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
March 31, 2006
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
April 20, 2006, the registrant had 21,160,513 shares of Class A Common Stock
($.01 par value) outstanding. The registrant also had 898,892 shares of Class
B
Stock outstanding on April 20, 2006 all of which is held by an affiliate
of the
registrant.
BERRY
PETROLEUM COMPANY AND SUBSIDIARY
FIRST
QUARTER 2006 FORM 10-Q
TABLE
OF CONTENTS
PART
I.
FINANCIAL
INFORMATION
|
|
Page
|
|
|
|
|
Item
1. Financial Statements
|
|
|
|
|
|
Unaudited
Condensed Consolidated Balance Sheets at March 31, 2006 and December
31,
2005
|
3
|
|
|
|
|
Unaudited
Condensed Consolidated Income Statements for the Three Month Periods
Ended
March 31, 2006 and 2005
|
4
|
|
|
|
|
Unaudited
Condensed Consolidated Statements of Comprehensive Income for the
Three
Month Periods Ended March 31, 2006 and 2005
|
4
|
|
|
|
|
Unaudited
Condensed Consolidated Statements of Cash Flows for the Three Month
Periods Ended March 31, 2006 and 2005
|
5
|
|
|
|
|
Notes
to Unaudited Condensed Consolidated Financial Statements
|
6
|
|
|
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
10
|
|
|
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
18
|
|
|
|
|
Item
4. Controls and Procedures
|
19
|
|
|
|
PART
II.
OTHER
INFORMATION
|
|
|
|
|
|
|
Item
1. Legal Proceedings
|
20
|
|
|
|
|
Item
1A. Risk Factors
|
20
|
|
|
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
20
|
|
|
|
|
Item
3. Defaults Upon Senior Securities
|
20
|
|
|
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
20
|
|
|
|
|
Item
5. Other Information
|
20
|
|
|
|
|
Item
6. Exhibits
|
20
|
BERRY
PETROLEUM COMPANY AND SUBSIDIARY
Unaudited
Condensed Consolidated Balance Sheets
(In
Thousands, Except Share Information)
|
|
|
March
31, 2006
|
|
|
December
31, 2005
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
1,385
|
|
$
|
1,990
|
|
Short-term
investments available for sale
|
|
|
661
|
|
|
661
|
|
Accounts
receivable
|
|
|
59,941
|
|
|
59,672
|
|
Deferred
income taxes
|
|
|
9,943
|
|
|
4,547
|
|
Fair
value of derivatives
|
|
|
624
|
|
|
3,618
|
|
Prepaid
expenses and other
|
|
|
6,066
|
|
|
4,398
|
|
Total
current assets
|
|
|
78,620
|
|
|
74,886
|
|
|
|
|
|
|
|
|
|
Oil
and gas properties (successful efforts basis), buildings and
equipment,
net
|
|
|
738,627
|
|
|
552,984
|
|
Long-term
deferred income taxes
|
|
|
2,329
|
|
|
1,600
|
|
Other
assets
|
|
|
5,399
|
|
|
5,581
|
|
|
|
$
|
824,975
|
|
$
|
635,051
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
55,153
|
|
$
|
57,783
|
|
Revenue
and royalties payable
|
|
|
13,862
|
|
|
34,920
|
|
Accrued
liabilities
|
|
|
8,174
|
|
|
8,805
|
|
Line
of credit
|
|
|
9,500
|
|
|
11,500
|
|
Income
taxes payable
|
|
|
5,592
|
|
|
1,237
|
|
Fair
value of derivatives
|
|
|
26,560
|
|
|
15,398
|
|
Total
current liabilities
|
|
|
118,841
|
|
|
129,643
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
52,664
|
|
|
55,804
|
|
Long-term
debt
|
|
|
249,000
|
|
|
75,000
|
|
Abandonment
obligation
|
|
|
10,724
|
|
|
10,675
|
|
Unearned
revenue
|
|
|
736
|
|
|
866
|
|
Fair
value of derivatives
|
|
|
61,349
|
|
|
28,853
|
|
|
|
|
374,473
|
|
|
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, 50,000,000 shares authorized; 21,177,938 shares
issued and
outstanding (21,099,906 in 2005)
|
|
|
212
|
|
|
211
|
|
Class
B Stock, 1,500,000 shares authorized; 898,892 shares issued and
outstanding (liquidation preference of $899)
|
|
|
9
|
|
|
9
|
|
Capital
in excess of par value
|
|
|
58,225
|
|
|
56,064
|
|
Accumulated
other comprehensive loss
|
|
|
(49,474
|
)
|
|
(24,380
|
)
|
Retained
earnings
|
|
|
322,689
|
|
|
302,306
|
|
Total
shareholders' equity
|
|
|
331,661
|
|
|
334,210
|
|
|
|
$
|
824,975
|
|
$
|
635,051
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY AND SUBSIDIARY
Unaudited
Condensed Consolidated Statements of Income
Three
Month Periods Ended March 31, 2006 and 2005
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
2006
|
|
|
2005
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas
|
|
|
|
|
$
|
101,932
|
|
$
|
75,391
|
|
Sales
of electricity
|
|
|
|
|
|
15,169
|
|
|
12,456
|
|
Interest
and other income, net
|
|
|
|
|
|
493
|
|
|
148
|
|
|
|
|
|
|
|
117,594
|
|
|
87,995
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
25,738
|
|
|
20,892
|
|
Operating
costs - electricity generation
|
|
|
|
|
|
14,332
|
|
|
13,358
|
|
Production
taxes
|
|
|
|
|
|
3,233
|
|
|
2,515
|
|
Exploration
costs
|
|
|
|
|
|
2,289
|
|
|
561
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
13,223
|
|
|
8,527
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
|
|
|
767
|
|
|
772
|
|
General
and administrative
|
|
|
|
|
|
8,314
|
|
|
4,820
|
|
Interest
|
|
|
|
|
|
1,577
|
|
|
1,162
|
|
Commodity
derivatives
|
|
|
|
|
|
4,828
|
|
|
-
|
|
Dry
hole, abandonment and impairment
|
|
|
|
|
|
5,209
|
|
|
2,021
|
|
|
|
|
|
|
|
79,510
|
|
|
54,628
|
|
Income
before income taxes
|
|
|
|
|
|
38,084
|
|
|
33,367
|
|
Provision
for income taxes
|
|
|
|
|
|
14,833
|
|
|
10,862
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
23,251
|
|
$
|
22,505
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
$
|
1.06
|
|
$
|
1.02
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
$
|
1.03
|
|
$
|
1.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
per share
|
|
|
|
|
$
|
.13
|
|
$
|
.12
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used
to calculate
basic net income per share)
|
|
|
|
|
|
21,994
|
|
|
21,981
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
459
|
|
|
433
|
|
Director
deferred compensation
|
|
|
|
|
|
49
|
|
|
56
|
|
Weighted
average number of shares of capital stock used to calculate
diluted net
income per share
|
|
|
|
|
|
22,502
|
|
|
22,470
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Consolidated Statements of Comprehensive
Income
|
|
Three
Month Periods Ended March 31, 2006 and 2005
|
(In
Thousands)
|
Net
income
|
|
|
|
|
$
|
23,251
|
|
$
|
22,505
|
|
Unrealized
losses on derivatives, net of income taxes of ($14,184) and
($12,165),
respectively
|
|
|
|
|
|
(21,276
|
)
|
|
(18,831
|
)
|
Reclassification
of realized (losses) gains included in net income net of
income taxes of
($2,545) and ($501), respectively
|
|
|
|
|
|
(3,818
|
)
|
|
752
|
|
Comprehensive
(loss) income
|
|
|
|
|
$
|
(1,843
|
)
|
$
|
4,426
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY AND SUBSIDIARY
Unaudited
Condensed Consolidated Statements of Cash Flows
Three
Month Periods Ended March 31, 2006 and 2005
(In
Thousands)
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
23,251
|
|
$
|
22,505
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
13,990
|
|
|
9,299
|
|
Dry
hole, abandonment and impairment
|
|
|
|
|
|
4,985
|
|
|
(213
|
)
|
Commodity
derivatives
|
|
|
|
|
|
4,828
|
|
|
-
|
|
Stock-based
compensation expense
|
|
|
|
|
|
1,014
|
|
|
376
|
|
Deferred
income taxes, net
|
|
|
|
|
|
7,464
|
|
|
5,042
|
|
Other,
net
|
|
|
|
|
|
52
|
|
|
89
|
|
Increase
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
|
|
|
(1,936
|
)
|
|
(10,541
|
)
|
Increase
in current liabilities other than book overdraft, line of credit
and fair
value of derivatives
|
|
|
|
|
|
(28,331
|
)
|
|
(7,305
|
)
|
Net
cash provided by operating activities
|
|
|
|
|
|
25,317
|
|
|
19,252
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
|
|
|
|
(41,345
|
)
|
|
(23,075
|
)
|
Property
acquisitions
|
|
|
|
|
|
(159,016
|
)
|
|
(101,105
|
)
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
|
|
|
(5,723
|
)
|
|
(970
|
)
|
Net
cash used in investing activities
|
|
|
|
|
|
(206,084
|
)
|
|
(125,150
|
)
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of line of credit
|
|
|
|
|
|
51,000
|
|
|
-
|
|
Payment
of line of credit
|
|
|
|
|
|
(53,000
|
)
|
|
-
|
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
219,750
|
|
|
116,000
|
|
Payment
of long-term debt
|
|
|
|
|
|
(45,750
|
)
|
|
(6,000
|
)
|
Dividends
paid
|
|
|
|
|
|
(2,867
|
)
|
|
(2,642
|
)
|
Change
in book overdraft
|
|
|
|
|
|
9,881
|
|
|
-
|
|
Stock
option exercises
|
|
|
|
|
|
2,950
|
|
|
-
|
|
Repurchase
of shares
|
|
|
|
|
|
(1,802
|
)
|
|
-
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
180,162
|
|
|
107,358
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash and cash equivalents
|
|
|
|
|
|
(605
|
)
|
|
1,460
|
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
1,990
|
|
|
16,690
|
|
Cash
and cash equivalents at end of period
|
|
|
|
|
$
|
1,385
|
|
$
|
18,150
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of $5,468 and $10,756, respectively)
|
|
|
|
|
$
|
(8,203
|
)
|
$
|
(16,717
|
)
|
Non-current
(net of income taxes of $11,261 and $908, respectively)
|
|
|
|
|
|
(16,891
|
)
|
|
(1,362
|
)
|
Net
decrease to accumulated other comprehensive income
|
|
|
|
|
$
|
(25,094
|
)
|
$
|
(18,079
|
)
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY AND SUBSIDIARY
Notes
to the Unaudited Condensed Consolidated Financial
Statements
1. General
All
adjustments which are, in the opinion of Management, necessary for a fair
statement of Berry Petroleum Company’s and subsidiary (collectively, the
“Company”) financial position at March 31, 2006 and December 31, 2005 and
results of operations and cash flows for the three month periods ended March
31,
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.
With
the
exception of the consolidation of the new subsidiary obtained in our
acquisition, Piceance Operating Company LLC (see Note 8), the accompanying
unaudited condensed consolidated 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
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.
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 March 31,
2006
and March 31, 2005 is $11.8 million and $1.9 million, respectively, representing
outstanding checks in excess of the bank balance (book overdraft).
2. Recent
Accounting Developments
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 after September
15, 2006. The impact of SFAS No. 155 will depend on the nature and extent
of any new derivative instruments entered into after the effective
date.
3. 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) will 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) did not have a material impact
on
our condensed consolidated financial statements for the three months ended
March
31, 2006.
Equity
Compensation Plans
The
2005
Equity Incentive Plan (the 2005 Plan), approved by shareholders in May 2005,
provides for granting of equity compensation to purchase up to an aggregate
of
1,450,000 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 is either 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 5,000 options at the market
value on the date of grant. The options granted to the non-employee Directors
vest immediately. The Company uses a broker for issuing new shares upon option
exercise.
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. 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. For the three months ended March 31, 2006, the Company
repurchased 30,000 shares for approximately $1.8 million. Since June 2005,
total
shares repurchased through March 31, 2006 is 138,900 for approximately $8.1
million.
3. Share-Based
Compensation (Continued)
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 123, Accounting
for Stock-Based Compensation.
The
modified prospective method was selected as described in SFAS 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. There were no grants made
in the
first quarter of 2005, therefore no data is shown below for that
quarter.
|
March
31, 2006
|
|
|
Expected
volatility
|
32%
- 33%
|
|
|
Weighted-average
volatility
|
32%
|
|
|
Expected
dividends
|
.79%
- .88%
|
|
|
Expected
term (in years)
|
5.27
|
|
|
Risk-free
rate
|
4.5
- 4.7
|
|
|
The
following is a summary of stock option activity for the three months ended
March
31, 2006 is as follows:
|
|
|
Options
|
|
|
Weighted
Average Exercise Price
|
|
|
Weighted
Average Contractual Life Remaining
|
|
Balance
outstanding, January 1
|
|
|
1,555,413
|
|
$
|
33.52
|
|
|
|
|
Granted
|
|
|
45,000
|
|
|
69.00
|
|
|
|
|
Exercised
|
|
|
(123,370
|
)
|
|
21.03
|
|
|
|
|
Canceled/expired
|
|
|
(107,050
|
)
|
|
37.91
|
|
|
|
|
Balance
outstanding, March 31
|
|
|
1,369,993
|
|
|
35.46
|
|
|
7.9
years
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
exercisable at March 31
|
|
|
603,168
|
|
|
25.61
|
|
|
6.8
years
|
|
Restricted
Stock Units
Under
the
2005 Equity Incentive Plan, the Company began a long-term incentive program
whereby restricted stock units (RSUs) are available for grant to certain
employees and RSU’s granted
vest
based on either 25% per year over 4 years or 100% after 3 years. At March
31,
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 will pay 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.
3. Share-Based
Compensation (Continued)
The
following is a summary of RSU activity for the three months ended March 31,
2006
as follows:
|
|
|
RSUs
|
|
|
Weighted
Average Intrinsic Value at Grant Date
|
|
|
Weighted
Average Contractual Life Remaining
|
|
Balance
outstanding, January 1
|
|
|
70,950
|
|
$
|
61.29
|
|
|
|
|
Granted
|
|
|
8,540
|
|
|
70.62
|
|
|
|
|
Converted
|
|
|
-
|
|
|
-
|
|
|
|
|
Canceled/expired
|
|
|
(6,800
|
)
|
|
61.29
|
|
|
|
|
Balance
outstanding, March 31
|
|
|
72,690
|
|
|
62.14
|
|
|
3.7
years
|
|
Other
share-based compensation data
|
|
Stock
Options
|
|
RSUs
|
|
|
Three
months ended
|
|
Three
months ended
|
|
|
3/31/06
|
|
3/31/05
|
|
3/31/06
|
|
3/31/05
|
Weighted-average
grant date fair value
|
$
|
23.90
|
$
|
-
|
$
|
70.62
|
$
|
-
|
Total
intrinsic value of options exercised (in millions)
|
|
5.9
|
|
9.1
|
|
-
|
|
-
|
Total
intrinsic value of options/RSUs outstanding (in millions)
|
|
45.2
|
|
33.1
|
|
4.9
|
|
-
|
Total
intrinsic value of options exercisable (in millions)
|
|
25.9
|
|
16.0
|
|
-
|
|
-
|
Total
compensation cost recognized into income (in millions)
|
|
.7
|
|
.6
|
|
.3
|
|
-
|
The
total
compensation cost related to nonvested awards not yet recognized for the
three
months ended March 31, 2006 is $9.5 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 annual period ended March
31,
2006 is $1.8 million.
4. Derivatives
The
Company’s derivatives (natural gas swaps and collar contracts) that were put in
place on March 1, 2006 do not qualify for hedge accounting under SFAS 133,
but
are important economic hedges of the Company’s natural gas commodity price
exposure. These contracts are recorded at their fair value on the balance
sheet.
During the first quarter of 2006, the Company recognized all unrealized and
realized gains and losses related to these contracts in the amount of $4.8
million on the income statement under the caption “Commodity derivatives.” The
related cash flow impact of all of the Company’s derivative activities are
reflected as cash flows from operating activities.
At
March 31, 2006, the Company’s net fair value of derivatives liability was
$87.3 million as compared to $40.6 million at December 31, 2005. Accumulated
other comprehensive loss consisted of $49.5 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 March 31, 2006. Deferred net
losses
recorded in Accumulated other comprehensive loss at March 31, 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.
5. Revisions
to the Classification of Production Taxes
Certain
amounts in the condensed consolidated income statements for the three months
ended March 31, 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 months ended March 31, 2005 (in thousands):
|
|
March
31, 2005
|
|
Operating
costs - oil and gas
|
|
|
|
As
previously reported
|
|
23,407
|
|
As
revised
|
|
20,892
|
|
Difference
|
$
|
2,515
|
|
|
|
|
|
Production
taxes
|
|
|
|
As
previously reported
|
$
|
-
|
|
As
revised
|
|
2,515
|
|
Difference
|
$
|
(2,515
|
)
|
6. Dry
Hole, Abandonment and Impairment
The
$5.2
million reflected on the Company’s income statement under the dry hole,
abandonment and impairment line item consists primarily of two Coyote Flats,
Utah prospect wells that were drilled, tested and determined non-commercial
in
2006.
7. Pro
Forma Results (unaudited)
On
January 27, 2005, the Company acquired certain interests in the Niobrara
field
in northeastern Colorado for approximately $105 million. The unaudited pro
forma
results presented below for the three months ended March 31, 2005 have been
prepared to give effect to the acquisition on the Company’s results of
operations under the purchase method of accounting as if it had been consummated
on January 1, 2005. The unaudited pro forma results do not purport to represent
the results of operations that actually would have occurred on such date
or to
project the Company’s results of operations for any future date or period. (in
thousands, except per share data):
|
|
|
March
31, 2005
|
|
Proforma
Revenue
|
|
$
|
89,358
|
|
Proforma
Income from operations
|
|
|
40,016
|
|
Proforma
Net income
|
|
|
22,809
|
|
Proforma
Basic earnings per share
|
|
|
1.04
|
|
Proforma
Diluted earnings per share
|
|
|
1.02
|
|
8. 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%
interests in Piceance Operating Company LLC (which owns 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 is the subsidiary obtained in the acquisition and is
consolidated into the financial statements.
9. Income
Taxes
The
Company’s effective tax rate was 39% for the first quarter of 2006 compared to
30% for the fourth quarter of 2005 and 33% for the first quarter of 2005.
The
effective tax rate was lower in 2005 due to the Company’s investment in projects
that qualified for the 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
approximately $44.50 per barrel.
10.Subsequent
Event
In
April
2006, the Company increased its existing credit facility borrowing base from
$350 million to $500 million and extended the term by one year to July
2011.
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 month periods ended March 31, 2006 and 2005 and the financial
condition, liquidity and capital resources as of March 31, 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
mission is to increase shareholder value, primarily through increasing the
net
asset value and maximizing the cash flow and earnings of our assets. The
strategies to accomplish these goals include:
· |
Growing
production and reserves from existing assets while managing
expenses
|
· |
Acquiring
more light oil and natural gas assets with significant growth potential
in
the Rocky Mountain and Mid-Continent
region
|
· |
Appraising
our exploitation and exploration projects in an expedient
manner
|
· |
Investing
our capital in an efficient, disciplined manner to increase production
and
reserves
|
· |
Utilizing
joint ventures with respected partners to enter new basins, utilize
available technologies, reduce our risk and/or improve
efficiencies
|
Key
First Quarter Items.
· |
Achieved
production which averaged 23,461 BOE/D, up 6% from the first quarter
of
2005
|
· |
Announced
discovery in Green River formation at Lake Canyon,
Utah
|
· |
Acquired
operatorship and significant working interest in Piceance, Colorado
natural gas assets - acquisition cost of $159
million
|
· |
Increased
our 2006 capital budget by $48 million to $208 million to include
development of our Piceance Basin assets
|
· |
Placed
natural gas hedges (both swaps and collars) on an average of 15,000
MMBtu
per day of future production from 2006 through
2008
|
· |
Have
two wells testing commercial quantities of gas at Coyote Flats, Utah
and
wrote off two dry holes
|
· |
Added
J. Frank Keller to the Board of Directors in February
2006
|
· |
Purchased
drilling rig for Piceance Basin drilling
program
|
Anticipated
and Completed Key Second Quarter Items.
· |
Added
financial capacity by increasing our credit facility borrowing base
by
$150 million to $500 million
|
· |
Will
take delivery of automated drilling rig in
California
|
· |
Two-for-one
split of Class A Common Stock and Class B Stock to be completed upon
shareholder approval in May
|
· |
Anticipate
adding 240 net acres to our Poso Creek, California enhanced oil recovery
project
|
· |
Production
has increased to 25,000 BOE/D in the first week of May
2006
|
· |
Poso
Creek, California achieved a 1,000 BOE/D milestone in April
2006
|
· |
Secured
commitments for three additional rigs to begin drilling on our Piceance
Basin property by July 2006
|
Acquisitions. On
February 28, 2006, we completed the acquisition of a 50% working interest
in
6,314 acres in the Piceance Basin of western Colorado for approximately $159
million. We estimate our net share of reserves on these properties to be
330
billion cubic feet (Bcf), which are comprised of 26 Bcf of proved reserves
and
304 Bcf of probable reserves. Since acquisition, we are drilling our fifth
gross
well and as of the first week of May 2006 there are 10 wells producing on
this
acreage. We have budgeted approximately $48 million for the initial development
of this asset in 2006 and are projecting to exit 2006 at approximately 10
MMcf
per day of production, net to our interest.
Results
of Operations. The
following companywide results are in thousands (except per share data) for
the
three months ended:
|
|
March
31, 2006
|
|
March
31, 2005
|
Change
|
December
31, 2005
|
Change
|
Sales
of oil
|
|
$
|
83,280
|
|
$
|
65,844
|
26%
|
$
|
74,588
|
12%
|
Sales
of gas
|
|
|
18,652
|
|
|
9,547
|
95%
|
|
22,467
|
(17%)
|
Total
sales of oil and gas
|
|
$
|
101,932
|
|
$
|
75,391
|
35%
|
$
|
97,055
|
5%
|
Sales
of electricity
|
|
|
15,169
|
|
|
12,456
|
22%
|
|
18,328
|
(17%)
|
Interest
and other income, net
|
|
|
493
|
|
|
148
|
233%
|
|
674
|
(27%)
|
Total
revenues and other income
|
|
$
|
117,594
|
|
$
|
87,995
|
34%
|
$
|
116,057
|
1%
|
Net
income
|
|
$
|
23,251
|
|
$
|
22,505
|
3%
|
$
|
30,372
|
(23%)
|
Earnings
per share (diluted)
|
|
$
|
1.03
|
|
$
|
1.00
|
3%
|
$
|
1.35
|
(24%)
|
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 are due to a tighter supply and demand
balance
and the nervousness of the market about possible supply disruptions, and
in
particular Iran and its nuclear aspirations.
In 2006,
we anticipate production, excluding potential future acquisitions, to average
approximately 25,800 BOE/D.
Our
production for the quarter ended March 31, 2006 was 23,461 BOE/D, which was
up
6% from the first quarter of 2005, but lower by 1% from the fourth quarter
of
2005. Our production was lower in this quarter versus our initial expectations
primarily as a result of changes at our California South Midway-Sunset field
including a modification in our steaming practices, the shut-in of a number
of
horizontal wells while we drilled a series of infill horizontal wells and
weather related outages. In the first quarter we revised our steam injection
patterns wherein we intend to improve production and ultimate recovery of
our
reserves by managing the steam volumes in the entire reservoir instead of
managing the steam by decisions based on each well’s individual performance. Our
production in early May is increasing from this field as our new steam injection
methodology is beginning to respond and the majority of our horizontal wells
are
back on production.
From
the
first quarter of 2006 as compared to the fourth quarter 2005, there was an
approximate 575 BOE/D decrease in California production and an approximate
360
BOE/D increase in Rockies and Mid-Continent production, for a net 215 BOE/D
decrease quarter to quarter. Our Rockies and Mid-Continent production is
meeting
our expectations and averaged approximately 7,950 BOE/D in the first quarter
of
2006.
In
the
first quarter of 2006, we incurred charges of $2.3 million in exploration
costs
which consists of our geological and geophysical (G&G) costs, primarily 3D
surveys and data accumulation, associated with our Tri-State and Uinta Basin
acreage. We project our total exploration expense for 2006 to be between
$5
million and $6 million. We also incurred charges of $5.2 million for two
dry
holes drilled at the Coyote Flats, Utah prospect. One well tested the acreage
west of the Scofield reservoir and the other well was our first test of the
Emery Coals. As we continue to determine the size of the reservoir at Coyote
Flats, we have now drilled two wells that are each testing gas in excess
of 900
Mcf per day near the discovery well which was drilled in 2003 with peak rates
exceeding 1 MMcf per day. In addition to the two dry holes at Coyote Flats,
we
also had one non-commercial well in the North Dakota Bakken play and one
dry
hole on our Tri-State acreage in the first quarter of 2006. The combined
dry
hole expense for these two wells was less than $.3 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 we put in place to protect our
Piceance Basin acquisition economics. These gas derivatives do not qualify
for
hedge accounting under SFAS 133, thus, it is necessary to record any
mark-to-market gains or losses into the respective accounting period. The
pre-tax charge in the first quarter is $4.8 million which represents the
change
in fair market value over the life of the contract, and is a result of an
increase in natural gas prices from the date of the derivative. We expect
that
we will be recording a non-cash gain or loss related to these derivative
instruments in each subsequent quarter until the expiration date of December
31,
2008 (see page 18 for hedge details) as the underlying future commodity price
curves increase or decrease.
Operating
data.
The
following table is for the three months ended:
|
|
|
March
31, 2006
|
%
|
|
March
31, 2005
|
%
|
|
December
31, 2005
|
%
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
15,407
|
66
|
|
15,813
|
72
|
|
15,997
|
68
|
Light
Oil Production (Bbl/D)
|
|
|
3,303
|
14
|
|
3,343
|
15
|
|
3,438
|
15
|
Total
Oil Production (Bbl/D)
|
|
|
18,710
|
80
|
|
19,156
|
87
|
|
19,435
|
83
|
Natural
Gas Production (Mcf/D)
|
|
|
28,507
|
20
|
|
17,347
|
13
|
|
25,428
|
17
|
Total
(BOE/D)
|
|
|
23,461
|
100
|
|
22,047
|
100
|
|
23,673
|
100
|
Percentage
increase from prior year
|
|
|
6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
50.04
|
|
$
|
40.89
|
|
$
|
51.71
|
|
Average
sales price after hedging
|
|
|
48.45
|
|
|
37.81
|
|
|
44.90
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
63.48
|
|
$
|
49.85
|
|
$
|
60.05
|
|
Price
sensitive royalties
|
|
|
(5.41)
|
|
|
(3.12)
|
|
|
(5.02)
|
|
Gravity
differential
|
|
|
(6.36)
|
|
|
(5.22)
|
|
|
(5.38)
|
|
Crude
oil hedges
|
|
|
(2.04)
|
|
|
(3.54)
|
|
|
(7.54)
|
|
Average
oil sales price after hedging
|
|
$
|
49.67
|
|
$
|
37.97
|
|
$
|
42.11
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas,
per MMBtu:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price
|
|
$
|
7.92
|
|
$
|
6.27
|
|
$
|
12.48
|
|
Natural
gas hedges
|
|
|
(.03)
|
|
|
-
|
|
|
(.55)
|
|
Location
and quality differentials
|
|
|
(1.05)
|
|
|
(.79)
|
|
|
(2.92)
|
|
Average
gas sales price after hedging
|
|
$
|
6.84
|
|
$
|
5.48
|
|
$
|
9.01
|
|
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 for approximately 15,000 net barrels per day. 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.
Brundage
Canyon crude oil production, which is approximately 40 degree API gravity,
is
currently sold under contract at WTI less a fixed differential approximating
$2.00 per barrel. This contract expires on September 30, 2006. The differential
of this crude oil to WTI, based on recent postings, has widened to approximately
$9.00 per barrel. We are investigating our market opportunities for this
crude
oil and are in negotiations with several refineries on certain quantities
of our
production. While the ultimate outcome of
future
crude oil sales contracts remains uncertain, we are working diligently to
place
the majority of our Uinta Basin crude production with refiners at prices
approximating market. We may also renegotiate our existing crude oil sales
contract near current market prices in an effort to secure a longer term
contract for our crude.
Hedging.
See
Note
4 to the unaudited condensed consolidated 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 March 31, 2006 were up from the three months ended
March 31, 2005 due to 25% higher electricity prices and 25% higher natural
gas
prices, respectively. However, revenue and operating costs in the three months
ended March 31, 2006 were down from the three months ended December 31, 2005
due
to 16% lower electricity prices and 29% lower natural gas prices, respectively.
We purchased approximately 38 MMBtu/D and 39 MMBtu/D, respectively, as fuel
for
use in our cogeneration facilities in the three months ended March 31, 2006
and
2005. The following table is for the three months ended:
|
|
|
March
31, 2006
|
|
|
March
31, 2005
|
|
|
December
31, 2005
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
15.2
|
|
$
|
12.5
|
|
$
|
18.3
|
|
Operating
costs (in millions)
|
|
$
|
14.3
|
|
$
|
13.4
|
|
$
|
18.5
|
|
Increase
(decrease) to total oil and gas operating expenses-per
barrel
|
|
$
|
.40
|
|
$
|
(.45
|
)
|
$
|
(.07
|
)
|
Electric
power produced - MWh/D
|
|
|
2,080
|
|
|
2,117
|
|
|
2,082
|
|
Electric
power sold - MWh/D
|
|
|
1,884
|
|
|
1,918
|
|
|
1,886
|
|
Average
sales price/MWh after hedging
|
|
$
|
85.93
|
|
$
|
68.87
|
|
$
|
101.73
|
|
Fuel
gas cost/MMBtu (excluding transportation)
|
|
$
|
7.19
|
|
$
|
5.74
|
|
$
|
10.07
|
|
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
We
believe that the most informative way to analyze changes in recurring operating
expenses from one period to another is on a per unit-of-production, or BOE,
basis. The following table presents information about our operating expenses
for
each of the three month periods ended:
|
|
|
|
Amount
per BOE
|
|
|
|
|
|
Amount
(in
thousands)
|
|
|
|
|
|
March
31, 2006
|
|
March
31, 2005
|
|
December
31, 2005
|
|
March
31, 2006
|
|
March
31, 2005
|
|
December
31, 2005
|
|
Operating
costs - oil and gas production
|
|
$
|
12.19
|
|
$
|
10.53
|
|
$
|
13.66
|
|
$
|
25,738
|
|
$
|
20,892
|
|
$
|
29,710
|
|
Production
taxes
|
|
|
1.53
|
|
|
1.27
|
|
|
1.35
|
|
|
3,233
|
|
|
2,515
|
|
|
2,937
|
|
DD&A
- oil and gas production
|
|
|
6.26
|
|
|
4.30
|
|
|
5.22
|
|
|
13,223
|
|
|
8,527
|
|
|
11,350
|
|
G&A
|
|
|
3.94
|
|
|
2.43
|
|
|
2.49
|
|
|
8,314
|
|
|
4,820
|
|
|
5,408
|
|
Interest
expense
|
|
|
.75
|
|
|
.59
|
|
|
.71
|
|
|
1,577
|
|
|
1,162
|
|
|
1,548
|
|
Total
|
|
$
|
24.67
|
|
$
|
19.12
|
|
$
|
23.43
|
|
$
|
52,085
|
|
$
|
37,916
|
|
$
|
50,953
|
|
Our
total
operating costs, production taxes, G&A and interest expenses for the three
months ended March 31, 2006, stated on a unit-of-production basis, increased
29%
over the three months ended March 31, 2005 and increased 5% over the three
months ended December 31, 2005. The changes were primarily related to the
following items:
· |
Operating
costs: Operating costs in the first quarter of 2006 were higher than
the
first quarter of 2005 due to higher costs of steaming operations,
increased well servicing activities and higher cost of goods and
services
in general. However, operating costs were lower in the first quarter
of
2006 as compared to the fourth quarter of 2005, primarily due to
the
decrease in fuel gas cost. 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:
|
|
March
31, 2006
|
March
31, 2005
|
Change
|
December
31, 2005
|
Change
|
Average
volume of steam injected (Bbl/D)
|
75,138
|
70,440
|
7%
|
73,312
|
2%
|
Fuel
gas cost/MMBtu
|
$7.19
|
$5.74
|
25%
|
$10.07
|
(29%)
|
As
commodity prices remain robust, we anticipate that cost pressures within
our
industry may continue. Natural gas prices impact our cost structure in
California by approximately $1.75 per California BOE for each $1.00 change
in
natural gas price. The California production target for 2006 is 16,700
BOE/D.
· |
Depreciation,
depletion and amortization: DD&A increased per BOE in the three months
ended March 31, 2006 due to higher acquisition costs of our Rocky
Mountain
and Mid-Continent region assets as compared to our legacy heavy oil
assets
in California and higher finding and development costs. 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 achieve our growth goals, the Company’s
compensation costs increased significantly due to additional staffing,
higher compensation levels, bonuses, stock compensation and benefit
costs.
We also incurred higher employee travel and other G&A costs associated
with our growth activities.
|
· |
Interest
expense: We increased our outstanding borrowings to $249 million
at March
31, 2006 as compared to $75 million at December 31, 2005. Average
borrowings increased as a result of an acquisition of $159 million
during
February 2006. A certain portion of our interest cost related to
our
Piceance Basin acquisition has been capitalized into the basis of
the
asset, and we anticipate more will be capitalized during 2006.
|
Estimated
2006 Oil and Gas Operating, G&A and Interest
Expenses.
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2006 per BOE
|
|
|
|
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
11.75
to 13.75
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
1.35
to 1.65
|
|
|
|
|
|
|
|
DD&A
|
|
|
6.00
to 6.75
|
|
|
|
|
|
|
|
G&A
|
|
|
3.40
to 3.80
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
.60
to 1.00
|
|
|
|
|
|
|
|
Total
|
|
$
|
23.10
to 26.95
|
|
|
|
|
|
|
|
(1) |
Assuming
natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan
to
inject steam at levels in 2006 comparable to, or slightly higher
than 2005
levels.
|
Income
Taxes.
See Note
9 to the unaudited condensed consolidated 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 first
quarter of 39%, which is in line with our projections.
Development,
Exploitation and Exploration Activity.
Berry
drilled 95 gross (65 net) wells during the first quarter of 2006, realizing
a
gross success rate of 97 percent. We expect total expenditures of $208 million,
excluding any future acquisitions in 2006. As of March 31, 2006, we have
seven
rigs drilling on our properties under long term contracts, one of which we
own.
We have several more rigs scheduled to begin in mid-2006, including the two
other rigs we own which are being refurbished.
Uinta
Basin
Brundage
Canyon: In the first quarter we drilled 20 gross (20 net) wells at Brundage
Canyon with 100% success rate. We added a gas plant and significantly upgraded
the gas gathering infrastructure, including the addition of 30 miles of
pressurized gas line, to handle significantly higher volumes of natural gas.
We
are meeting all requirements to proceed with drilling in the Ashley National
Forest where we anticipate drilling up to 14 wells in 2006.
Lake
Canyon - Shallow: In January 2006, we announced commercial success from our
first two wells on this acreage which is approximately three miles west of
our
Brundage Canyon field. These wells contributed 45 net barrels of oil per
day in
our first quarter. A gas pipeline to the area and to the wells was completed
in
early May, thus gas production and sales are commencing out of these two
wells.
We are in the permitting process with another 30 wells which is intended
to
continue exploratory and development drilling on approximately 20,000 acres
on
the eastern edge of this 169,000 acre block.
Lake
Canyon - Deep: Berry’s industry partner is testing and evaluating a formation
interval (6,600 foot depth) in the #1 DLB well. Production of 42 degree API
crude oil has been established and a sustained production test over several
months is needed in order to quantify the magnitude of this discovery. Berry
has
a 25% working interest in this well.
Coyote
Flats: We have two successful appraisal Ferron gas wells on the east side
of the
Scofield reservoir which have each tested flow rates exceeding 900 Mcf per
day.
We are planning to construct a 13 mile gas pipeline to transport the gas
to a
sales point and anticipate sales will begin in the third quarter of 2006.
In the
first quarter of 2006, we determined that our Emery coalbed methane
well
and
our Ferron gas well, which were drilled west of the Scofield reservoir, were
dry
holes. To better delineate the areal extent of the Ferron and to improve
our
drilling success rate, we are designing a 15.5 square mile 3D seismic survey
on
the more promising acreage. We have now completed five of our nine-well drilling
commitment under our drill-to-earn agreement.
Denver-Julesburg
Basin
Tri-State
Area: In Yuma County, Colorado, we have drilled 43 wells in the first quarter
with one dry hole and are upgrading our gas gathering facilities to handle
production increases. In the Phillips County, Colorado, Paoli prospect, we
have
completed the acquisition of 20 square miles of 3D seismic and are planning
to
begin drilling in the second quarter of 2006. In our Tri-State area, Berry’s
industry partner has recently completed four 3D seismic surveys covering
a total
of 62 square miles and we plan to drill exploratory wells in the second and
third quarters of 2006 based on the results of those surveys.
Williston
Basin
Bakken
Play: We continue to be an active participant in several wells in North Dakota.
We wrote off one well as non-commercial for approximately $.3 million and
the
other wells, in which we have an interest, are being tested and/or evaluated.
It
is our intent to participate with a low working interest in a number of wells
in
the area over the next year so we can gather data with respect to the potential
of our acreage position.
Piceance
Basin
Grand
Valley: In early May, we had 10 wells completed and producing into a sales
line.
We are drilling our fifth gross well on the property since our acquisition
and
have completed seven wells since the acquisition with initial test rates
per
well between 1.3 and 2 MMcf/D. These results are consistent with our acquisition
metrics. Our net production in March averaged 1.1 MMcf/D and in early May
it is
averaging over 4 MMcf/D. We currently have one drilling rig running and plan
to
add three more rigs by mid-year 2006. We have made significant progress in
gearing up for extensive development of this asset beginning in mid-year
2006.
We anticipate drilling a total of 35 gross wells on this asset in 2006 and
are
planning for approximately 78 wells in 2007. We expect gas production from
this
project to increase quarter over quarter as we proceed with our
development.
Diatomite
The
project’s current performance is meeting our expectations and our goal of
determining commerciality in 2006 is on track. During the first quarter of
2006
we have focused our efforts on integrating the large scale, 25 well expansion
to
the pilot steam flood project that we drilled in late 2005. Steam injection
has
increased, per well production performance is improving and we have seen
consistent production growth nearing 300 BOE/D. We continue to accumulate
data, monitor subsurface temperatures and reservoir response and modify our
application of technology and operating practices in ways that we believe
will
lead to commercial development.
Midway-Sunset
A
total
of 17 well were drilled (including eight horizontal wells) during the first
quarter of 2006. The horizontal wells were drilled at the end of the first
quarter with initial steam cycles occurring in the second quarter. The vertical
wells were drilled as part of our Ethel D property thermal revitalization
efforts where production has increased from approximately 300 BOE/D in December
to its current level of over 700 BOE/D.
In
an
effort to improve production and make better use of our steam, we modified
our
cyclic steam injection practices. The modifications were made to heat regions
of
the reservoir to accelerate response as opposed to choosing cyclic candidates
based on individual well performance. This decision was made, in part, based
on
successful results from a targeted application of this approach during our
2005
cyclic steaming program. While this methodology resulted in lower first quarter
production, we believe it will ultimately result in improved
recoveries.
Poso
Creek
During
the first quarter of 2006, we continued the successful redevelopment of the
Poso
Creek field through continued steam flood injection into our pilot area,
drilling seven additional infill wells and consolidating operations by acquiring
offsetting properties. Production on this property was negligible when Berry
acquired it in 2003. Through thermal redevelopment, we have seen production
consistently increase to current levels which are currently above 1,000 BOE/D.
To build on our position at Poso Creek we added 40 acres to the west of our
existing operations in the first quarter and expect to close on an additional
240 acres to the south of our project in the second quarter of 2006.
Drilling
Activity. The
following table sets forth certain information regarding drilling activities
for
the three months ended March 31, 2006:
|
|
|
Gross
Wells
|
|
|
Net
Wells
|
|
|
Workovers
|
|
Midway-Sunset
|
|
|
17
|
|
|
16.8
|
|
|
6
|
|
Poso
Creek
|
|
|
7
|
|
|
7.0
|
|
|
2
|
|
Placerita
|
|
|
-
|
|
|
-
|
|
|
6
|
|
Brundage
Canyon
|
|
|
20
|
|
|
20.0
|
|
|
14
|
|
Coyote
Flats (1)
|
|
|
2
|
|
|
2.0
|
|
|
-
|
|
Tri-State
(2)
|
|
|
43
|
|
|
16.6
|
|
|
15
|
|
Piceance
|
|
|
5
|
|
|
2.5
|
|
|
-
|
|
Bakken
(3)
|
|
|
1
|
|
|
.1
|
|
|
-
|
|
Totals
|
|
|
95
|
|
|
65.0
|
|
|
43
|
|
(1) |
Includes
2 gross wells that were dry holes. Acreage ownership is earned upon
fulfilling certain drilling
obligations.
|
(2) |
Includes
1 gross well (.3 net well) that was a dry hole
|
(3) |
Includes
1 gross well (.06 net well) that was a dry
hole.
|
California
Drilling Rig.
In
2005, we entered into a three-year drilling contract for the services of
an
automated drilling rig. This rig provides a means for us to meet at least
half
of our California new well drilling needs for the next three years, with
the
other half being met by conventional drilling rigs. The three-year drilling
contract begins upon commissioning of the rig which is expected in the second
quarter of 2006.
Rocky
Mountain and Mid-Continent Region Drilling Rigs.
During
2005, we purchased two drilling rigs, one of which is currently drilling
while
the other is being refurbished. These rigs are leased to a drilling company
under a three year contract and carry purchase options available to the drilling
company. Owning these rigs allows us to successfully meet a portion of our
drilling needs in the Uinta Basin over the next several years. In February
2006,
we purchased a third drilling rig, which upon refurbishment, is expected
to cost
approximately $9 million and will be used in our Piceance Basin development
program. We have several more rigs contracted to begin in mid-2006.
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.
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
any future acquisitions, in 2006 we plan to spend approximately $208 million
on
capital projects and anticipate funding these expenditures from internally
generated cash flow. These expenditures will be directed toward developing
reserves, increasing oil and gas production and exploration opportunities.
For
2006, we plan to invest approximately $147 million, or 70%, in our Rocky
Mountain and Mid-Continent region assets, and $61 million, or 30%, in our
California assets. Approximately half the capital budget is focused on
converting probable and possible reserves into proved reserves and on our
appraisal and exploratory projects. All capital expenditures, excluding
acquisitions, are funded out of internally generated cash flow.
Dividends.
In 2005,
we increased the dividend for the third consecutive year and the current
quarterly dividend is $.13 per share.
Stock
Split.
On March
1, 2006, our Board of Directors approved a two-for-one split of our Class
A
Common Stock (Common Stock) and Class B Stock, subject to shareholder approval
of an increase in authorized shares. The stock split will require that
shareholders authorize the issuance of new shares at the May 17, 2006 annual
meeting. Berry's shareholders are being asked to approve an increase in the
authorized shares of Common Stock to 100 million from the current 50 million
shares and the Class B Stock to 3.0 million shares from 1.5 million shares.
If
approved, Berry’s transfer agent will distribute to each holder of record as of
the close of business on May 17, 2006, one additional share for every share
of
stock held. The split will be in the form of a stock dividend, which will
be
distributed
on June 2, 2006. Berry’s Common Stock should begin trading on a post-split basis
on June 5, 2006. Based on shares outstanding on May 1, 2006, Berry would
have
approximately 42.4 million shares of Common Stock and 1.8 million shares
of
Class B Stock outstanding following the proposed stock split
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
arrangement. 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 as follows (in millions, except for production
and
average prices):
|
March
31, 2006
|
March
31, 2005
|
Change
|
December
31, 2005
|
Change
|
Production
(BOE/D)
|
23,461
|
22,047
|
6%
|
23,673
|
(1%)
|
Average
oil and gas sales prices, per BOE after hedging
|
$
48.45
|
$
37.81
|
28%
|
$
44.90
|
8%
|
Net
cash provided by operating activities
|
$
25
|
$
19
|
32%
|
$
65
|
(62%)
|
Working
capital
|
$
(40)
|
$
(1)
|
negligible
|
$
(55)
|
(27%)
|
Sales
of oil and gas
|
$
102
|
$
75
|
36%
|
$
97
|
5%
|
Long-term
debt
|
$
249
|
$
138
|
80%
|
$
75
|
232%
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
206
|
$
125
|
65%
|
$
46
|
348%
|
Dividends
paid
|
$
2.9
|
$
2.6
|
12%
|
$
2.9
|
-
|
Contractual
Obligations. Berry's
contractual obligations as of March 31, 2006 are as follows (in thousands)
for
the years ended:
|
|
|
Total
|
|
2006
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
Thereafter
|
Long-term
debt and interest
|
|
$
|
265,011
|
$
|
4,003
|
$
|
4,003
|
$
|
4,003
|
$
|
4,002
|
$
|
249,000
|
$
|
-
|
Abandonment
obligations
|
|
|
10,724
|
|
315
|
|
360
|
|
539
|
|
556
|
|
556
|
|
8,398
|
Operating
lease obligations
|
|
|
11,521
|
|
1,046
|
|
1,400
|
|
1,370
|
|
1,178
|
|
955
|
|
5,572
|
Drilling
and rig obligations
|
|
|
22,383
|
|
14,633
|
|
2,400
|
|
2,950
|
|
2,400
|
|
-
|
|
-
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
transportation
contracts
|
|
|
35,625
|
|
3,706
|
|
4,574
|
|
4,398
|
|
4,386
|
|
4,386
|
|
14,175
|
Total
|
|
$
|
345,264
|
$
|
23,703
|
$
|
12,737
|
$
|
13,260
|
$
|
12,522
|
$
|
254,897
|
$
|
28,145
|
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 and Colorado.
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.
Drilling
rig obligation
- We are
obligated in operating lease agreements for the use of multiple drilling
rigs,
each for one year or less ending in 2006.
Firm
natural gas transportation
-
We
entered into several firm transportation contracts which provide us additional
flexibility in securing our natural gas supply and allow us to potentially
benefit from lower natural gas prices in the Rocky Mountains compared to
natural
gas prices in California.
Item
3. Quantitative
and Qualitative Disclosures About Market Risk
As
discussed in Note 4 to the unaudited condensed consolidated 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 March 31, 2006:
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
Barrels
|
|
Average
|
|
|
|
MMBtu
|
|
Average
|
Term
|
|
Per
Day
|
|
Price
|
|
Term
|
|
Per
Day
|
|
Price
|
Crude
Oil Sales
(NYMEX
WTI)
|
|
|
|
|
|
Natural
Gas Purchases (SoCal Border)
|
|
|
|
|
Swaps
|
|
|
|
|
|
Swaps
|
|
|
|
|
2nd
Quarter 2006
|
|
3,000
|
|
$50.20
|
|
2nd
Quarter 2006
|
|
5,000
|
|
$4.85
|
3rd
Quarter 2006
|
|
3,000
|
|
$49.56
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Sales
(NYMEX
HH)
|
|
|
|
|
Collars
|
|
|
|
Floor/Ceiling
Prices
|
|
Swaps
|
|
|
|
|
1st
through 3rd Quarter 2006
|
|
7,000
|
|
$47.50
/ $70
|
|
2nd
Quarter 2006
|
|
4,000
|
|
$6.96
|
4th
Quarter 2006
|
|
10,000
|
|
$47.50
/ $70
|
|
3rd
Quarter 2006
|
|
6,000
|
|
$7.35
|
Full
year 2007
|
|
10,000
|
|
$47.50
/ $70
|
|
|
|
|
|
|
Full
year 2008
|
|
10,000
|
|
$47.50
/ $70
|
|
Collars
|
|
|
|
Floor/Ceiling
Prices
|
Full
year 2009
|
|
10,000
|
|
$47.50
/ $70
|
|
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 March 31, 2006, (WTI $68.71; HH $9.09) and due
to the
backwardated nature of the futures prices as of that date, 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
|
|
|
|
|
March
31, 2006
|
|
|
on
earnings
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Price
|
|
$
|
68.71
|
|
$
|
54.97
|
|
$
|
61.84
|
|
$
|
75.59
|
|
$
|
82.46
|
|
Crude
Oil gain/(loss) (in millions)
|
|
|
(10.4
|
)
|
|
(2.8
|
)
|
|
(6.6
|
)
|
|
(87.5
|
)
|
|
(181.7
|
)
|
Average
HH Price
|
|
|
9.09
|
|
|
7.27
|
|
|
8.18
|
|
|
10.00
|
|
|
10.91
|
|
Natural
Gas gain/(loss) (in millions)
|
|
|
(.8
|
)
|
|
7.1
|
|
|
.7
|
|
|
(8.4
|
)
|
|
(17.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
(10.6
|
)
|
$
|
(1.8
|
)
|
$
|
(6.1
|
)
|
$
|
(28.6
|
)
|
$
|
(48.7
|
)
|
2007
|
|
|
(.2
|
)
|
|
2.3
|
|
|
-
|
|
|
(26.8
|
)
|
|
(55.5
|
)
|
2008
|
|
|
(.4
|
)
|
|
3.8
|
|
|
.2
|
|
|
(24.7
|
)
|
|
(54.4
|
)
|
2009
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(15.8
|
)
|
|
(40.5
|
)
|
Total
|
|
$
|
(11.2
|
)
|
$
|
4.3
|
|
$
|
(5.9
|
)
|
$
|
(95.9
|
)
|
$
|
(199.1
|
)
|
Interest
Rates.
Our
exposure to changes in interest rates results primarily from long-term debt.
Total long-term debt outstanding at March 31, 2006 was $249 million. Interest
on
amounts borrowed is charged at LIBOR plus 1.0% to 1.75%. Based on these
borrowings, a 1% change in interest rates would have a $2.5 million impact
on
our financial statements.
Item
4. Controls and Procedures
As
of
March 31, 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 March 31, 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.”
PART
II. OTHER INFORMATION
Item
1. Legal Proceedings
None.
Item
1A. Risk Factors
No
material changes from 2005 Form 10-K.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
None.
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
10.1* Amended
and Restated Purchase and Sale Agreement between Registrant and Orion Energy
Partners, LP.
10.2 Second
Amendment to Credit Agreement, dated as of April 28, 2006 by and between
the
Registrant and Wells Fargo Bank, N.A. and other financial institutions
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 in the Company’s 2005 annual report on Form 10-K filed
on March 6, 2006
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: May
9, 2006