced off of the NYMEX HH price, the benchmark for U.S.
natural gas. While we attempt to contract for the best possible price in each
of
our producing locations, there is no assurance that past price differentials
will continue into the future. Numerous factors may influence local pricing,
such as refinery capacity, particularly for paraffinic crude, pipeline capacity
and specifications, upsets in the mid-stream or downstream sectors of the
industry, trade restrictions and governmental regulations. We may be adversely
impacted by a widening differential on the products we sell. Our oil and natural
gas hedges are based on WTI or natural gas index prices, so we may be subject
to
basis risk if the differential on the products we sell widens from those
benchmarks if we do not have a contract tied to those benchmarks. Additionally,
insufficient pipeline capacity and the lack of demand in any given operating
area may cause the differential to widen in that area compared to other oil
and
gas producing areas.
Market
conditions or operational impediments may hinder our access to crude oil and
natural gas markets or delay our production.
Market
conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand
for
and supply of oil and natural gas and the proximity of reserves to pipelines
and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines,
processing facilities and refineries owned and operated by third parties. Our
failure to obtain such services on acceptable terms could materially harm our
business. We may be required to shut in wells for a lack of a market or because
of inadequacy or unavailability of natural gas pipelines, gathering system
capacity, processing facilities or refineries. If that were to occur, then
we
would be unable to realize revenue from those wells until arrangements were
made
to deliver the production to market.
Factors
that can cause price volatility for crude oil and natural gas
include:
· |
availability
and capacity of refineries;
|
· |
availability
of gathering systems with sufficient capacity to handle local
production;
|
· |
seasonal
fluctuations in local demand for production;
|
· |
local
and national gas storage capacity;
|
· |
interstate
pipeline capacity; and
|
· |
availability
and cost of gas transportation facilities.
|
Our
Utah
crude oil is a paraffinic crude and can be processed efficiently by only a
limited number of refineries. Increased production of crude oil in the region,
the ability of refiners to process other higher sulfur crudes as a result of
capital upgrades, as well as the increasing availability of Canadian crude
oil,
is putting downward pressure on the sales price of our crude oil.
Our
weighted average realized sales price for our Utah crude oil as of October
1,
2006 under our contracts is approximately $14.50 per barrel below WTI, with
certain volumes tied to field posting. In some cases, our realized price is
further reduced by transportation charges. From October 1, 2003 through April
30, 2006, we sold our Utah crude oil at approximately $2 per barrel below WTI;
and from May 1, 2006 through September 30, 2006, we sold the majority of our
Utah crude oil at approximately $9 per barrel below WTI.
Due
to
this lower pricing and based on sales of 4,600 Bbl/D gross, we estimate our
revenues will be lower by approximately $4 million in the fourth quarter of
2006, as compared to the third quarter of 2006. If this pricing continues
throughout 2007 and on the same volumes, we estimate our 2007 revenues will
be
lower by approximately $15 million versus our expected 2006 revenues. Field
postings are currently at approximately $12 to $13 below WTI. We are working
on
a longer term sales contract for our crude oil, which has a high paraffinic
content, and may adjust our future capital expenditures in the Uinta basin
due
to our actual or expected change in our realized price.
We
are subject to complex federal, state, regional, local and other laws and
regulations that could give rise to substantial liabilities from environmental
contamination or otherwise adversely affect our cost, manner or feasibility
of
doing business.
All
facets of our operations are regulated extensively at the federal, state,
regional and local levels. In addition, a portion of our leases in the Uinta
basin in Utah are, and some of our future leases may be, regulated by Native
American tribes. Environmental laws and regulations impose limitations on our
discharge of pollutants into the environment, establish standards for our
management, treatment, storage, transportation and disposal of hazardous
materials and of solid and hazardous wastes, and impose on us obligations to
investigate and remediate contamination in certain circumstances. We also must
satisfy, in some cases, federal and state requirements for providing
environmental assessments, environmental impact studies and/or plans of
development before we commence exploration and production activities.
Environmental and other requirements applicable to our operations generally
have
become more stringent in recent years, and compliance with those requirements
more expensive. Frequently changing environmental and other governmental laws
and regulations have increased our costs to plan, design, drill, install,
operate and abandon oil and natural gas wells and other facilities, and may
impose substantial liabilities if we fail to comply with such regulations or
for
any contamination resulting from our operations. Failure to comply with these
laws and regulations may also result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties.
Furthermore, our business, results from operations and financial condition
may
be adversely affected by any failure to comply with, or future changes to,
these
laws and regulations.
In
addition, we could also be liable for the investigation or remediation of
contamination, as well as other liabilities concerning hazardous materials
or
contamination such as claims for personal injury or property damage. Such
liabilities may arise at many locations, including properties in which we have
an ownership interest but no operational control, properties we formerly owned
or operated and sites where our wastes have been treated or disposed of, as
well
as at properties that we currently own or operate, and may arise even where
the
contamination does not result from any noncompliance with applicable
environmental laws. Under a number of environmental laws, such liabilities
may
also be joint and several, meaning that we could be held responsible for more
than our share of the liability involved, or even the entire share. We have
incurred expenses and penalties in connection with remediation of contamination
in the past, and we may do so in the future. From time to time we have
experienced accidental spills, leaks and other discharges of contaminants at
some of our properties, as have other similarly situated oil and gas companies,
and some of the properties that we have acquired, or in which we may hold an
interest but not operational control, may have past or ongoing contamination
for
which we may be held responsible.
Some
of
our operations are in environmentally sensitive areas, including coastal areas,
wetlands, areas that may provide habitat for endangered or threatened species,
and other protected areas, and our operations in such areas must satisfy
additional regulatory requirements. Moreover, public interest in environmental
protection has increased in recent years, and environmental organizations have
opposed certain drilling projects and/or access to prospective lands and have
filed litigation to attempt to stop such projects, including decisions by the
Bureau of Land Management regarding several leases in Utah that we have been
awarded.
Our
activities are also subject to the regulation by oil and natural gas-producing
states and one Native American tribe of conservation practices and protection
of
correlative rights. These regulations affect our operations and limit the
quantity of oil and natural gas we may produce and sell. A major risk inherent
in our drilling plans is the need to obtain drilling permits from federal,
state, local and Native American tribal authorities. Delays in obtaining
regulatory approvals or drilling permits, the failure to obtain a drilling
permit for a well or the receipt of a permit with unreasonable conditions that
are more expensive than we have anticipated could have a negative effect on
our
ability to explore on or develop our properties. Additionally, the oil and
natural gas regulatory environment could change in ways that might substantially
increase the financial and managerial costs to comply with the requirements
of
these laws and regulations and, consequently, adversely affect our
profitability.
Future
environmental regulations, including potential state and federal restrictions
on
greenhouse gasses that may be passed in response to climate change concerns,
could increase our costs to operate and produce our properties and also reduce
the demand for the oil we produce. While we continue to diversify our asset
base
by acquiring additional natural gas assets, our business, results from
operations and financial condition may be adversely affected by future
restrictions.
Furthermore,
we benefit from federal energy laws and regulations that relieve our
cogeneration plants, all of which are Qualifying Facility (QFs), from compliance
with extensive federal and state regulations that control the financial
structure of electricity generating plants, as well as the prices and terms
on
which electricity may be sold by those plants. These federal energy regulations
also require that electric utilities purchase electricity generated by our
cogeneration plants at a price based on the purchasing utility’s avoided cost,
and that the utility sell back-up power to us on a non-discriminatory basis.
The
term "avoided cost" is defined as the incremental cost to an electric utility
of
electric energy or capacity, or both, which, but for the purchase from QFs,
such
utility would generate for itself or purchase from another source. These
regulations have recently been amended; and a utility may now petition the
Federal Energy Regulation Commission (FERC) to be relieved of its obligation
to
enter into any new contracts with us, if the FERC determines that a competitive
electricity market is available to us in our service territory.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
In
June
2005, the Company announced that its Board of Directors authorized a share
repurchase program for up to an aggregate of $50 million of the Company's
outstanding Class A Common Stock. In December 2005, the Company adopted a plan
under Rule 10b5-1 of the Securities Exchange Act of 1934 to facilitate the
repurchase of its shares of common stock. Rule 10b5-1 allows a company to
purchase its shares at times when it would not normally be in the market due
to
possession of nonpublic information, such as the time immediately preceding
its
quarterly earnings releases. This 10b5-1 plan is authorized under, and is
administered consistent with, the Company's $50 million share repurchase
program. All repurchases of common stock are made in compliance with regulations
set forth by the SEC and are subject to market conditions, applicable legal
requirements and other factors. For the three months ended September 30, 2006,
the Company repurchased 92,500 shares for approximately $3 million. Since June
2005, total shares repurchased through September 30, 2006 are 500,200 for
approximately $22.1 million.
Period
|
|
Total
number of shares purchased
|
|
Average
price paid per share
|
|
Total
number of shares purchased as part of publicly announced plans or
programs
|
|
Maximum
approximate dollar value of shares that may yet be purchased under
the
plans or programs (in thousands)
|
First
Quarter 2006
|
|
60,000
|
|
$
30.04
|
|
60,000
|
|
$
41,882
|
Second
Quarter 2006
|
|
347,700
|
|
31.55
|
|
347,700
|
|
30,913
|
July
2006
|
|
75,000
|
|
32.50
|
|
75,000
|
|
28,475
|
August
2006
|
|
17,500
|
|
31.79
|
|
17,500
|
|
27,919
|
Total
|
|
500,200
|
|
$
31.52
|
|
500,200
|
|
$
27,919
|
Item
3. Defaults Upon Senior Securities
None.
Item
4. Submission of Matters to a Vote of Security Holders
None.
Item
5. Other Information
None.
Item
6. Exhibits
Exhibit
No.
Description
of Exhibit
3.1* Registrant’s
Restated Certificate of Incorporation (filed as Exhibit 3.1 on Form 8-K filed
on
August 8, 2006, file number 1-9735).
4.1* Registrant’s
8.25% Senior Subordinated Notes (filed as Form 425B5 on October 19,
2006).
10.1* Form
of
Change in Control Severance Protection Agreement (filed as Exhibit 99.1 on
Form
8-K filed on August 24, 2006, file number 1-9735).
10.2* Underwriting
Agreement dated October 18, 2006 by and between Berry Petroleum Company and
the
several Underwriters listed in Schedule 1 thereto (filed as Exhibit 1.1 on
Form
8-K filed on October 19, 2006, file number 1-9735).
10.3* First
Supplemental Indenture dated October 24, 2006 (filed as Exhibit 4.1 on Form
8-K
filed on October 26, 2006, file number 1-9735).
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.
*
Incorporated by reference
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
BERRY
PETROLEUM COMPANY
/s/
Donald A. Dale
Donald
A.
Dale
Controller
(Principal
Accounting Officer)
Date: November
8, 2006