form10-q.htm
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, 2007
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 15, 2007, the registrant had 42,336,198 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 15, 2007 all of which is held
by
an affiliate of the registrant.
BERRY
PETROLEUM COMPANY
THIRD
QUARTER 2007 FORM 10-Q
TABLE
OF CONTENTS
PART
I. FINANCIAL INFORMATION
|
|
Page
|
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Item
1. Financial Statements
|
|
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|
|
Unaudited
Condensed Balance Sheets at September 30, 2007 and December 31,
2006
|
3
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended
September
30, 2007 and 2006
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Three Month
Periods
Ended September 30, 2007 and 2006
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Nine Month Periods Ended September
30, 2007 and 2006
|
5
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Nine Month Periods
Ended September 30, 2007 and 2006
|
5
|
|
|
|
|
Unaudited
Condensed Statements of Cash Flows for the Nine Month Periods Ended
September 30, 2007 and 2006
|
6
|
|
|
|
|
Notes
to Unaudited Condensed Financial Statements
|
7
|
|
|
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
11
|
|
|
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
22
|
|
|
|
|
Item
4. Controls and Procedures
|
24
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PART
II.
OTHER
INFORMATION
|
|
|
|
|
|
|
Item
1. Legal Proceedings
|
24
|
|
|
|
|
Item
1A. Risk Factors
|
24
|
|
|
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
24
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|
|
|
|
Item
3. Defaults Upon Senior Securities
|
24
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|
|
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
24
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|
|
|
Item
5. Other Information
|
24
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|
|
|
|
Item
6. Exhibits
|
25
|
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
|
September
30, 2007
|
|
|
December
31, 2006
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
191
|
|
$
|
416
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
77,320
|
|
|
67,905
|
|
|
|
|
|
|
|
|
|
Fair
value of derivatives
|
|
|
6,703
|
|
|
7,349
|
|
|
|
|
|
|
|
|
|
Prepaid expenses and other
|
|
|
|
|
|
|
|
Total
current assets
|
|
|
114,106
|
|
|
98,809
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,237,921
|
|
|
1,080,631
|
|
Fair
value of derivatives
|
|
|
1,048
|
|
|
2,356
|
|
Other
assets
|
|
|
15,526
|
|
|
17,201
|
|
|
|
$
|
1,368,601
|
|
$
|
1,198,997
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
94,287
|
|
$
|
69,914
|
|
Property acquisition payable
|
|
|
|
|
|
|
|
Revenue and royalties payable
|
|
|
|
|
|
|
|
Accrued
liabilities
|
|
|
26,051
|
|
|
20,415
|
|
|
|
|
|
|
|
|
|
Fair value of derivatives
|
|
|
|
|
|
|
|
Other
current liabilities
|
|
|
1,335
|
|
|
745
|
|
Total current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
143,320
|
|
|
103,515
|
|
|
|
|
|
|
|
|
|
Abandonment
obligation
|
|
|
32,386
|
|
|
26,135
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
Fair value of derivatives
|
|
|
|
|
|
|
|
|
|
|
666,406
|
|
|
555,894
|
|
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
|
-
|
|
Capital stock, $.01 par value:
|
|
|
|
|
|
|
|
Class
A Common Stock, 100,000,000 shares authorized; 42,329,886 shares
issued
and outstanding (42,098,551 in 2006)
|
|
|
423
|
|
|
421
|
|
Class B Stock, 3,000,000 shares authorized; 1,797,784 shares
issued and outstanding (liquidation preference of
$899)
|
|
|
|
|
|
|
|
Capital
in excess of par value
|
|
|
60,449
|
|
|
50,166
|
|
Accumulated
other comprehensive loss
|
|
|
(48,410
|
)
|
|
(19,977
|
)
|
|
|
|
|
|
|
|
|
Total
shareholders' equity
|
|
|
497,120
|
|
|
427,700
|
|
|
|
$
|
1,368,601
|
|
$
|
1,198,997
|
|
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, 2007 and 2006
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
|
Three
months ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
133,500
|
|
|
129,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs – oil and gas production
|
|
|
|
|
|
33,995
|
|
|
30,950
|
|
|
Operating costs – electricity generation
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
|
|
|
4,344
|
|
|
5,286
|
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
23,356
|
|
|
17,974
|
|
|
Depreciation, depletion & amortization - electricity
generation
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative
|
|
|
|
|
|
9,333
|
|
|
9,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
5,175
|
|
|
527
|
|
|
|
|
|
|
|
|
91,227
|
|
|
78,886
|
|
|
Income
before income taxes
|
|
|
|
|
|
42,273
|
|
|
50,477
|
|
|
Provision
for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
772
|
|
|
654
|
|
|
Director deferred compensation
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
|
Three
Month Periods Ended September 30, 2007 and 2006
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($7,027)
and
$28,188, respectively
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of realized (gains) losses included in net income, net of income
taxes of
$1,411 and ($1,178), respectively
|
|
|
|
|
|
2,116
|
|
|
(1,767
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Nine
Month Periods Ended September 30, 2007 and 2006
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
|
Nine
months ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other income, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
430,207
|
|
|
370,116
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs – oil and gas production
|
|
|
|
|
|
103,330
|
|
|
83,763
|
|
|
Operating costs – electricity generation
|
|
|
|
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
|
|
|
12,297
|
|
|
11,891
|
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
65,478
|
|
|
47,333
|
|
|
Depreciation, depletion & amortization - electricity
generation
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative
|
|
|
|
|
|
29,291
|
|
|
25,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
|
|
|
|
-
|
|
|
(736
|
)
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
9,342
|
|
|
11,070
|
|
|
|
|
|
|
|
|
271,006
|
|
|
224,357
|
|
|
Income
before income taxes
|
|
|
|
|
|
159,201
|
|
|
145,759
|
|
|
Provision
for income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
701
|
|
|
792
|
|
|
Director deferred compensation
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited Condensed Statements of Comprehensive
Income
|
|
|
Nine
Month Periods Ended September 30, 2007 and 2006
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($19,484)
and
$1,223, respectively
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
of realized (gains) losses included in net income, net of income
taxes of
$529 and ($3,534), respectively
|
|
|
|
|
|
793
|
|
|
(5,301
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Nine
Month Periods Ended September 30, 2007 and 2006
(In
Thousands)
|
|
|
|
|
|
Nine
months ended September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
Dry
hole and impairment
|
|
|
|
|
|
8,725
|
|
|
6,965
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
|
|
|
53,162
|
|
|
44,410
|
|
Gain
on sale of oil and gas properties
|
|
|
|
|
|
(51,816
|
)
|
|
-
|
|
Other,
net
|
|
|
|
|
|
750
|
|
|
1,749
|
|
Cash paid for abandonment
|
|
|
|
|
|
|
|
|
|
|
Increase in current assets other than cash, cash equivalents and
short-term investments
|
|
|
|
|
|
|
|
|
|
|
Increase
in current liabilities other than book overdraft, line of credit,
property
acquisition payable and fair value of derivatives
|
|
|
|
|
|
13,116
|
|
|
8,600
|
|
Net
cash provided by operating activities
|
|
|
|
|
|
184,539
|
|
|
185,145
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Exploration and development of oil and gas
properties
|
|
|
|
|
|
|
|
|
|
|
Property
acquisitions
|
|
|
|
|
|
(56,167
|
)
|
|
(210,126
|
)
|
Additions to vehicles, drilling rigs and other fixed
assets
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of asset
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest and other
|
|
|
|
|
|
|
|
|
|
|
Net
cash used in investing activities
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of line of credit
|
|
|
|
|
|
285,150
|
|
|
241,750
|
|
Payment
of line of credit
|
|
|
|
|
|
(296,650
|
)
|
|
(232,750
|
)
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
179,300
|
|
|
324,700
|
|
Payment of long-term debt
|
|
|
|
|
|
|
|
|
|
|
Dividends
paid
|
|
|
|
|
|
(10,036
|
)
|
|
(9,889
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase of shares of common stock
|
|
|
|
|
|
|
|
|
|
|
Proceeds from stock option exercises
|
|
|
|
|
|
|
|
|
|
|
Excess tax benefit and other
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
416
|
|
|
1,990
|
|
Cash
and cash equivalents at end of period
|
|
|
|
|
$
|
191
|
|
$
|
352
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of ($13,820) and $1,491,
respectively)
|
|
|
|
|
$
|
(20,731
|
)
|
$
|
2,237
|
|
Non-current
(net of income taxes of ($5,135) and ($3,803),
respectively)
|
|
|
|
|
|
|
|
|
|
|
Net
decrease to accumulated other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
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, 2007 and December 31, 2006 and results of operations for the
three and nine month periods ended September 30, 2007 and 2006 and cash flows
for the nine month periods ended September 30, 2007 and 2006 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, 2006 financial statements. The December 31, 2006 Form 10-K and
the March 31, 2007 and June 30, 2007 Form 10-Qs 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.
Our
cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at September 30, 2007 and
December 31, 2006 is $14.2 million and $17.2 million, respectively, representing
outstanding checks in excess of the bank balance (book overdraft).
In
December 2004, Statement of Financial Accounting Standards (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. We adopted this statement beginning January 1,
2006. This standard requires us 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. The adoption of SFAS No. 123(R) using the modified
prospective method did not have a material impact on our condensed financial
statements for the year ended December 31, 2006. We previously adopted the
fair value recognition provisions of SFAS No. 123, Accounting for
Stock-Based Compensation effective January 1, 2004. The modified
prospective method was selected as described in SFAS No. 148, Accounting for
Stock-Based Compensation - Transition and Disclosure. The adoption of SFAS
No. 123(R) did not have a material impact on our condensed
financial statements as we previously applied the provisions of SFAS
No. 123.
2.
|
Recent
Accounting
Developments
|
In
June
2006, the Financial Accounting Standards Board (FASB) issued Interpretation
(FIN) No. 48, Accounting for Uncertainty in Income Taxes—an interpretation
of FASB Statement No. 109, Accounting for Income Taxes. This
interpretation requires that realization of an uncertain income tax position
must be “more likely than not” (i.e. greater than 50% likelihood of receiving a
benefit) before it can be recognized in the financial statements. Further,
this
interpretation prescribes the benefit to be recorded in the financial statements
as the amount most likely to be realized assuming a review by tax authorities
having all relevant information and applying current conventions. This
interpretation also clarifies the financial statement classification of
tax-related penalties and interest and sets forth new disclosures regarding
unrecognized tax benefits. This interpretation is effective for fiscal years
beginning after December 15, 2006, and we adopted this interpretation in
the first quarter of 2007. See Note 5.
In
September 2006, SFAS No. 157, Fair Value Measurements was issued
by the 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 our fiscal year beginning January 1,
2008, and should not have a material effect on our 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 was issued by the Securities and Exchange
Commission. 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 was adopted at December 31, 2006. The adoption
of SAB No. 108 had no effect on our financial position or on the
results of our operations.
In
April
2007, the FASB issued a FASB Staff Position to amend FASB Interpretation 39,
Offsetting Amount Related to Certain Contracts. FIN 39-1 states that a
reporting entity that is party to a master netting arrangement can offset fair
value amounts recognized for the right to reclaim cash collateral (a receivable)
or the obligation to return cash collateral (a payable) against fair value
amounts recognized for derivative instruments that have been offset under the
same master netting arrangement in accordance with paragraph 10 of
Interpretation 39. FIN 39-1 will become effective for our fiscal year beginning
January 1, 2008 and will have no effect on our financial statements as we do not
post collateral under our hedging agreements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
2.
|
Recent
Accounting Developments
(Cont’d)
|
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities, which permits an entity to
measure certain financial assets and financial liabilities at fair value. The
objective of SFAS No. 159 is to improve financial reporting by allowing entities
to mitigate volatility in reported earnings caused by the measurement of related
assets and liabilities using different attributes, without having to apply
complex hedge accounting provisions. Under SFAS No. 159, entities that elect
the
fair value option (by instrument) will report unrealized gains and losses in
earnings at each subsequent reporting date. The fair value option election
is
irrevocable, unless a new election date occurs. SFAS No. 159 establishes
presentation and disclosure requirements to help financial statement users
understand the effect of the entity’s election on its earnings, but does not
eliminate disclosure requirements of other accounting standards. Assets and
liabilities that are measured at fair value must be displayed on the face of
the
balance sheet. This statement is effective beginning January 1, 2008 and should
not have a material effect on our financial statements.
The
related cash flow impact of all of our hedges is reflected in cash flows
from
operating activities. At September 30, 2007, our net fair value of derivatives
liability was $81.4 million as compared to $33.2 million at December 31,
2006
which reflects increases in commodity prices in the period. At September
30,
2007, Accumulated Other Comprehensive Loss consisted of $48.4 million, net
of
tax, of unrealized losses from our crude oil and natural gas swaps and collars
that qualified for hedge accounting treatment at September 30, 2007. Deferred
net losses recorded in Accumulated Other Comprehensive Loss at September
30,
2007 and subsequent marked-to-market changes in the underlying hedging contracts
are expected to be reclassified to earnings over the life of these contracts.
Our liability is primarily related to the time value of the underlying
instruments and based on current prices the amount expected to be reclassified
to earnings over the next 12 months is approximately $30 million before
tax.
In
February 2007, we converted 2,000 Bbl/D of our 2007 oil collars beginning
on
March 1, 2007 to a swap with a strike price of $60 West Texas Intermediate
(WTI). Additionally, we entered into the following oil swaps and oil collars
during the nine months ended September 30, 2007:
·
|
oil
swaps for 1,000 Bbl/D at $64.55 from July 2007 through December
2007
|
·
|
oil
swaps for 260 Bbl/D at $74 for calendar year
2008
|
·
|
oil
swaps for 240 Bbl/D at $71.50 for calendar year
2009
|
·
|
oil
collars for 1,000 Bbl/D at $60 floor and $75 ceiling prices for
calendar
year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $65.15 floor and $75 ceiling prices
for
calendar year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $65.50 floor and $78.50 ceiling prices
for
calendar year 2010
|
·
|
oil
collars for 1,000 Bbl/D at $70 floor and $75.85 ceiling prices
from July
to December 2007
|
·
|
oil
collars for 1,000 Bbl/D at $70 floor and $76.70 ceiling prices
for
calendar year 2008
|
These
hedges have been designated as cash flow hedges in accordance with SFAS No.
133,
Accounting for Derivative Instruments and Hedging
Activities.
4.
|
Asset
Retirement
Obligations
|
Inherent
in the fair value calculation of the asset retirement obligation (ARO) are
numerous assumptions and judgments including the ultimate settlement amounts,
inflation factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political environments.
To
the extent future revisions to these assumptions impact the fair value of the
existing ARO liability, a corresponding adjustment is made to the oil and gas
property balance. In March 2007, we revised our estimate of future abandonment
costs due to demand for related services.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
4.
|
Asset
Retirement Obligations
(Cont’d)
|
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the nine months ended September 30, 2007 (in thousands):
|
|
|
|
|
|
Beginning
balance at January 1
|
|
$
|
26,135
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
settled
|
|
|
(1,601
|
)
|
|
|
|
Revisions
in estimated liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance at September 30
|
|
|
|
|
|
|
|
The
effective tax rate was 36% for the third quarter of 2007 compared to 39%
for the second quarter of 2007 and 38% for the third quarter of 2006. The
effective tax rate was 39% for the nine months ending September 30, 2006 and
2007. Our rate differs from a statutory rate, primarily due to state income
taxes.
In
June
2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income
Taxes—an interpretation of FASB Statement No. 109, Accounting for Income
Taxes. The Interpretation addresses the determination of whether tax
benefits claimed or expected to be claimed on a tax return should be recorded
in
the financial statements. Under FIN No. 48, we may recognize the tax benefit
from an uncertain tax position only if it is more likely than not that the
tax
position will be sustained on examination by the taxing authorities, based
on
the technical merits of the position. The tax benefits recognized in the
financial statements from such a position should be measured based on the
largest benefit that has a greater than fifty percent likelihood of being
realized upon ultimate settlement. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties on income taxes,
accounting in interim periods and requires increased disclosures.
We
adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of the date of adoption, we had
a
gross liability for uncertain tax benefits of $14.6 million of which $10.8
million, if recognized, would affect the effective tax rate. We recognize
potential accrued interest and penalties related to unrecognized tax benefits
in
income tax expense, which is consistent with the recognition of these items
in prior reporting periods. As of January 1, 2007, we had accrued approximately
$.9 million of interest related to our uncertain tax positions.
As
of
January 1, 2007, we remain subject to examination in the following major tax
jurisdictions for the tax years indicated below:
Jurisdiction:
|
Tax
Years Subject to Exam:
|
Federal
|
2003
– 2006
|
California
|
2002
– 2006
|
Colorado
|
2002
– 2006
|
Utah
|
2003
– 2006
|
For
the
nine months ending September 30, we recognized a net benefit of approximately
$.7 million to the statement of income due to the closure of the 2003 federal
tax year and additional FIN 48 accruals including interest.
6.
|
Long-term
and Short-term Obligations
|
Short-term
debt
In
November 2005, we completed an unsecured uncommitted money market line of credit
(Line of Credit). Borrowings under the Line of Credit may be up to $30 million
for a maximum of 30 days. The Line of Credit may be terminated at any
time upon written notice by either us or the lender. At September 30, 2007
the
outstanding balance under this Line of Credit was $5 million. Interest on
amounts borrowed is charged at LIBOR plus a margin of approximately 1%. The
weighted average interest rate on outstanding borrowings on the Line of Credit
at September 30, 2007 was 6%.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
6.
|
Long-term
and Short-term Obligations
(Cont’d)
|
Long-term
debt
In
October 2006, we issued in a public offering $200 million of 8.25% senior
subordinated notes due 2016 (the Notes). The deferred costs of approximately
$5
million associated with the issuance of this debt are being amortized over
the
ten year life of the Notes.
In
April
2006, we completed a new unsecured five year bank credit facility 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 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. Effective May
2007 and in accordance with the existing Agreement, the bank syndicate agreed
to
increase the borrowing base by $50 million to $550 million. The outstanding
Line
of Credit reduces our borrowing capacity available under the
Agreement.
The
total
outstanding debt at September 30, 2007 under the credit facility and the
short-term Line of Credit was $235 million and $5 million, respectively, leaving
$310 million in borrowing capacity available. Interest on amounts borrowed
under
this debt 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. We are required under the Agreement to pay
an
annual commitment fee of .25% to .375% on the unused portion of the credit
facility.
The
Agreement contains restrictive covenants which, among other things, require
us
to maintain a certain debt to EBITDA ratio and a minimum current ratio, as
defined. The $200 million Notes are subordinated to our credit facility
indebtedness. Covenants of our Notes limit debt to the greater of $750 million
or 40% of Adjusted Consolidated Net Tangible Assets (as defined). Additionally,
as long as the interest coverage ratio (as defined) is met, we may incur
additional debt. We were in compliance with all such covenants as of September
30, 2007. The weighted average interest rate on the long-term outstanding
credit facility borrowings at September 30, 2007 was 6.5%.
7.
|
Contingencies
and Commitments
|
We
have
no accrued environmental liabilities for our sites, including sites in which
governmental agencies have designated us as a potentially responsible party,
because it is not probable that a loss will be incurred. 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 incurred. Management believes,
based upon current site assessments, that the ultimate resolution of any matters
will not result in substantial costs incurred. We are involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of
our
business. In the opinion of management, the resolution of these matters will
not
have a material effect on our financial position, or on the results of
operations or liquidity.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly Corporation (Holly) for a portion of our
Uinta basin crude oil. Under the agreement, Holly began purchasing 3,200 Bbl/D
beginning July 1, 2007. Upon completion of their Woods Cross refinery expansion
in Salt Lake City, which is expected in late 2008, Holly will increase total
purchased volumes to 5,000 Bbl/D through June 30, 2013. During the term of
the
contract, the minimum number of delivered units (“base daily volume”) is 3,200
Bbl/D increasing to 5,000 Bbl/D upon the certified completion of the refinery
upgrade. Holly may, but is not obligated to, purchase volumes in excess of
the
base daily volumes. Pricing under the contract, which includes transportation,
is a fixed percentage of WTI.
8.
|
Asset
Sales and Impairment
|
On
May
11, 2007, we sold our non-core West Montalvo assets in Ventura County,
California. The sale proceeds were approximately $61 million and we recognized
approximately $52 million pretax gain on the sale, including post closing
adjustments.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
8.
|
Asset
Sales and Impairment
(Cont’d)
|
During
the second quarter of 2007, we recorded a $2.9 million pretax charge to reduce
our carrying value of the Bakken asset in the Williston Basin, North Dakota
from
$9.9 million to $7 million. This asset was sold during the third quarter of
2007
for approximately its carrying value. In the third quarter of 2007, we also
recorded a $4.6 million pretax charge to reduce the carrying value of our
Tri-State unproved properties from $5.9 million to $1.3 million which we believe
approximates fair value as of September 30, 2007 based on available
information. We plan to sell a portion of our Tri-State acreage
during the fourth quarter of 2007 and have classified $.7 million as held for
sale at September 30, 2007 in accordance with SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets. Total impairment expense
for the nine months ended September 30, 2007 was $7.6 million.
On
October 22, 2007, we announced plans to form a master limited partnership (MLP)
and intend to proceed with an initial public offering of common units
representing limited partner interests in the MLP during the first half of
2008.
Approximately $125 million to $175 million of common units are expected to
be
offered to the public. We will own the general partner of the MLP and expect
to
retain a significant interest in the MLP at the close of the initial public
offering.
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
the
three and nine month periods ended September 30, 2007 and 2006 and our financial
condition, liquidity and capital resources as of September 30, 2007. 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.
Overview.
Our mission is to increase shareholder value 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.
·
|
Increased
production at North Midway-Sunset diatomite to an average 1,100 Bbl/D
in
the quarter through modification of our steam cycling practices and
well
fracturing techniques
|
·
|
Achieved
a record production at Poso Creek to an average 2,400 Bbl/D in the
quarter
|
·
|
Drilled
14 infill horizontal wells at South Midway-Sunset targeting oil pays
closer to the oil-water contact; performance is meeting
expectations
|
·
|
Accelerated
Pan Fee and Ethel D development by drilling 15 additional infill
wells
|
·
|
Accomplished
a 15 day drilling record on a Piceance mesa well as we are realizing
our
goal of reducing our drilling costs; we drilled 21 gross (7 net)
Piceance
wells
|
·
|
Completed
and tied into gathering systems 15 gross (8 net) Piceance basin operated
wells which increased Piceance net production to 11.5 MMcf/D, up
40% from
the second quarter 2007
|
Notable
Items and Expectations for the Remainder of 2007.
·
|
Companywide
production is projected to approximate 28,000 BOE/D in the fourth
quarter
of 2007 with a projected 2007 year end exit rate of 28,200
BOE/D
|
·
|
Drilling
the next 50 well expansion on our North Midway-Sunset diatomite asset;
this activity will continue into early 2008 and the projected 2007
year
end exit rate is 1,250 Bbl/D
|
·
|
Accelerating
Poso Creek infill drilling by an additional 13 wells and expected
2007
year end exit rate is 2,600 Bbl/D
|
·
|
Continuing
to focus on reducing drilling costs of our operated Piceance mesa
wells
and we expect to complete 12 gross (6 net) Piceance wells while targeting
fourth quarter average net production in Piceance of 15
MMcf/D
|
·
|
Proceeding
with plans as announced on forming a master limited
partnership
|
Results
of Operations. The following companywide
results are in millions (except per share data) for the three months
ended:
|
|
September
30, 2007
(3Q07)
|
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06 Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
Sales
of oil
|
|
$
|
100.1
|
|
$
|
97.9
|
2%
|
$
|
94.4
|
6%
|
Sales
of gas
|
|
|
18.6
|
|
|
18.3
|
2%
|
|
19.0
|
(2%)
|
Total
sales of oil and gas
|
|
$
|
118.7
|
|
$
|
116.2
|
2%
|
$
|
113.4
|
5%
|
Sales
of electricity
|
|
|
12.3
|
|
|
12.6
|
(2%)
|
|
13.9
|
(12%)
|
Gain
on sale of assets
|
|
|
1.4
|
|
|
-
|
n/a
|
|
50.4
|
(97%)
|
Interest
and other income, net
|
|
|
1.1
|
|
|
.6
|
83%
|
|
1.5
|
(27%)
|
Total
revenues and other income
|
|
$
|
133.5
|
|
$
|
129.4
|
3%
|
$
|
179.2
|
(26%)
|
Net
income
|
|
$
|
26.9
|
|
$
|
31.4
|
(14%)
|
$
|
52.0
|
(48%)
|
Net
income per share (diluted)
|
|
$
|
.60
|
|
$
|
.70
|
(14%)
|
$
|
1.16
|
(48%)
|
Our
revenues may vary significantly from period to period as a result of changes
in
commodity prices and/or production volumes. Our production for the
third quarter of 2007 averaged 26,873 BOE/D, which was up 2% from the third
quarter of 2006, and decreased 1% from the second quarter of 2007. Our average
production for the nine months ended September 30, 2007 was 26,525 BOE/D, which
was up 7% from the same period last year. Excluding the production impact of
the
West Montalvo assets sold in the second quarter, production in the third quarter
of 2007 increased slightly as compared to the second quarter of 2007. Based
on
the timing of actual production from our projects we are forecasting average
production of between 26,700 BOE/D and 27,000 BOE/D for the full year of
2007.
Crude
oil
sales in the three months ended September 30, 2007 were 6% higher than the
three
months ended June 30, 2007 resulting from price increases of 9%, offset by
production decreases of 3%. Gas sales in the three months ended September 30,
2007 were 2% lower than the three months ended June 30, 2007 resulting from
production increases of 6% partially offset by a price decline of 8%.
Similarly, crude oil sales and gas sales were 2% and 3% higher, respectively,
in
the nine months ended September 30, 2007 as compared to the nine months ended
September 30, 2006. Management estimates that for 2008, a $1.00 per MMBtu change
in NYMEX Henry Hub natural gas prices would result in a $3 million change in
annual net income, demonstrating our relative insensitivity to natural gas
prices companywide.
On
May
11, 2007, we sold our non-core West Montalvo assets in Ventura County,
California. The sale proceeds were approximately $61 million and we recognized
approximately $52 million pretax gain on the sale, including post closing
adjustments. During the second quarter of 2007, we recorded a $2.9 million
pretax charge to reduce our carrying value of the Bakken asset in the Williston
Basin, North Dakota from $9.9 million to $7 million. This asset was sold during
the third quarter of 2007 for approximately its carrying value. In the third
quarter of 2007, we also recorded a $4.6 million charge to reduce the carrying
value of our Tri-State unproved properties from $5.9 million to $1.3 million
which we believe approximates fair value as of September 30, 2007 based on
available information. We plan to sell a portion of our Tri-State
acreage during the fourth quarter of 2007 and have classified $.7 million as
held for sale at September 30, 2007 in accordance with SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. Total
impairment expense for the nine months ended September 30, 2007 was $7.6
million. In addition, during the second quarter we paid the third and final
installment of approximately $54 million for the North Parachute Ranch property
located in the Piceance basin.
Operating
data. The following table is for the three months
ended:
|
|
|
September
30, 2007
|
%
|
|
September
30, 2006
|
%
|
|
June
30, 2007
|
%
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
15,806
|
59
|
|
16,076
|
61
|
|
16,129
|
59
|
Light
Oil Production (Bbl/D)
|
|
|
3,675
|
14
|
|
4,118
|
16
|
|
4,034
|
15
|
Total
Oil Production (Bbl/D)
|
|
|
19,481
|
73
|
|
20,194
|
76
|
|
20,163
|
74
|
Natural
Gas Production (Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
Total
(BOE/D)
|
|
|
26,873
|
100
|
|
26,423
|
100
|
|
27,195
|
100
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
|
|
|
|
|
|
|
|
|
Average
sales price after hedging
|
|
|
47.93
|
|
|
47.28
|
|
|
45.43
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
75.15
|
|
$
|
70.54
|
|
$
|
65.02
|
|
Price
sensitive royalties
|
|
|
(5.50
|
)
|
|
(5.21
|
)
|
|
(4.20
|
)
|
Quality
differential and other
|
|
|
(9.56
|
)
|
|
(8.76
|
)
|
|
(9.24
|
)
|
Crude
oil hedges
|
|
|
(4.37
|
)
|
|
(3.99
|
)
|
|
(.52
|
)
|
Average
oil sales price after hedging
|
|
$
|
55.72
|
|
$
|
52.58
|
|
$
|
51.06
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
6.24
|
|
$
|
6.18
|
|
$
|
7.65
|
|
Conversion
to Mcf
|
|
|
.31
|
|
|
.31
|
|
|
.39
|
|
Natural
gas hedges
|
|
|
1.07
|
|
|
(.02
|
)
|
|
.71
|
|
Location,
quality differentials and other
|
|
|
(3.06
|
)
|
|
(1.36
|
)
|
|
(3.89
|
)
|
Average
gas sales price after hedging
|
|
$
|
4.56
|
|
$
|
5.11
|
|
$
|
4.86
|
|
The
following table is for the nine months ended:
|
|
|
September
30, 2007
|
%
|
|
September
30, 2006
|
%
|
|
|
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,019
|
60
|
|
15,681
|
63
|
|
|
|
Light
Oil Production (Bbl/D)
|
|
|
3,655
|
14
|
|
3,823
|
15
|
|
|
|
Total
Oil Production (Bbl/D)
|
|
|
19,674
|
74
|
|
19,504
|
78
|
|
|
|
Natural
Gas Production (Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
Total
(BOE/D)
|
|
|
26,525
|
100
|
|
24,896
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
|
|
|
|
|
|
|
|
|
Average
sales price after hedging
|
|
|
45.82
|
|
|
48.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
66.22
|
|
$
|
68.26
|
|
|
|
|
Price
sensitive royalties
|
|
|
(4.48
|
)
|
|
(5.41
|
)
|
|
|
|
Quality
differential and other
|
|
|
(9.26
|
)
|
|
(7.87
|
)
|
|
|
|
Crude
oil hedges
|
|
|
(1.61
|
)
|
|
(3.17
|
)
|
|
|
|
Average
oil sales price after hedging
|
|
$
|
50.87
|
|
$
|
51.81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
7.02
|
|
$
|
6.89
|
|
|
|
|
Conversion
to Mcf
|
|
|
.36
|
|
|
.34
|
|
|
|
|
Natural
gas hedges
|
|
|
.67
|
|
|
-
|
|
|
|
|
Location,
quality differentials and other
|
|
|
(2.85
|
)
|
|
(1.28
|
)
|
|
|
|
Average
gas sales price after hedging
|
|
$
|
5.20
|
|
$
|
5.95
|
|
|
|
|
|
Gas
Basis Differential. Natural gas prices in the Rockies
continue to be volatile due to various factors, including takeaway
pipeline capacity, supply volumes, and regional demand issues. We
expect
the basis differential between Henry Hub (HH) and Colorado Interstate
Gas
(CIG) to narrow upon the startup of the Rockies Express Pipeline
(REX)
which is anticipated in early 2008. We have contracted 10,000 MMBtu/D
on
this pipeline to provide firm transport for a portion of our Piceance
gas
production. The CIG basis differential per MMBtu, based upon
first-of-month values, averaged $3.55 below HH and ranged from $2.68
to
$4.37 below HH in the third quarter. Although related to CIG, the
actual
basin price varies. Gas from the Piceance basin was slightly below
the CIG
price while Uinta basin gas sold for approximately $.40 below CIG
pricing.
DJ Basin gas is priced using one of two indices. Approximately two-thirds
of the pricing of our DJ natural gas is tied to the Panhandle Eastern
Pipeline (PEPL) index and the remaining volumes to the CIG. For that
portion of the production with firm transportation on either the
Cheyenne
Plains Pipeline or the KMIGT pipeline, pricing is based upon the
PEPL
index which averaged approximately $.86 below the HH index before
the cost
of transportation is considered. The remainder of the DJ Basin gas
is sold
slightly above the CIG index price.
|
Oil
Contracts. Utah –Our Utah crude oil is paraffinic crude and can be
transported only a short distance before solidifying thus limiting the number
of
refineries for processing. We are currently able to secure short-term contracts
which, along with long-term contracts, allows us to produce at full capacity.
As
of September 30, 2007, our Utah light crude oil is sold under multiple long-term
and short-term contracts with different purchasers for varying prices. In some
cases the price is tied to field postings and in other contracts the price
is
based upon a percentage of the average NYMEX WTI prices. As operator we deliver
all produced volumes pursuant to these contracts.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly for a portion of our Uinta basin crude
oil.
Under the agreement, Holly began purchasing 3,200 Bbl/D beginning July 1, 2007.
Holly took delivery of approximately 1,000 Bbl/D and 1,500 Bbl/D in the first
and second quarters of 2007, respectively, which stabilized our realized sales
price and reduced our transportation costs. Upon completion of their Woods
Cross
refinery expansion in Salt Lake City, which is expected in late 2008, Holly
will
increase total purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing
under the contract, which includes transportation, is a fixed percentage of
WTI. This contract provides the pricing assurance we need to proceed
with the long-term development of our Uinta basin assets. We may adjust our
capital expenditures in the Uinta basin due to various factors, including the
timing of refinery demand for the Uinta basin barrels and the actual or expected
change in our realized price.
Hedging.
See Note 3 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 in California. Revenue and
operating costs for the three months ended September 30, 2007 were down from
the
three months ended September 30, 2006 and June 30, 2007 due to the decrease
in
electricity prices and the decrease in fuel gas cost. On September 20, 2007,
the
California Public Utilities Commission (CPUC) issued a decision (SRAC Decision)
that changes SRAC energy and capacity prices paid under Standard Offer (SO)
contracts prospectively, and authorizes California utilities to offer new
short-term and long-term SO contracts. This decision has been appealed at
the CPUC and may be subject to additional challenges and further clarification.
We do not believe that the proposed changes will materially effect us in
2007.
The
following table is for the three months ended:
|
|
|
September
30, 2007
|
|
|
September
30, 2006
|
|
|
June
30, 2007
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
12.3
|
|
$
|
12.6
|
|
$
|
13.9
|
|
Operating
costs (in millions)
|
|
|
9.8
|
|
|
11.2
|
|
|
11.1
|
|
Electric
power produced - MWh/D
|
|
|
2,257
|
|
|
2,100
|
|
|
2,060
|
|
Electric
power sold - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
4.84
|
|
$
|
6.14
|
|
$
|
6.46
|
|
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, 2007
|
|
September
30, 2006
|
|
June
30, 2007
|
|
September
30, 2007
|
|
September
30, 2006
|
|
June
30, 2007
|
|
Operating
costs – oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
3.78
|
|
|
3.87
|
|
|
3.90
|
|
|
9,333
|
|
|
9,419
|
|
|
9,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
30.49
|
|
$
|
27.27
|
|
$
|
31.47
|
|
$
|
75,354
|
|
$
|
66,336
|
|
$
|
77,888
|
|
Our
total
operating costs, production taxes, DD&A, G&A and interest expenses for
the three months ended September 30, 2007, stated on a unit-of-production basis,
increased 12% over the three months ended September 30, 2006 and decreased
3% as
compared to the three months ended June 30, 2007. The changes were primarily
related to the following items:
|
·
|
Operating
costs: Operating costs per BOE in the third quarter of 2007 were
8% higher
than the third quarter of 2006 primarily due to increases in contract
labor, well servicing, chemicals and compression and gathering costs,
partially offset by lower steam costs and used on-lease electricity
costs.
Operating costs per BOE were 5% lower in the third quarter of 2007
as
compared to the second quarter of 2007 due to lower steam costs and
used
on-lease electricity costs. The cost of our steam and
electricity used on-lease on our heavy oil properties in
California has decreased in the third quarter of 2007 due to lower
cost of
natural gas used as fuel, partially offset by a higher volume of
steam
injected. The following table presents steam
information:
|
|
September
30, 2007
(3Q07)
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06
Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
Average
volume of steam injected (Bbl/D)
|
88,711
|
86,556
|
2%
|
84,032
|
3%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
4.84
|
$
6.14
|
(21%)
|
$
6.46
|
(25%)
|
Based
on
current plans, we are targeting average steam injection of approximately 96,000
barrels of steam per day (BSPD) during the last quarter of 2007.
·
|
Production
taxes: Overall, our production taxes have decreased compared to 2006
due
to lower tax rates and lower assessed values for some of our oil
and
natural gas assets. Severance taxes, which are prevalent in Utah
and
Colorado, are directly related to the cost of the field sales price
of the
commodity. In California and Utah, our production is burdened with
ad
valorem taxes on proved reserves. Colorado has an ad valorem
tax which is based on field commodity prices. We expect
production taxes, in general, to correlate with the underlying commodity
price.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE were 28% higher in the three
months ended September 30, 2007 compared to the same period in the
prior
year due to an increase in capital spending over the last year and
particularly more extensive development in fields with higher drilling
costs and leasehold acquisition
costs.
|
·
|
General
and administrative: G&A per BOE decreased by 2% in the third quarter
of 2007 compared to the third quarter of 2006 due to higher production
in
2007. G&A per BOE was 3% lower in the third quarter of 2007 as
compared to the second quarter of 2007 due to lower compensation
related
costs and consulting expenses, partially offset by higher legal and
accounting expenses related to business development
activities.
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was approximately
$440 million at September 30, 2007 compared to approximately
$330 million and $475 million at September 30, 2006 and June 30,
2007, respectively. Our average borrowings increased since September
30,
2006 as a result of our capital expenditure program and due to payments
of
$153 million to purchase the North Parachute Ranch property located
in the
Piceance basin. Beginning in 2006, a certain portion of our interest
cost
related to our Piceance basin acquisition and joint venture has been
capitalized into the basis of the assets, and we anticipate a portion
will
continue to be capitalized until the remainder of our probable reserves
has been recategorized to proved developed reserves. For the quarter
ended
September 30, 2007, $4.8 million has been capitalized and we expect
to
capitalize approximately $18 million of interest cost during the
full year
of 2007.
|
Estimated
2007 and Actual Nine Months Ended September 30, 2007 and 2006 Oil and Gas
Operating, G&A and Interest Expenses.
|
|
Anticipated
range
|
|
Nine
months ended
|
|
Nine
months ended
|
|
|
|
In
2007 per
BOE
|
|
September
30, 2007
|
|
September
30, 2006
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
14.00
to 15.00
|
|
$
|
14.27
|
|
$
|
12.32
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
3.75
to 4.25
|
|
|
4.05
|
|
|
3.77
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
29.25
to 32.75
|
|
$
|
30.94
|
|
$
|
25.79
|
|
(1)
Assuming natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan
to
inject approximately 15% greater steam levels in 2007 compared to 2006
levels.
Our
total
operating costs, production taxes, DD&A, G&A and interest expenses for
the nine months ended September 30, 2007, stated on a unit-of-production basis,
increased 20% over the nine months ended September 30, 2006. The changes were
primarily related to the following items:
·
|
Operating
costs: Operating costs per BOE in the nine months ended September
30, 2007
were 16% higher than the comparable period in 2006 primarily due
to
approximately 15% greater steam levels in 2007 compared to 2006
levels.
|
·
|
Production
taxes: Overall, our production taxes have decreased slightly compared
to
2006 due to lower tax rates and lower assessed values for some of
our oil
and natural gas assets.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE were 30% higher in the nine
months ended September 30, 2007 compared to the same period in the
prior
year due to an increase in capital spending over the last year and
particularly more extensive development in fields with higher drilling
costs and leasehold acquisition
costs.
|
·
|
General
and administrative: G&A per BOE increased by 7% in the nine months
ended September 30, 2007 compared to the same period in the prior
year due
to additional staffing and higher overall compensation costs associated
with our growth activities.
|
·
|
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was approximately
$440 million at September 30, 2007 compared to approximately
$330 million at September 30, 2006, respectively. Our average
borrowings increased since September 30, 2006 primarily due to
acquisitions.
|
Estimated
2008 Capital Budget, Production Volume, and Oil and
Gas Operating, G&A and
Interest
Expenses. We are in the process of
determining our 2008 capital budget. Excluding any changes that may be impacted
by ongoing business development activities and ultimate realized commodity
prices, we are targeting our capital expenditures between $250 million and
$300
million. Our goal is to maintain our total capital expenditures (excluding
acquisitions) within our cash flow from operations, which is primarily
determined by our realized commodity sales prices and production volume. With
the implementation of this capital budget, we estimate our 2008 production
volume will range between 29,500 BOE/D and 31,000 BOE/D. Based on WTI of $60
and
NYMEX HH of $7.50 MMBtu, we expect our expenses to be within the following
ranges:
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2008 per BOE
|
|
|
|
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
15.50
to 16.50
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
1.50
to 2.00
|
|
|
|
|
|
|
|
DD&A
|
|
|
9.00
to 10.00
|
|
|
|
|
|
|
|
G&A
|
|
|
3.75
to 4.25
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
1.50
to 2.00
|
|
|
|
|
|
|
|
Total
|
|
$
|
31.25
to 34.75
|
|
|
|
|
|
|
|
(1)
We expect operating costs to increase in 2008 as compared to 2007 due to higher
projected natural gas costs.
Income
Taxes. See Note 5 to the unaudited condensed financial
statements. We estimate our effective tax rate of 38% to 39% will be similar
in
2007 as compared to 2006, and anticipate a similar effective tax rate in 2008.
We experienced an effective tax rate in the three months ended September 30,
2007 of 36%, which is in line with our projections. The decrease in the
effective tax rate for the third quarter 2007 was principally due to the closure
of certain tax issues for prior years. The effective tax rate was 39% for the
nine months ending September 30, 2006 and 2007. Our rate differs from a
statutory rate, primarily due to state income taxes. For the nine months
ending September 30, we recognized a net benefit of approximately $.7 million
to
the statement of income due to the closure of the 2003 federal tax year and
additional FIN 48 accruals including interest.
Development,
Exploitation and Exploration Activity. We drilled 99
gross (83 net) wells during the third quarter of 2007, realizing a success
rate
of 97 percent. Management is closely monitoring the capital development program
in relation to estimated cash flows and expects to expend capital of
approximately $275 million to $285 million, excluding acquisitions, during
2007.
As of September 30, 2007, we have five rigs drilling on our properties
under long-term contracts and have one more rig scheduled to begin in the fourth
quarter of 2007.
Drilling
Activity. The following table sets forth
certain information regarding drilling activities (including operated and
non-operated wells):
|
|
Three
months ended September 30, 2007
|
|
Nine
months ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
Midway-Sunset (including diatomite)
|
|
|
|
|
|
|
|
|
|
|
Socal
|
|
11
|
|
11
|
|
78
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
table above includes 3 gross wells
(2.5 net wells) and 7 gross wells (4.6 net wells) dry holes drilled in the
three
months and nine months ended September 30, 2007, respectively.
Production
We
have
six asset teams as follows: South Midway-Sunset, North Midway-Sunset (including
diatomite), Socal (including Poso Creek and Placerita), Piceance, Uinta and
DJ.
South
Midway-Sunset– During the three months ended September 30, 2007,
production averaged approximately 9,300 Bbl/D compared to approximately 10,900
Bbl/D and 9,700 Bbl/D during the three month periods ended September 30, 2006
and June 30, 2007, respectively. We completed ten horizontal infill wells during
the three months ended September 30, 2007 and we plan to drill one more
horizontal infill well in the fourth quarter. Increased production from these
activities is expected to slow the natural decline of these assets.
North
Midway-Sunset (including diatomite)– Our North Midway-Sunset
properties, including our diatomite project, are performing as expected. During
the three months ended September 30, 2007, production from the area averaged
approximately 2,100 Bbl/D up from approximately 1,100 Bbl/D and 2,100 Bbl/D
during the three month periods ended September 30, 2006 and June 30, 2007,
respectively.
Production
from the diatomite project has now improved to over 1,100 Bbl/D through
implementation of a modified steam injection plan and new well fracturing
techniques. We expect production to continue to increase as we have begun the
next 50-well development program in the fairway of the asset in the latter
part
of the third quarter. We will also begin installation of the
necessary infrastructure, including steam generation equipment and fluid
processing facilities.
Socal–
During the three months ended September 30, 2007, production averaged
approximately 4,300 Bbl/D up from approximately 3,400 Bbl/D and 4,000 Bbl/D
during the three month periods ended September 30, 2006 and June 30, 2007,
respectively.
Poso
Creek continues to respond favorably to steam flood injection and our
accelerated infill drilling program is performing solidly above plan. Production
has increased to over 2,400 Bbl/D from less than 1,000 Bbl/D in the same period
last year. This year we accelerated development of the asset by drilling over
70
wells to expand our thermally enhanced project and installed a third steam
generator. We expect continued production improvement as these wells are
cyclically steamed, the additional steam flood patterns are brought on line
and
the balance of the infill wells are drilled and completed.
Piceance –
During the third quarter, production from the Piceance averaged 11.5 MMcf/D,
an
increase of 40% over the second quarter. On the Berry operated wells, we
completed 15 gross wells (8 net). An additional 12 wells (6 net) are forecasted
to be drilled and connected by the end of the fourth quarter, and we anticipate
production will approximate 15 MMcf/D for the fourth quarter of
2007.
We
are
currently running a three rig program and we expect to return to a four rig
program as we high grade our rig fleet with the addition of another “fit for
purpose” Piceance drilling rig. Significant progress was made in the
third quarter in lowering the days required to drill wells on our Piceance
asset. During the quarter our mesa wells drilled in the Piceance
averaged 21 days from spud date to rig release with our most efficient well
drilled at 15 days. We are targeting drilling days for our mesa locations at
Garden Gulch to be 17 days and 25 days at North Parachute Ranch. We are
confident that we can maintain this efficiency and expect improved economics
as
a result. We continue to expand the infrastructure needed to support our
operations. We are pursuing opportunities to acquire additional firm
transportation for future sales out of this region.
Uinta
–
Our 2007 capital is directed at additional Brundage Canyon 40-acre
development wells, drilling the Ashley Forest extension to the south of Brundage
Canyon, continued Lake Canyon assessment and drilling 20-acre infill wells
in
Brundage Canyon. During the third quarter, we drilled eight net wells in
Brundage Canyon. Average daily production during the third quarter from all
Uinta basin assets was approximately 5,900 net BOE/D. We continue to have one
drilling rig operating in the basin. Our current oil marketing arrangements
provide us the ability to sell all of our crude oil production in the Uinta
basin.
Our
fourth quarter drilling activity will focus on continued efforts to extend
Brundage Canyon success south into the Ashley Forest and continue our assessment
of Lake Canyon potential to the west of Brundage. In support of our
plans, we have 15 approved drilling permits and a four well drilling commitment
in Lake Canyon along with six approved permits in the Ashley
Forest. Two Ashley Forest wells that were drilled in the second
quarter of 2007 and five wells drilled in the third quarter of 2007 are
providing encouraging initial oil production results.
DJ–
Our third quarter
activity in the DJ basin has focused on drilling 30 successful Niobrara
development wells in Yuma County, Colorado. Average daily production
in the DJ for the third quarter was 18.9 net MMcf/D. Berry’s Yuma
County Niobrara projects provide sustainable and steady cash flow resulting
from
low capital development costs, modest production declines and long-life
reserves.
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 exploitation 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
senior unsecured revolving credit facility to increase our maximum credit amount
under the facility to $750 million and increased our current borrowing base
to $500 million. In the second quarter of 2007, we increased our current
borrowing base to $550 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 $145 million.
As
of
September 30, 2007, we had total borrowings under the senior unsecured revolving
credit facility and senior unsecured money market line of credit of
$240 million and $200 million under our senior subordinated ten year
notes.
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. Acquisitions are typically debt
financed. We may revise our capital budget during the year as a result of
acquisitions, drilling outcomes and/or changes in commodity prices that
influence our decision to change capital expenditures to closely match operating
cash flows. Excess cash generated from operations is expected to be applied
toward capital expenditures, debt reduction or other corporate
purposes.
Management
is closely monitoring the capital development program in relation to estimated
cash flows and expects to expend capital of approximately $275 million to $285
million, excluding acquisitions, during 2007. The capital development program
may be revised due to realized commodity prices and price expectations,
equipment availability, permitting and/or changes in our internal development
plans. Our 2007 expenditures are directed toward developing reserves, increasing
oil and gas production and exploitation opportunities. For 2007, we plan to
invest up to approximately 66% in our Rocky Mountain assets and 34% in our
California assets. Capital expenditures, excluding property acquisitions,
totaled $58.6 million and $209.2 million during the three months and the
nine months ended September 30, 2007, respectively.
On
May
11, 2007, we sold our non-core West Montalvo assets in Ventura County,
California. The sale proceeds were approximately $61 million and we recognized
approximately $52 million pretax gain on the sale, including post closing
adjustments and we transferred the properties in the second quarter of 2007.
Production from the property was approximately 700 BOE/D, which is less than
3%
of current production and, as of December 31, 2006, the property had 7 million
BOE of proved reserves which is less than 5% of the 2006 year end total of
150
million BOE. In
addition, during the second quarter we paid the third and final installment
of
approximately $54 million for the North Parachute Ranch property located in
the
Piceance basin.
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. Crude oil and gas sales in
the
three months ended September 30, 2007 were 5% higher than the three months
ended
June 30, 2007 resulting from an 9% increase in oil price (see graphs on page
13)
and an 8% decrease in gas price (see graphs on page 13), partially offset
by production declines in both oil and gas.
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 senior unsecured revolving 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 (in millions, except for production and average
prices):
|
September
30, 2007
(3Q07)
|
September
30, 2006
(3Q06)
|
3Q07
to 3Q06
Change
|
June
30, 2007
(2Q07)
|
3Q07
to 2Q07
Change
|
Average
production (BOE/D)
|
26,873
|
26,423
|
2%
|
27,195
|
(1%)
|
Average
oil and gas sales prices, per BOE after hedging
|
$
47.93
|
$
47.28
|
1%
|
$
45.43
|
5%
|
Net
cash provided by operating activities
|
$
93
|
$
101
|
(8%)
|
$
80
|
16%
|
Working
capital
|
$
(91)
|
$
(175)
|
(48%)
|
$
(49)
|
86%
|
Sales
of oil and gas
|
$
119
|
$
116
|
3%
|
$
113
|
5%
|
Total
debt
|
$
440
|
$
330
|
32%
|
$
475
|
(8%)
|
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
$
63
|
$
148
|
(60%)
|
$
131
|
(55%)
|
Dividends
paid
|
$
3.4
|
$
4.2
|
(19%)
|
$
3.4
|
-%
|
Contractual
Obligations. Our contractual obligations as
of September 30, 2007 are as follows (in millions):
|
|
|
Total
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
Total
debt and interest
|
|
$
|
673.5
|
$
|
36.6
|
$
|
31.8
|
$
|
31.8
|
$
|
31.8
|
$
|
259.1
|
$
|
282.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
lease obligations
|
|
|
12.8
|
|
.4
|
|
1.7
|
|
1.4
|
|
1.4
|
|
1.4
|
|
6.5
|
Drilling
and rig obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
878.7
|
$
|
48.5
|
$
|
72.6
|
$
|
85.5
|
$
|
49.8
|
$
|
270.2
|
$
|
352.1
|
Total
debt and interest - Our credit facility borrowings and related interest
of approximately 6.5% can be paid before its maturity date without significant
penalty. Our 8.25% senior subordinated notes mature in November 2016, but are
not redeemable until November 1, 2011 and are not redeemable without any premium
until November 1, 2014. Our Line of Credit has related interest of
6%.
Operating
leases - We lease corporate and field offices in California, Colorado
and Texas. We lease an airplane for business travel under a ten year operating
lease beginning December 2006.
Drilling
obligation - We intend to participate in the drilling of over 16 wells on
our Lake Canyon prospect over the four year contract, which began in 2006.
Our
minimum expenditure obligation under our exploration and development agreement
is $9.6 million. Also included above, under our June 2006 joint venture
agreement in the Piceance basin, we must drill 120 wells by 2010 to avoid
penalties of $.2 million per well or a maximum 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 for
California operations. This 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 transportation contracts which
provide us with physical access to interstate pipelines to move gas from our
producing areas to markets.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly for a portion of our Uinta basin crude
oil.
Under the agreement, Holly began purchasing 3,200 Bbl/D beginning July 1, 2007.
Upon completion of their Woods Cross refinery expansion in Salt Lake City,
which
is expected in late 2008, Holly will increase their total purchased volumes
to
5,000 Bbl/D through June 30, 2013. During the term of the contract, the minimum
number of delivered units (“base daily volume”) is 3,200 Bbl/D increasing to
5,000 Bbl/D upon the certified completion of the refinery upgrade. Holly may,
but is not obligated to, purchase volumes in excess of the base daily volumes
upon proper notification by us.
|
Item
3.
Quantitative
and Qualitative
Disclosures About Market
Risk
|
As
discussed in Note 3 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 any
commodity price increases. In California, we benefit from lower natural gas
pricing as we are a consumer of natural gas in our operations 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 and/or basis adjustments or other price
protection is appropriate in accordance with policy established by our board
of
directors.
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 CIG and Questar index prices, respectively.
The
following table summarizes our hedge position as of September 30,
2007:
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Floor/Ceiling
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Prices
|
Crude
Oil Sales
(NYMEX
WTI)
|
|
|
|
|
|
Natural
Gas Sales
(NYMEX
HH)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,000
|
|
$70.00
/ $75.85
|
|
|
|
15,000
|
|
$8.00
/ $11.39
|
|
|
8,000
|
|
$47.50
/ $70.00
|
|
|
|
|
|
$8.00
/ $15.65
|
|
|
|
|
|
|
|
|
17,000
|
|
$7.50
/ $8.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,000
|
|
$47.50
/ $70.00
|
|
4th
Quarter
2008
|
|
21,000
|
|
$8.00
/ $9.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO CIG)
|
|
|
|
|
|
|
|
|
|
|
Basis
Swaps
|
|
|
|
Price
|
|
|
|
|
|
|
October
2007
|
|
15,000
|
|
$1.63
|
|
|
|
|
|
|
November
& December 2007
|
|
15,000
|
|
$1.71
|
|
|
|
|
|
|
|
|
|
|
$1.74
|
|
|
240
|
|
$71.50
|
|
|
|
17,000
|
|
$1.43
|
|
|
|
|
|
|
|
|
|
|
$1.40
|
|
|
|
|
|
|
4th
Quarter
2008
|
|
21,000
|
|
$1.46
|
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below our floor prices which
range from $47.50 to $70.00 per barrel while still participating in any oil
price increase up to the ceiling prices which range from $70.00 to $83.10 per
barrel on the volumes indicated above, and if 2) gas prices, including our
basis swaps, decline below our floor prices which range from $6.07 to $6.26
per
MMBtu while still participating in any gas price increase, including our basis
differentials, up to the ceiling prices, which range from $6.97 to $13.91 per
MMBtu on the respective volumes. 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, including certain basis differentials. 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 our senior unsecured revolving credit
facility.
While
we
have designated our hedges as cash flow hedges in accordance with SFAS
No. 133, Accounting for Derivative Instruments and Hedging
Activities, it is possible that a portion of the hedge related to the
movement in the WTI to California heavy crude oil price differential may be
determined to be ineffective. Likewise, we may have some ineffectiveness in
our
natural gas hedges due to the movement of HH pricing as compared to actual
sales
points. If this occurs, the ineffective portion will directly impact net income
rather than being reported as Other Comprehensive Income (Loss). If the
differential were to change significantly, it is possible that our hedges,
when
marked-to-market, could have a material impact on earnings in any given quarter
and, thus, add increased volatility to our net income. The marked-to-market
values reflect the liquidation values of such hedges and not necessarily the
values of the hedges if they are held to maturity.
We
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 we recognized
an
unrealized net loss of approximately $4.8 million on the income statement under
the caption “Commodity derivatives.” We 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 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.
The
related cash flow impact of all of our derivative activities are reflected
as
cash flows from operating activities. Irrespective of the unrealized gains
reflected in Other Comprehensive Income (Loss), the ultimate impact to net
income over the life of the hedges will reflect the actual settlement values.
All of these hedges have historically been deemed to be cash flow hedges with
the marked-to-market valuations provided by external sources, based on prices
that are actually quoted.
Based
on average NYMEX
futures prices as of September 30,
2007,
(WTI $74.79;
HH $7.76)
for the term of our hedges we would expect to
make pretax 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, 2007
|
|
|
on
pretax future cash (payments) and receipts
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Futures Price (2007 – 2010)
|
|
$
|
74.79
|
|
$
|
59.83
|
|
$
|
67.31
|
|
$
|
82.27
|
|
$
|
89.74
|
|
Average
HH Futures Price (2007 – 2008)
|
|
|
7.76
|
|
|
6.21
|
|
|
6.99
|
|
|
8.54
|
|
|
9.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$
|
(53.2
|
)
|
$
|
12.2
|
|
$
|
(4.3
|
)
|
$
|
(127.1
|
)
|
$
|
(214.7
|
)
|
Natural
Gas gain/(loss) (in millions)
|
|
|
4.4
|
|
|
15.4
|
|
|
9.2
|
|
|
3.3
|
|
|
(.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions)
based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
(WTI $80.59; HH $7.00)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
(WTI $76.94; HH $7.95)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13.9
|
)
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
2010
(WTI $72.23)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
Total
|
|
$
|
(48.8
|
)
|
$
|
|
|
$
|
|
|
$
|
|
)
|
$
|
|
)
|
Interest
Rates. Our
exposure to changes in interest rates results primarily from long-term debt.
On
October 24, 2006, we issued $200 million of 8.25% senior subordinated notes
due
2016 in a public offering. Total long-term debt outstanding including our
short-term Line of Credit, at September 30, 2007 was $440 million. Interest
on amounts borrowed under our revolving credit facility is charged at LIBOR
plus
1.0% to 1.75%, with the exception of the $100 million of principal for which
we
have hedged the interest rate at approximately 5.5% plus the senior unsecured
revolving credit facility’s margin through June 30, 2011. Based on September 30,
2007 credit facility borrowings, a 1% change in interest rates would have an
annual $.9 million after tax impact on our financial statements.
|
Item
4. Controls and
Procedures
|
As
of
September 30, 2007, we have carried out an evaluation under the supervision
of,
and with the participation of management, including our 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 Exchange Act of 1934, as amended.
Based
on
their evaluation as of September 30, 2007, our 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 “plan,” “will,”
“intend,” “continue,” “target(s),” “expect,” “achieve,” “future,” “may,”
“could,” “goal(s),”, “forecast,” “anticipate,” 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 including that the master limited partnership will not be
formed, will not complete an offering of securities and will not complete such
actions on the timetable indicated. 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 15 of our Form 10-K filed with the
Securities and Exchange Commission, under the heading “Risk Factors” and all
material changes are updated in Part II, Item 1A within this 10-Q.
|
PART
II. OTHER INFORMATION
|
|
Item
1. Legal
Proceedings
|
None.
None.
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.
Exhibit
No. Description
of Exhibit
31.1 Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of
2002.
31.2 Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
of
2002.
32.1
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as
adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
32.2
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as
adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
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/
Shawn
M. Canaday
Shawn
M.
Canaday
Controller
(Principal
Accounting Officer)
Date: October
31, 2007