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, 2008
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)
|
|
1999
Broadway, Suite 3700
Denver,
Colorado 80202
(Address
of principal executive offices, including zip code)
Registrant's telephone number,
including area
code: (303) 999-4400
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, a non-accelerated filer, or a smaller reporting company. See
definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filerx Accelerated
filero Non-accelerated
filero Smaller
reporting companyo
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 20, 2008, the registrant had 42,738,091 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 20, 2008 all of which is held by
an affiliate of the registrant.
BERRY PETROLEUM
COMPANY
THIRD
QUARTER 2008 FORM 10-Q
TABLE
OF CONTENTS
PART
I. FINANCIAL INFORMATION
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Page
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Item
1. Financial Statements
|
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3 |
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Unaudited
Condensed Balance Sheets at September 30, 2008 and December 31,
2007
|
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|
3 |
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended September
30, 2008 and 2007
|
|
|
4 |
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Nine Month Periods Ended September
30, 2008 and 2007
|
|
|
5 |
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Cash Flows for the Nine Month Periods Ended
September 30, 2008 and 2007
|
|
|
6 |
|
|
|
|
|
|
|
|
Notes
to Unaudited Condensed Financial Statements
|
|
|
7 |
|
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|
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|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
|
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15 |
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|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
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27 |
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Item
4. Controls and Procedures
|
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30 |
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PART
II.
OTHER
INFORMATION
|
|
|
|
|
|
|
|
|
|
|
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|
Item
1. Legal Proceedings
|
|
|
30 |
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|
|
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Item
1A. Risk Factors
|
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|
30 |
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|
|
|
|
|
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
|
|
30 |
|
|
|
|
|
|
|
|
Item
3. Defaults Upon Senior Securities
|
|
|
30 |
|
|
|
|
|
|
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Item
4. Submission of Matters to a Vote of Security Holders
|
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30 |
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Item
5. Other Information
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30 |
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|
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Item
6. Exhibits
|
|
|
31 |
|
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
ASSETS
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
59 |
|
|
$ |
316 |
|
|
|
|
65 |
|
|
|
58 |
|
Accounts
receivable
|
|
|
145,701 |
|
|
|
117,038 |
|
|
|
|
38,987 |
|
|
|
28,547 |
|
Fair
value of derivatives
|
|
|
2,198 |
|
|
|
2,109 |
|
|
|
|
- |
|
|
|
1,394 |
|
Prepaid
expenses and other
|
|
|
19,432 |
|
|
|
11,557 |
|
Total
current assets
|
|
|
206,442 |
|
|
|
161,019 |
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
2,196,322 |
|
|
|
1,275,091 |
|
Other
assets
|
|
|
17,307 |
|
|
|
15,996 |
|
|
|
$ |
2,420,071 |
|
|
$ |
1,452,106 |
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
150,750 |
|
|
$ |
90,354 |
|
Revenue
and royalties payable
|
|
|
35,779 |
|
|
|
47,181 |
|
Accrued
liabilities
|
|
|
37,284 |
|
|
|
21,653 |
|
|
|
|
19,300 |
|
|
|
14,300 |
|
|
|
|
380 |
|
|
|
2,591 |
|
Fair
value of derivatives
|
|
|
110,427 |
|
|
|
95,290 |
|
Total
current liabilities
|
|
|
353,920 |
|
|
|
271,369 |
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
206,848 |
|
|
|
128,824 |
|
|
|
|
1,109,300 |
|
|
|
445,000 |
|
Abandonment
obligation
|
|
|
40,414 |
|
|
|
36,426 |
|
|
|
|
- |
|
|
|
398 |
|
Other
long-term liabilities
|
|
|
6,226 |
|
|
|
1,657 |
|
Fair
value of derivatives
|
|
|
106,459 |
|
|
|
108,458 |
|
|
|
|
1,469,247 |
|
|
|
720,763 |
|
|
|
|
|
|
|
|
|
|
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; 42,737,029 shares issued
and outstanding (42,583,002 in 2007)
|
|
|
427 |
|
|
|
425 |
|
Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares issued
and outstanding (liquidation preference of $899) (1,797,784 in
2007)
|
|
|
18 |
|
|
|
18 |
|
Capital
in excess of par value
|
|
|
77,739 |
|
|
|
66,590 |
|
Accumulated
other comprehensive loss
|
|
|
(130,361
|
) |
|
|
(120,704
|
) |
|
|
|
649,081 |
|
|
|
513,645 |
|
Total
shareholders' equity
|
|
|
596,904 |
|
|
|
459,974 |
|
|
|
$ |
2,420,071 |
|
|
$ |
1,452,106 |
|
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, 2008 and 2007
(In
Thousands, Except Per Share Data)
|
|
Three
months ended September 30,
|
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
|
$ |
207,863 |
|
|
$ |
118,733 |
|
|
|
|
|
18,317 |
|
|
|
12,241 |
|
|
|
|
|
13,284 |
|
|
|
- |
|
|
|
|
|
95 |
|
|
|
1,418 |
|
|
Interest
and other income, net
|
|
|
1,202 |
|
|
|
1,108 |
|
|
|
|
|
240,761 |
|
|
|
133,500 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
56,038 |
|
|
|
33,995 |
|
|
Operating
costs - electricity generation
|
|
|
13,706 |
|
|
|
9,760 |
|
|
Production
taxes
|
|
|
9,673 |
|
|
|
4,344 |
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
40,440 |
|
|
|
23,356 |
|
|
Depreciation,
depletion & amortization - electricity
generation
|
|
|
646 |
|
|
|
938 |
|
|
Gas
marketing
|
|
|
12,034 |
|
|
|
- |
|
|
General
and administrative
|
|
|
14,524 |
|
|
|
9,333 |
|
|
|
|
|
8,755 |
|
|
|
4,326 |
|
|
Commodity
derivatives
|
|
|
(594
|
) |
|
|
- |
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
1,571 |
|
|
|
5,175 |
|
|
|
|
|
156,793 |
|
|
|
91,227 |
|
|
Income
before income taxes
|
|
|
83,968 |
|
|
|
42,273 |
|
|
Provision
for income taxes
|
|
|
30,620 |
|
|
|
15,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
53,348 |
|
|
$ |
26,855 |
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
$ |
1.20 |
|
|
$ |
.61 |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
$ |
1.17 |
|
|
$ |
.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
.075 |
|
|
$ |
.075 |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
44,527 |
|
|
|
44,112 |
|
|
Equity
based compensation
|
|
|
886 |
|
|
|
772 |
|
|
Director
deferred compensation
|
|
|
128 |
|
|
|
118 |
|
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share
|
|
|
45,541 |
|
|
|
45,002 |
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
|
Three
Month Periods Ended September 30, 2008 and 2007
|
(In
Thousands)
|
|
|
$ |
53,348 |
|
|
$ |
26,855 |
|
|
Unrealized
gains (losses) on derivatives, net of income taxes (benefits) of $144,881
and ($7,027), respectively
|
|
|
225,693 |
|
|
|
(10,541 |
|
|
Reclassification
of realized gains on derivatives included in net income, net of income
taxes of $18,745 and $1,411, respectively
|
|
|
30,584 |
|
|
|
2,116 |
|
|
|
|
$ |
309,625 |
|
|
$ |
18,430 |
|
|
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, 2008 and 2007
(In
Thousands, Except Per Share Data)
|
|
Nine
months ended September 30,
|
|
|
|
|
|
REVENUES
AND OTHER INCOME ITEMS
|
|
|
|
|
|
|
$ |
557,689 |
|
$ |
333,933 |
|
|
|
|
51,223 |
|
|
40,704 |
|
|
|
|
28,046 |
|
|
- |
|
|
|
|
510 |
|
|
51,816 |
|
Interest
and other income, net
|
|
|
4,095 |
|
|
3,754 |
|
|
|
|
641,563 |
|
|
430,207 |
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
152,852 |
|
|
103,330 |
|
Operating
costs - electricity generation
|
|
|
45,620 |
|
|
35,014 |
|
Production
taxes
|
|
|
23,121 |
|
|
12,297 |
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
96,588 |
|
|
65,478 |
|
Depreciation,
depletion & amortization - electricity
generation
|
|
|
1,991 |
|
|
2,661 |
|
Gas
marketing
|
|
|
26,087 |
|
|
- |
|
General
and administrative
|
|
|
37,067 |
|
|
29,291 |
|
|
|
|
16,444 |
|
|
13,593 |
|
Commodity
derivatives
|
|
|
172 |
|
|
- |
|
Dry
hole, abandonment, impairment and exploration
|
|
|
9,162 |
|
|
9,342 |
|
|
|
|
409,104 |
|
|
271,006 |
|
Income
before income taxes
|
|
|
232,459 |
|
|
159,201 |
|
Provision
for income taxes
|
|
|
86,939 |
|
|
61,534 |
|
|
|
|
|
|
|
|
|
|
|
$ |
145,520 |
|
$ |
97,667 |
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
$ |
3.27 |
|
$ |
2.22 |
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
$ |
3.20 |
|
$ |
2.18 |
|
|
|
|
|
|
|
|
|
|
|
$ |
.225 |
|
$ |
.225 |
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
|
|
|
44,466 |
|
|
44,020 |
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
914 |
|
|
701 |
|
Director
deferred compensation
|
|
|
126 |
|
|
115 |
|
Weighted
average number of shares of capital stock used to calculate diluted net
income per share
|
|
|
45,506 |
|
|
44,836 |
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
Nine
Month Periods Ended September 30, 2008 and 2007
|
(In
Thousands)
|
|
|
$ |
145,520 |
|
$ |
97,667 |
|
Unrealized
losses on derivatives, net of income tax benefits of $58,260 and $19,484,
respectively
|
|
|
(95,055 |
) |
|
(29,226 |
|
Reclassification
of realized gains on derivatives included in net income, net of income
taxes of $52,341 and $529, respectively
|
|
|
85,399 |
|
|
793 |
|
|
|
$ |
135,864 |
|
$ |
69,234 |
|
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, 2008 and 2007
(In
Thousands)
|
|
Nine
months ended September 30,
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
$ |
145,520 |
|
|
$ |
97,667 |
|
Depreciation,
depletion and amortization
|
|
|
98,579 |
|
|
|
68,139 |
|
Dry
hole and impairment
|
|
|
6,858 |
|
|
|
8,725 |
|
|
|
|
(180
|
) |
|
|
804 |
|
Stock-based
compensation expense
|
|
|
6,653 |
|
|
|
5,437 |
|
Deferred
income taxes
|
|
|
76,502 |
|
|
|
53,162 |
|
Unrealized
loss on ineffective hedges
|
|
|
172 |
|
|
|
- |
|
Gain
on sale of oil and gas properties
|
|
|
(510
|
) |
|
|
(51,816
|
) |
Other,
net
|
|
|
(1,500
|
) |
|
|
750 |
|
|
|
|
3,935 |
|
|
|
(2,995
|
) |
Cash
paid for abandonment
|
|
|
(3,957
|
) |
|
|
(660
|
) |
Increase
in current assets other than cash and cash
equivalents
|
|
|
(35,361
|
) |
|
|
(10,785
|
) |
Increase
in current liabilities other than book overdraft, line of credit and fair
value of derivatives
|
|
|
34,537 |
|
|
|
13,116 |
|
Net
cash provided by operating activities
|
|
|
331,248 |
|
|
|
181,544 |
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
|
(302,266
|
) |
|
|
(206,240
|
) |
Property
acquisitions
|
|
|
(667,030
|
) |
|
|
(56,167
|
) |
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
(4,146
|
) |
|
|
(2,944
|
) |
Proceeds
from sale of assets
|
|
|
2,038 |
|
|
|
68,432 |
|
|
|
|
(15,461
|
) |
|
|
(13,160
|
) |
Net
cash used in investing activities
|
|
|
(986,865
|
) |
|
|
(210,079
|
) |
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
Proceeds
from issuances on line of credit
|
|
|
308,000 |
|
|
|
285,150 |
|
Payments
on line of credit
|
|
|
(303,000
|
) |
|
|
(296,650
|
) |
Proceeds
from issuance of long-term debt
|
|
|
1,481,300 |
|
|
|
179,300 |
|
Payments
on long-term debt
|
|
|
(817,000
|
) |
|
|
(134,300
|
) |
Debt
issuance cost
|
|
|
(8,353
|
) |
|
|
- |
|
Dividends
paid
|
|
|
(10,084
|
) |
|
|
(10,036
|
) |
Proceeds
from stock option exercises
|
|
|
2,834 |
|
|
|
3,051 |
|
Excess
tax benefit and other
|
|
|
1,663 |
|
|
|
1,795 |
|
Net
cash provided by financing activities
|
|
|
655,360 |
|
|
|
28,310 |
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
(257
|
) |
|
|
(225
|
) |
Cash
and cash equivalents at beginning of year
|
|
|
316 |
|
|
|
416 |
|
Cash
and cash equivalents at end of period
|
|
$ |
59 |
|
|
$ |
191 |
|
|
|
|
|
|
|
|
|
|
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, 2008 and December 31, 2007 and results of operations and
comprehensive (loss) income and cash flows for the three month and nine month
periods ended September 30, 2008 and 2007 have been included. All such
adjustments, except as described below, 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, 2007 financial statements. The December 31, 2007 Form 10-K/A
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, 2008 and
December 31, 2007 is $11.7 million and $7.8 million, respectively, representing
outstanding checks in excess of the bank balance (book overdraft).
Certain
reclassifications have been made to prior period financial statements to conform
them to the current year presentation. Specifically, the change in book
overdraft line in the Statements of Cash Flows is classified as an operating
activity to reflect the use of these funds in operations, rather than their
prior year classification as a financing activity.
In March
2008, we determined there was an error in computing royalties payable in prior
years, accumulating to $10.5 million as of December 31, 2007. We concluded the
error was not material to any individual prior interim or annual period (or to
the projected earnings for 2008) and, therefore, the error was corrected during
the first quarter of 2008, with the effect of increasing our sales of oil and
gas by $10.5 million and reducing our royalties payable.
The price
sensitive royalty that burdens our Formax property in the South Midway Sunset
field has changed. We previously paid a royalty equal to 75% of the
amount of the heavy oil posted above a price of $16.11. This price
escalates at 2% annually. Effective January 1, 2008, the royalty rate
is reduced from 75% to 53% as long as we maintain a minimum steam injection
level, which we expect to meet, that reduces over time. Current net
production from this property is approximately 2,300 Bbl/D.
2.
|
Recent Accounting
Developments
|
In
September 2008, the Financial Accounting Standards Board (FASB) issued FASB
Staff Positions (FSP) No. 133-1 and FIN 45-4 to amend FASB Statement No. 133,
Accounting for Derivative
Instruments and Hedging Activities, to require disclosures by sellers of
credit derivatives, including credit derivatives embedded in a hybrid
instrument. This FSP also amends FASB Interpretation No.45,
Guarantor’s Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others, to require an additional disclosure about the
current status of the payment/performance risk of a
guarantee. Further, this FSP clarifies the FASB’s intent about the
effective date of FASB Statement No. 161, Disclosures about Derivative
Instruments and Hedging Activities. We do not expect the
adoption of this FSP to have a material effect on our financial statements and
related disclosures. This FSP is effective for financial statements issued for
reporting periods (annual or interim) ending after November 15, 2008, with early
application encouraged.
In
December 2007, the FASB issued Statement of Financial Accounting Standard (SFAS)
No. 160, Noncontrolling
Interests in Consolidated Financial Statements. SFAS 160 was issued to
establish accounting and reporting standards for the noncontrolling interest in
a subsidiary (formerly called minority interests) and for the deconsolidation of
a subsidiary. We do not expect the adoption of SFAS 160 to have a material
effect on our financial statements and related disclosures. The effective date
of this Statement is for
fiscal years, and interim periods within those fiscal years, beginning on or
after December 15, 2008.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
In
December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which
expands the information that a reporting entity provides in its financial
reports about a business combination and its effects. This Statement establishes
principles and requirements for how the acquirer recognizes and measures in its
financial statements the identifiable assets acquired, the liabilities assumed,
and any non controlling interest in the acquiree, recognizes and measures the
goodwill acquired in the business combination or a gain from a bargain purchase,
and determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination. This Statement applies prospectively to business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. An entity may not
apply the principle before that date. We may experience a financial statement
impact depending on the nature and extent of any new business combinations
entered into after the effective date of SFAS No. 141(R).
In March
2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—an amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Expanded disclosures are required to provide information
about (a) how and why an entity uses derivative instruments, (b) how derivative
instruments and related hedged items are accounted for under Statement 133 and
its related interpretations, and (c) how derivative instruments and related
hedged items affect an entity’s financial position, financial performance, and
cash flows. This Statement is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
application encouraged. This Statement will require us to provide the additional
disclosures described above.
In May
2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, which identifies the sources of accounting
principles and the framework for selecting the principles used in the
preparation of financial statements of nongovernmental entities that are
presented in conformity with generally accepted accounting principles (GAAP) in
the United States of America (the GAAP hierarchy). This Statement is
effective 60 days following the SEC’s approval of the Public Company Accounting
Oversight Board amendments to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles, which has not
yet occurred. We do not expect
the adoption of SFAS 162 to have a material effect on our financial statements
or related disclosures.
3.
|
Fair
Value Measurement
|
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.
We adopted this Statement as of January 1, 2008.
Determination
of fair value
We have
established and documented a process for determining fair values. Fair value is
based upon quoted market prices, where available. We have various controls in
place to ensure that valuations are appropriate. These controls
include: identification of the inputs to the fair value methodology through
review of counterparty statements and other supporting documentation,
determination of the validity of the source of the inputs, corroboration of the
original source of inputs through access to multiple quotes, if available, or
other information and monitoring changes in valuation methods and assumptions.
The methods described above may produce a fair value calculation that may not be
indicative of future fair values. Furthermore, while we believe these valuation
methods are appropriate and consistent with that used by other market
participants, the use of different methodologies, or assumptions, to determine
the fair value of certain financial instruments could result in a different
estimate of fair value.
Valuation
hierarchy
SFAS 157
establishes a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy is based upon the transparency of inputs
to the valuation of an asset or liability as of the measurement date. The three
levels are defined as follows.
• Level
1 - inputs to the valuation methodology that are quoted prices (unadjusted) for
identical assets or liabilities in active markets.
• Level
2 - inputs to the valuation methodology that include quoted prices for similar
assets and liabilities in active markets, and inputs that are observable for the
asset or liability, either directly or indirectly, for substantially the full
term of the financial instrument.
• Level
3 - inputs to the valuation methodology that are unobservable and significant to
the fair value measurement.
A
financial instrument's categorization within the valuation hierarchy is based
upon the lowest level of input that is significant to the fair value
measurement.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
Our oil
swaps, natural gas swaps and interest rate swaps are valued using the
counterparties’ mark-to-market statements which are validated by our internally
developed models and are classified within Level 2 of the valuation hierarchy.
The observable inputs include underlying commodity and interest rate levels and
quoted prices of these instruments on actively traded
markets. Derivatives that are valued based upon models with
significant unobservable market inputs (primarily volatility), and that are
normally traded less actively are classified within Level 3 of the valuation
hierarchy. Level 3 derivatives include oil collars, natural gas collars and
natural gas basis swaps.
Assets
and liabilities measured at fair value on a recurring basis
September
30, 2008 (in millions)
|
|
Total
carrying value on the condensed Balance Sheet
|
|
|
Level
2
|
|
|
Level
3
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
derivatives
|
|
|
209.8 |
|
|
|
.9 |
|
|
|
208.9 |
|
Interest
rate swaps
|
|
|
4.9 |
|
|
|
4.9 |
|
|
|
- |
|
Total
liabilities at fair value
|
|
|
214.7 |
|
|
|
5.8 |
|
|
|
208.9 |
|
Changes
in Level 3 fair value measurements
The table below includes a rollforward
of the Balance Sheet amounts (including the change in fair value) for financial
instruments classified by us within Level 3 of the valuation hierarchy. When a
determination is made to classify a financial instrument within Level 3 of the
valuation hierarchy, the determination is based upon the significance of the
unobservable factors to the overall fair value measurement. Level 3 financial
instruments typically include, in addition to the unobservable or Level 3
components, observable components (that is, components that are actively quoted
and can be validated to external sources).
(in
millions)
|
|
Three
months ended September 30, 2008
|
|
|
Nine
months ended September 30, 2008
|
|
|
|
|
|
|
|
|
Fair
value, beginning of period
|
|
$ |
569.6 |
|
|
$ |
194.3 |
|
Total
realized and unrealized gains and (losses) included in sales of oil and
gas
|
|
|
(370.5 |
) |
|
|
31.1 |
|
Purchases,
sales and settlements, net
|
|
|
9.8 |
|
|
|
(16.5 |
) |
Transfers
in and/or out of Level 3
|
|
|
- |
|
|
|
- |
|
Fair
value, September 30, 2008
|
|
$ |
208.9 |
|
|
$ |
208.9 |
|
|
|
|
|
|
|
|
|
|
Total
unrealized gains and (losses) included in income related to financial
assets and liabilities still on the condensed balance sheet at September
30, 2008
|
|
$ |
- |
|
|
$ |
- |
|
In
February of 2007, the FASB issued SFAS 159, which is effective for fiscal years
beginning after November 15, 2007. SFAS 159 provides an option to elect
fair value as an alternative measurement for selected financial assets and
financial liabilities not previously carried at fair value. We adopted this
statement at January 1, 2008, but did not elect fair value as an alternative for
any financial assets or liabilities.
The
related cash flow impact of all of our hedges is reflected in cash flows from
operating activities. At September 30, 2008, our net fair value of derivatives
liability was $214.7 million as compared to $201.6 million at December 31, 2007
which reflects increases in commodity prices in the period. Based on NYMEX strip
pricing as of September 30, 2008, we expect to make hedge payments under the
existing derivatives of $115.4 million during the next twelve months. At
September 30, 2008, Accumulated Other Comprehensive Loss consisted of $130.4
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,
2008. Deferred net losses recorded in Accumulated Other Comprehensive Loss at
September 30, 2008 and subsequent mark-to-market changes in the underlying
hedging contracts are expected to be reclassified to earnings over the life of
these contracts.
We
entered into the following natural gas hedges during the three months ended
March 31, 2008:
·
|
Swaps
on 15,400 MMBtu/D at $8.50 for the full year of 2009 and basis swaps on
the same volumes for average prices of $1.17, $1.12, $.97, and $1.05 for
each of the four quarters of 2009,
respectively.
|
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
These
swaps were not highly effective at inception, so we subsequently entered into
basis swaps and established effectiveness at that time. In 2007, we
entered into natural gas swap contracts that were not highly
effective. We recognized an unrealized net gain of
approximately $.6 million and an unrealized net loss of $.2 million on the
income statement under the caption Commodity derivatives in the three and nine
months ended September 30, 2008, respectively.
We
entered into the following oil hedges during the three months ended September
30, 2008:
Crude
Oil Sales (NYMEX WTI) Collars
|
|
Average Barrels
Per Day
|
|
|
Floor/Ceiling
Prices
|
|
|
Deferred
Premium Per Barrel
|
|
Full
year 2009
|
|
|
1,000
|
|
|
$
|
100.00
/ $163.60 |
|
|
$
|
1.00 |
|
Full
year 2009
|
|
|
1,000
|
|
|
$
|
100.00
/ $150.30 |
|
|
$
|
- |
|
Full
year 2009
|
|
|
1,000
|
|
|
$
|
100.00
/ $160.00 |
|
|
$
|
2.00 |
|
Full
year 2009
|
|
|
1,000
|
|
|
$ |
100.00
/ $150.00 |
|
|
$
|
0.63 |
|
Full
year 2009
|
|
|
1,000
|
|
|
$
|
100.00
/ $157.48 |
|
|
$
|
- |
|
Full
year 2010
|
|
|
1,000
|
|
|
$ |
100.00
/ $161.10 |
|
|
$
|
1.00 |
|
Full
year 2010
|
|
|
1,000
|
|
|
$
|
100.00
/ $150.30 |
|
|
$
|
- |
|
Full
year 2010
|
|
|
1,000
|
|
|
$
|
100.00
/ $160.00 |
|
|
$
|
2.00 |
|
Full
year 2010
|
|
|
1,000
|
|
|
$
|
100.00
/ $150.00 |
|
|
$
|
1.55 |
|
Full
year 2010
|
|
|
1,000
|
|
|
$
|
100.00
/ $158.50 |
|
|
$
|
- |
|
These
hedges have been designated as cash flow hedges in accordance with SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities.
Our hedge
contracts have been primarily executed with the counterparties that are party to
our senior secured revolving credit facility. The credit rating of
each of these counterparties is AA/Aa2 or better as of
September 30, 2008.
5.
|
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.
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the nine months ended September 30, 2008 (in thousands):
Beginning
balance at January 1
|
|
$
|
36,426
|
|
Liabilities
incurred
|
|
|
3,490
|
|
Liabilities
settled
|
|
|
(3,957
|
)
|
Revisions
in estimated liabilities
|
|
|
|
|
|
|
|
|
|
Ending
balance at September 30
|
|
|
|
|
6.
|
Acquisitions and
Dispositions
|
During
the third quarter of 2008, Berry completed the acquisition of certain interests
in natural gas producing properties on 4,500 net acres in Limestone and Harrison
Counties of East Texas for $666 million cash including an initial purchase price
of $622 million, and normal post closing adjustments of $44
million. See the pro forma discussion in Footnote 8 of these
financial statements. As part of the acquisition we assumed
commitments for drilling rig contracts and compressor rental agreements which
approximate $30 million. Oil and gas properties increased $921
million or 72% from December 31, 2007 to September 30, 2008 primarily due to
this acquisition.
Proceeds
from the first quarter 2008 sale of our Prairie Star assets were $1.8 million
and are reflected in the Statements of Cash Flows. The gain from that
sale is $.4 million and is reflected in the Statements of Income for the nine
month period ended September 30, 2008.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
7.
|
Dry
Hole, Abandonment and Impairment
|
In the
first nine months of 2008, we recorded a total of $9.2 million in dry hole,
abandonment, impairment and exploration expense. Charges of $2.7
million, $2.6 million and $1.6 million were recorded during the first, second
and third quarters of 2008, respectively, for technical difficulties that were
encountered on five wells in the Piceance basin before reaching total
depth. These holes were abandoned in favor of drilling to the
same bottom hole location by drilling new wells. In addition, $2.3
million of
exploration expense was recorded for exploration activities which were primarily
3-D seismic activity in the DJ basin.
On July
15, 2008, the Company acquired certain interests in natural gas producing
properties on 4,500 net acres in Limestone and Harrison Counties in East Texas
for $666 million cash (East Texas Acquisition) including an initial purchase
price of $622 million, and normal post closing adjustments of $44
million.
The
unaudited pro forma results presented below for the three and nine months ended
September 30, 2008 and 2007 have been prepared to give effect to the East Texas
Acquisition on the Company’s results of operations under the purchase method of
accounting as if it had been consummated on January 1, 2007. 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:
|
|
Three
Months Ended
September
30, 2008
|
|
|
Three
Months Ended
September
30, 2007
|
|
|
Nine
Months Ended
September
30, 2008
|
|
|
Nine
Months Ended
September
30, 2007
|
|
Pro
forma revenue
|
|
$ |
253,112 |
|
|
$ |
142,785 |
|
|
$ |
694,269 |
|
|
$ |
454,747 |
|
Pro
forma income from operations
|
|
$ |
91,082 |
|
|
$ |
31,035 |
|
|
$ |
239,235 |
|
|
$ |
124,520 |
|
Pro
forma net income
|
|
$ |
57,427 |
|
|
$ |
20,913 |
|
|
$ |
150,423 |
|
|
$ |
78,878 |
|
Pro
forma basic earnings per share
|
|
$ |
1.29 |
|
|
$ |
0.47 |
|
|
$ |
3.38 |
|
|
$ |
1.79 |
|
Pro
forma diluted earnings per share
|
|
$ |
1.27 |
|
|
$ |
0.46 |
|
|
$ |
3.31 |
|
|
$ |
1.76 |
|
The
following is a preliminary calculation and allocation of purchase price to the
East Texas Acquistion assets and liabilities based on their relative fair
values:
Purchase
price (in thousands):
|
|
As
of
September
30, 2008
|
|
|
Original
purchase price
|
|
$ |
622,356 |
|
|
|
|
|
|
|
|
Closing
adjustments for property costs, and operating expenses in excess of
revenues between the effective date and closing date
|
|
|
43,811 |
|
|
|
|
|
|
|
|
Total
purchase price allocation
|
|
$ |
666,167 |
|
|
|
|
|
|
|
|
Preliminary
allocation of purchase price (in thousands):
|
|
|
|
|
|
Oil
and natural gas properties
|
|
$ |
651,803 |
|
(i)
|
Pipeline
|
|
|
17,288 |
|
|
|
|
|
|
|
|
Total
assets acquired
|
|
|
669,091 |
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
(1,569
|
) |
(ii)
|
Asset
retirement obligation
|
|
|
(1,355
|
) |
|
|
|
|
|
|
|
Net
assets acquired
|
|
$ |
666,167 |
|
|
(i) Determined
by reserve analysis.
(ii) Accrual
for royalties payable and transaction costs, which are primarily legal and
accounting fees.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
The
effective tax rate was 36.5% for the third quarter of 2008 compared to
36.8% for the second quarter of 2008 and 36.5% for the third quarter of
2007. Our estimated annual effective tax rate varies from the 35% federal
statutory rate due to the effects of state income taxes and estimated permanent
differences.
As of
September 30, 2008, we had a gross liability for uncertain tax benefits of
$11.9 million of which $9.6 million, if recognized, would affect the
effective tax rate. There were no significant changes to the calculation since
year end 2007. For the nine months ending September 30, 2008, we
recognized a net tax benefit of approximately $0.9 million due to the closure of
the 2004 federal tax year offset by additional FIN 48 accruals including
interest.
Due to
the uncertainty about the periods in which examinations will be completed and
limited information related to current audits, we are not able to make
reasonably reliable estimates of the periods in which cash settlements will
occur with taxing authorities for the noncurrent liabilities.
Short-term
lines of credit
In 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. In conjunction with
the amendment to our senior secured credit facility, on July 15, 2008, the Line
of Credit was secured with oil and gas properties. At September 30,
2008 the outstanding balance under this Line of Credit was $19.3 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, 2008 was 5.35%.
In July,
2008, we completed a $100 million senior unsecured credit facility that was to
mature on December 31, 2008. There was no outstanding balance under
this credit facility at September 30, 2008 and we terminated it without penalty
in October, 2008 (see footnote 12 Subsequent Events in these financial
statements).
Senior
Secured Revolving Credit Facility
On July
15, 2008, we entered into a five year amended and restated credit agreement (the
Agreement) with Wells Fargo Bank, N.A. as administrative agent and other
lenders. The Agreement amends and restates the Company’s previous
credit agreement dated as of April 28, 2006, as amended. The
Agreement is a revolving credit facility for up to $1.5 billion with a borrowing
base of $1.0 billion. The outstanding Line of Credit reduces our
borrowing capacity available under the Agreement. The borrowing base
under the previous agreement was $650 million. Interest on amounts
borrowed under this debt is charged at LIBOR plus a margin of 1.125% to 1.875%
or the prime rate, with margins on the various rate options based on the ratio
of credit outstanding to the borrowing base. Additionally, an
annual commitment fee of .25% to .375% is charged on the unused portion of the
credit facility. The deferred costs of approximately $8.2 million
associated with the issuance of this credit facility and $.6 million associated
with the issuance of the previous credit facility are being amortized over the 5
year life of the Agreement. $.1 million was charged to the income
statement as a loss on debt extinguishment during the third quarter of 2008
related to parties who reduced their commitment or chose not to participate in
the Agreement.
The total
outstanding debt at September 30, 2008 under the Agreement and the Line of
Credit was $910 million and $19 million, respectively, and $8 million in letters
of credit have been issued under the facility, leaving $63 million in borrowing
capacity available under the Agreement and $100 million available under our
$100 million senior unsecured credit facility. The maximum amount
available is subject to annual redetermination of the borrowing base in
accordance with the lender’s customary procedures and practices. Both
we and the banks have bilateral right to one additional redetermination each
year. We further amended this credit facility in October 2008 (see
Footnote 12 Subsequent Events in these financial statements).
Senior
Subordinated 8.25% notes due 2016
In 2006,
we issued in a public offering $200 million of 8.25% senior subordinated notes
due 2016 (the Notes). Interest on the Notes is paid semiannually in
May and November of each year. 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.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
The
senior secured revolving credit facility contains restrictive covenants which,
among other things, require us to maintain a debt to EBITDA ratio of not greater
than 3.5 to 1.0 and a minimum current ratio, as defined, of 1.0. The $200
million Notes are subordinated to our credit facility indebtedness. Under the
Notes, as long as the interest coverage ratio (as defined) is greater than
2.5
times, we
may incur additional debt. We were in compliance with all of these covenants as
of September 30, 2008.
Interest
Rates and Interest Rate Hedges
Additionally,
in 2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility for five years beginning on September 29, 2006. These interest
rate swaps have been designated as cash flow hedges.
The
weighted average interest rate on total outstanding borrowings at September 30,
2008 was 5.3%.
11.
|
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 and the minimum cost
and/or amount of loss cannot be reasonably estimated. However, because of the
uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be 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.
We have
a crude oil sales contract with an independent refiner for substantially
all of our California production for deliveries beginning February 1, 2006 and
ending January 31, 2010. After the initial term of the contract, we have a
one-year renewal at our option. 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 $8.10, or
2) heavy oil field postings plus a premium of approximately $1.35. The agreement
effectively eliminates our exposure to the risk of a widening WTI to California
heavy crude price differential over the four year contract term and allows us to
effectively hedge our production based on WTI pricing.
In
February 2007, we entered into a multi-staged crude oil sales contract with a
refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D in July 2007. The refiner has increased its total
purchase volume capacity to 5,000 Bbl/D as provided in our
contract. The differential under the contract, which includes
transportation and gravity adjustments, is linked to WTI and would range from
$15 to $20 per barrel at WTI prices between $60 and $80 per
barrel. Gross oil production averaged approximately 4,150 BOE/D in
the quarter ended September 30, 2008.
We have
two long-term firm transportation contracts for our Colorado natural gas
production that total 35,000 MMBtu/D on the Rockies Express (REX) pipeline for
gas production in the Piceance basin. We pay a demand charge for this
capacity and our own production did not completely fill that capacity. To
maximize the utilization of our firm transportation, we bought our partners’
share of the gas produced in the Piceance basin at the market rate for that area
and used our excess transportation to move this gas to the sales point. The
pre-tax net of our gas marketing revenue and our gas marketing expense in the
Statements of Income is $2.0 million for the nine month period ended September
30, 2008.
In
addition, Berry has signed a binding precedent agreement with El Paso
Corporation for an average of 35,000 MMBtu/d of firm transportation on the
proposed Ruby Pipeline from Opal, WY to Malin, OR. While it is not
certain that this new line will be constructed, the expectation is that the
project will proceed and be in service by 2011. As part of this
agreement and in order to access the Ruby pipeline, we also secured firm
transportation from the Piceance basin to Opal.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial
Statements
On
October 17, 2008, we amended our $1.5 billion credit facility with the Company’s
syndicate of seventeen banks which increased our borrowing base from $1.0
billion to $1.25 billion with current commitments of $1.08 billion and a new
maturity date of July 15, 2012. The amendment includes an accordion
feature which allows the Company to increase borrowing commitments to $1.25
billion without further bank approval, and modifies the annual commitment fee
and interest rate margins. Interest on amounts borrowed under the
facility is charged at LIBOR or the prime rate plus a margin. The
LIBOR and prime rate margins range between 1.375% and 2.125% based on the ratio
of credit outstanding to the borrowing base. Additionally, an annual
commitment fee of .30% to .50% is charged on the unused portion of the credit
facility. We also terminated our $100 million senior unsecured credit
facility without penalty that was to mature at December 31,
2008.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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, 2008 and 2007 and our financial
condition, liquidity and capital resources as of September 30, 2008. 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 global 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. We
seek 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:
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
·
|
Developing
our existing resource base
|
·
|
Acquiring
additional assets with significant growth
potential
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
·
|
Utilizing
joint ventures with respected partners to enter new
basins
|
Notable
Third Quarter Items.
·
|
Achieved
target production averaging 35,150 BOE/D, up 31% from the third quarter of
2007 and up 21% from the second quarter of
2008
|
·
|
Closed
on our East Texas acquisition on July 15, 2008, adding approximately 335
Bcfe of proved reserves
|
·
|
Increased
Diatomite net production to an average of 2,100 BOE/D, up 24% from the
second quarter of 2008
|
·
|
Increased
Piceance net average production to 22.7 MMcf/D in the third quarter of
2008, up 37% from the second quarter of
2008
|
·
|
Production
at Poso Creek averaged 3,300 Bbl/D, up 3% from the second quarter of
2008
|
·
|
Increased
both oil and natural gas production during the quarter with oil production
up 9% and natural gas production up 89% from the third quarter of
2007
|
·
|
Amended
our credit facility increasing the borrowing base from $600 million to $1
billion
|
·
|
David
D. Wolf joined the Company as Executive Vice President and Chief Financial
Officer
|
Notable
Items and Expectations for the Fourth Quarter of 2008.
·
|
Increased
the borrowing base on our senior secured credit facility from $1.0 billion
to $1.25 billion with an increase in our commitments to $1.08 billion on
October 17, 2008
|
·
|
Reducing
drilling activity from 12 rigs to 4 rigs by year-end 2008 with 1 rig in
California, 1 rig in the Piceance basin and 2 rigs in East
Texas
|
·
|
Targeting
a production average of 37,000 to 38,000 BOE/D in the fourth
quarter
|
·
|
Planning
to takeover operations in East Texas from the seller on November 1,
2008
|
·
|
Anticipating
a 2009 Capital budget of approximately $200 million focusing on
development of the diatomite and other high return oil projects in
California and high impact recompletions in East
Texas
|
·
|
Expect
proved reserves at year-end to range between 235-245 MMBOE, up over 40%
from 169 MMBOE at year-end 2007, with organic growth of 27
MMBOE
|
Overview of the
Third Quarter of 2008. We had net income of $53.3 million, or $1.17 per
diluted share and net cash from operations was $137.4 million in the third
quarter of 2008. We drilled 118 gross wells and capital expenditures, excluding
property acquisitions, totaled $134.8 million. We achieved average
production of 35,150 BOE/D in the third quarter of 2008, up 21% from an average
of 29,000 BOE/D in the second quarter of 2008.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Results of
Operations. The following
companywide results are in millions (except per share data) for the three months
ended:
|
|
September
30, 2008
(3Q08)
|
|
|
September
30, 2007
(3Q07)
|
|
|
3Q07
to 3Q08 Change
|
|
|
June
30, 2008
(2Q08)
|
|
|
2Q08
to 3Q08 Change
|
|
Sales
of oil
|
|
$ |
145 |
|
|
$ |
100 |
|
|
|
45 |
% |
|
$ |
146 |
|
|
|
(1 |
%) |
Sales
of gas
|
|
|
63 |
|
|
|
19 |
|
|
|
232 |
% |
|
|
39 |
|
|
|
62 |
% |
Total
sales of oil and gas
|
|
$ |
208 |
|
|
$ |
119 |
|
|
|
75 |
% |
|
$ |
185 |
|
|
|
12 |
% |
Sales
of electricity
|
|
|
18 |
|
|
|
12 |
|
|
|
50 |
% |
|
|
17 |
|
|
|
6 |
% |
Gain
on sale of assets
|
|
|
- |
|
|
|
2 |
|
|
|
- |
% |
|
|
- |
|
|
|
- |
% |
Other
revenues
|
|
|
15 |
|
|
|
1 |
|
|
|
1,400 |
% |
|
|
13 |
|
|
|
15 |
% |
Total
revenues and other income
|
|
$ |
241 |
|
|
$ |
134 |
|
|
|
80 |
% |
|
$ |
215 |
|
|
|
12 |
% |
Net
income
|
|
$ |
53 |
|
|
$ |
27 |
|
|
|
96 |
% |
|
$ |
49 |
|
|
|
8 |
% |
Earnings
per share (diluted)
|
|
$ |
1.17 |
|
|
$ |
.60 |
|
|
|
95 |
% |
|
$ |
1.08 |
|
|
|
8 |
% |
Our
revenues may vary significantly from period to period as a result of changes in
commodity prices and/or production volumes. Crude oil sales in the
three months ended September 30, 2008 were flat with the three months ended June
30, 2008 resulting from price decreases of 1% and sales volume increases of 1%.
While crude oil production was 3% higher during the quarter, our sales were up
1% due to a build up in our inventory which we expect to draw during the fourth
quarter of 2008. Gas sales in the three months ended September 30,
2008 were 62% higher than the three months ended June 30, 2008 resulting from
production increases of 69%, in part due to the East Texas acquisition, and a
price decrease of 6%.
In the
first quarter of 2008, we determined there was an error in computing royalties
payable in prior years, accumulating to $10.5 million as of December 31, 2007.
We concluded the error was not material to any individual prior interim or
annual period (or to the projected earnings for 2008) and, therefore, the error
was corrected during the first quarter of 2008, with the effect of increasing
our sales of oil and gas by $10.5 million and reducing our royalties
payable.
Operating
data. The following table is for the three months ended:
|
|
September
30, 2008
|
|
|
%
|
|
|
September
30, 2007
|
|
|
%
|
|
|
June
30, 2008
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
17,264 |
|
|
|
49 |
|
|
|
15,806 |
|
|
|
59 |
|
|
|
16,888 |
|
|
|
58 |
|
Light
Oil Production (Bbl/D)
|
|
|
3,898 |
|
|
|
11 |
|
|
|
3,675 |
|
|
|
14 |
|
|
|
3,723 |
|
|
|
13 |
|
Total
Oil Production (Bbl/D)
|
|
|
21,162 |
|
|
|
60 |
|
|
|
19,481 |
|
|
|
73 |
|
|
|
20,611 |
|
|
|
71 |
|
Natural
Gas Production (Mcf/D)
|
|
|
83,928 |
|
|
|
40 |
|
|
|
44,346 |
|
|
|
27 |
|
|
|
50,339 |
|
|
|
29 |
|
Total
(BOE/D)
|
|
|
35,150 |
|
|
|
100 |
|
|
|
26,873 |
|
|
|
100 |
|
|
|
29,000 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas, per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$ |
80.22 |
|
|
|
|
|
|
$ |
49.35 |
|
|
|
|
|
|
$ |
91.89 |
|
|
|
|
|
Average
sales price after hedging
|
|
|
64.98 |
|
|
|
|
|
|
|
47.93 |
|
|
|
|
|
|
|
69.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$ |
118.22 |
|
|
|
|
|
|
$ |
75.15 |
|
|
|
|
|
|
$ |
123.80 |
|
|
|
|
|
Price
sensitive royalties
|
|
|
(5.30
|
) |
|
|
|
|
|
|
(5.50
|
) |
|
|
|
|
|
|
(5.92
|
) |
|
|
|
|
Quality
differential and other
|
|
|
(10.80
|
) |
|
|
|
|
|
|
(9.56
|
) |
|
|
|
|
|
|
(11.52
|
) |
|
|
|
|
Crude
oil hedges
|
|
|
(26.12
|
) |
|
|
|
|
|
|
(4.37
|
) |
|
|
|
|
|
|
(29.37
|
) |
|
|
|
|
Average
oil sales price after hedging
|
|
$ |
76.00 |
|
|
|
|
|
|
$ |
55.72 |
|
|
|
|
|
|
$ |
76.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$ |
10.24 |
|
|
|
|
|
|
$ |
6.24 |
|
|
|
|
|
|
$ |
10.93 |
|
|
|
|
|
Conversion
to Mcf
|
|
|
.52 |
|
|
|
|
|
|
|
.31 |
|
|
|
|
|
|
|
.55 |
|
|
|
|
|
Natural
gas hedges
|
|
|
.15 |
|
|
|
|
|
|
|
1.07 |
|
|
|
|
|
|
|
(.69
|
) |
|
|
|
|
Location,
quality differentials and other
|
|
|
(2.81
|
) |
|
|
|
|
|
|
(3.06
|
) |
|
|
|
|
|
|
(2.15
|
) |
|
|
|
|
Average
gas sales price after hedging per Mcf
|
|
$ |
8.10 |
|
|
|
|
|
|
$ |
4.56 |
|
|
|
|
|
|
$ |
8.64 |
|
|
|
|
|
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Operating
data. The following table is for the nine months ended:
|
|
September
30, 2008
|
|
|
%
|
|
|
September
30, 2007
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,845 |
|
|
|
54 |
|
|
|
16,019 |
|
|
|
60 |
|
Light
Oil Production (Bbl/D)
|
|
|
3,710 |
|
|
|
12 |
|
|
|
3,655 |
|
|
|
14 |
|
Total
Oil Production (Bbl/D)
|
|
|
20,555 |
|
|
|
66 |
|
|
|
19,674 |
|
|
|
74 |
|
Natural
Gas Production (Mcf/D)
|
|
|
61,201 |
|
|
|
34 |
|
|
|
41,109 |
|
|
|
26 |
|
Total
(BOE/D)
|
|
|
30,755 |
|
|
|
100 |
|
|
|
26,525 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas, per BOE:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$ |
82.57 |
|
|
|
|
|
|
$ |
45.98 |
|
|
|
|
|
Average
sales price after hedging
|
|
|
66.37 |
|
|
|
|
|
|
|
45.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$ |
113.52 |
|
|
|
|
|
|
$ |
66.22 |
|
|
|
|
|
Price
sensitive royalties
|
|
|
(3.36
|
) |
|
|
|
|
|
|
(4.48
|
) |
|
|
|
|
Quality
differential and other
|
|
|
(12.90
|
) |
|
|
|
|
|
|
(9.26
|
) |
|
|
|
|
Crude
oil hedges
|
|
|
(23.83
|
) |
|
|
|
|
|
|
(1.61
|
) |
|
|
|
|
Correction
to royalties payable
|
|
|
1.88 |
|
|
|
|
|
|
|
- |
|
|
|
|
|
Average
oil sales price after hedging
|
|
$ |
75.31 |
|
|
|
|
|
|
$ |
50.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$ |
9.74 |
|
|
|
|
|
|
$ |
7.02 |
|
|
|
|
|
Conversion
to Mcf
|
|
|
.49 |
|
|
|
|
|
|
|
.36 |
|
|
|
|
|
Natural
gas hedges
|
|
|
(.15
|
) |
|
|
|
|
|
|
.67 |
|
|
|
|
|
Location,
quality differentials and other
|
|
|
(2.01
|
) |
|
|
|
|
|
|
(2.85
|
) |
|
|
|
|
Average
gas sales price after hedging per Mcf
|
|
$ |
8.07 |
|
|
|
|
|
|
$ |
5.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Gas Basis
Differential. The basis differential between Henry Hub
(HH) and Colorado Interstate Gas (CIG) index increased during the third
quarter after decreasing at the start up of the Rockies Express Pipeline
(REX) in January. The differential averaged $4.31 in the third
quarter. In the second quarter of 2008, the CIG basis
differential per MMBtu, based upon first-of-month values, averaged $2.45
below HH and ranged from $1.77 to $3.24 below HH. For the
third quarter, the differential averaged $4.31 with the range from $2.19
at the start of the quarter to $6.61 below HH at the end of the quarter.
The large September differential was due primarily to maintenance on REX
which put a large portion of the pipeline out of service for almost the
entire month. Maintenance was completed and REX was back in
service September 28, 2008. We have contracted a total of
35,000 MMBtu/D on the REX pipeline under two separate transactions to
provide firm transportion for our Piceance basin gas
production. After the REX startup in 2008, all of the Piceance
basin gas was sold at mid-continent (ANR, NGPL or PEPL) indexes which
averaged approximately $1.08 above the CIG index pricing before the cost
of transportation.
|
Gas from
the Uinta basin sold for approximately $.30 below CIG pricing before deducting
the cost of pipeline transport. A portion of the Uinta gas is priced
on the Questar index while the remainder is based upon the CIG or NWPL
index.
DJ Basin
gas is priced using one of two indices. Approximately two-thirds of our volume
from our DJ natural gas properties is tied to the Panhandle Eastern Pipeline
(PEPL) index for pricing and the remaining volume to CIG pricing. 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 $1.91 below the HH index during the third quarter, before
the cost of transportation. The remainder of the DJ Basin gas is sold slightly
above the CIG index price.
Gas Marketing.
We have two long-term (ten year) firm transportation contracts for our
Colorado natural gas production. The first contract is for 10,000 MMBtu/D on the
Rockies Express (REX) pipeline for gas production in the Piceance
basin. The second contract is for 25,000 MMBtu/D on the REX pipeline
for gas production in the Piceance basin. We pay a demand charge for this
capacity and our own production did not fill that capacity. In order to maximize
our firm transportation capacity, we bought our partners’ share of the gas
produced in the Piceance at the market rate for that area. We then used our
excess transportation to move this gas to where it was eventually sold. The
pre-tax net of our gas marketing revenue and our gas marketing expense in the
Statements of Income is $2.0 million in the nine month period ended September
30, 2008.
In
addition, Berry has signed a binding precedent agreement with El Paso
Corporation for an average of 35,000 MMBtu/d of firm transportation on the
proposed Ruby Pipeline from Opal, WY to Malin, OR. While it is not
certain that this new line will be constructed, the expectation is that the
project will proceed and be in service by 2011. As part of this
agreement and in order to access the Ruby pipeline, we also secured firm
transportation from the Piceance basin to Opal.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Oil Contracts.
California - We have
a crude oil sales contract with an independent refiner for substantially all of
our California production for deliveries beginning February 1, 2006 and ending
January 31, 2010. After the initial term of the contract, we have a one-year
renewal at our option. 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 $8.10, or 2) heavy
oil field postings plus a premium of approximately $1.35. The agreement
effectively eliminates our exposure to the risk of a widening WTI to California
heavy crude price differential over the four year contract term and allows us to
effectively hedge our production based on WTI pricing.
Utah - In
February 2007, we entered into a multi-staged crude oil sales contract with a
refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D in July 2007. The refiner has increased its total
capacity to 5,000 Bbl/D as provided in our contract. As operator we deliver all
produced volumes under our sales contracts, although our working interest
partners or royalty owners may take their respective volumes in kind and market
their own volumes. Gross oil production averaged approximately 4,150
BOE/D in the quarter ended September 30, 2008. The differential under the
contract, which includes transportation and gravity adjustments, is linked to
WTI and would range from $15 to $20 per barrel at WTI prices between $60 and
$80. This contract provides us an outlet to sell all of our current oil
production in the Uinta basin.
Hedging.
See Note 4 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 cost-effective production of heavy oil in California. We sell
our electricity to utilities under standard offer contracts based on "avoided
cost" or SRAC pricing approved by the California Public Utilities Commission
(CPUC) and under which our revenues are currently linked to the cost of natural
gas. Natural gas index prices are the primary determinant of our electricity
sales price based on the current pricing formula under these contracts. The
correlation between electricity sales and natural gas prices allows us to manage
our cost of producing steam more effectively.
In 2007,
our electricity operations improved partially from the lower cost of our firm
transportation natural gas compared to California prices which are used to
determine our electricity payment. We purchase and transport 12,000 MMBtu/D on
the Kern River Pipeline under our firm transportation contract and use this
gas to produce cogeneration steam in the Midway-Sunset field. The differential
between Rocky Mountain gas prices and Southern California Border prices
increased during 2007 allowing us to purchase a portion of our gas at a discount
to the Southern California Border price. As our electricity revenue is linked to
Southern California Border prices, the fuel we purchased at lower Rocky Mountain
prices was the primary contributor to the increase in our electricity margin in
2007. We purchased approximately 38,000 MMBtu/D as fuel for use in our
cogeneration facilities in the year ended December 31, 2007.
We
generally expect to have small gains or losses on electricity on a quarterly
basis which depends on seasonality as we receive improved pricing during the
summer months. However, wider natural gas price differentials in the Rockies
when compared to California will increase our margin on electricity as described
above. In the third quarter of 2008, our margin on electricity
increased to $4.6 million. Approximately $2 million of this margin
was due to lower Rockies gas prices when compared to Southern California border
prices and $2.4 million of this change was due to seasonal capacity payments the
Company receives during the summer months.
On
September 20, 2007, the CPUC issued a decision (SRAC Decision) that changes the
way SRAC energy prices will be determined for existing and new Standard Offer
(SO) contracts and revises the capacity prices paid under current SO1 contracts.
The effective date of the new pricing under the SRAC Decision has not been
determined as of yet and a portion of the SRAC Decision has been appealed to the
Court of Appeal. We do not believe that the
proposed pricing changes will materially affect us in
2008.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
The
following table is for the three months ended:
|
|
September
30, 2008
|
|
September
30, 2007
|
|
|
June
30, 2008
|
|
Electricity
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
$
|
18.3
|
$
|
12.3
|
|
$
|
17.0
|
|
Operating
costs (in millions)
|
|
13.7
|
|
9.8
|
|
|
15.5
|
|
Electric
power produced - MWh/D
|
|
2,096
|
|
2,257
|
|
|
1,919
|
|
Electric
power sold - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
gas cost/MMBtu (including transportation)
|
$
|
8.20
|
$
|
4.84
|
|
$
|
10.01
|
|
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, 2008
|
|
|
September
30, 2007
|
|
|
June
30,
2008
|
|
|
September
30, 2008
|
|
|
September
30, 2007
|
|
|
June
30, 2008
|
|
Operating
costs – oil and gas production
|
|
$ |
17.33 |
|
|
$ |
13.75 |
|
|
$ |
20.91 |
|
|
$ |
56,038 |
|
|
$ |
33,995 |
|
|
$ |
55,185 |
|
|
|
|
2.99 |
|
|
|
1.76 |
|
|
|
2.83 |
|
|
|
9,673 |
|
|
|
4,344 |
|
|
|
7,481 |
|
DD&A
– oil and gas production
|
|
|
12.51 |
|
|
|
9.45 |
|
|
|
11.02 |
|
|
|
40,440 |
|
|
|
23,356 |
|
|
|
29,073 |
|
G&A
|
|
|
4.49 |
|
|
|
3.78 |
|
|
|
4.23 |
|
|
|
14,524 |
|
|
|
9,333 |
|
|
|
11,160 |
|
|
|
|
2.71 |
|
|
|
1.75 |
|
|
|
1.50 |
|
|
|
8,755 |
|
|
|
4,326 |
|
|
|
3,951 |
|
Total
|
|
$ |
40.03 |
|
|
$ |
30.49 |
|
|
$ |
40.49 |
|
|
$ |
129,430 |
|
|
$ |
75,354 |
|
|
$ |
106,850 |
|
Our total
operating costs, production taxes, DD&A, G&A and interest expenses for
the three months ended September 30, 2008, stated on a unit-of-production basis,
increased 32% over the three months ended September 30, 2007 and decreased 1% as
compared to the three months ended June 30, 2008. The changes were primarily
related to the following items:
|
·
|
Operating
costs: Steam costs are the primary variable component of our operating
costs and fluctuate based on the amount of steam we inject and the price
of fuel used to generate steam. The following table presents steam
information:
|
|
|
September
30, 2008
(3Q08)
|
|
|
September
30, 2007
(3Q07)
|
|
|
3Q07
to
3Q08 Change
|
|
|
June
30, 2008
(2Q08)
|
|
|
2Q08
to 3Q08 Change
|
|
Average
volume of steam injected (Bbl/D)
|
|
|
105,574 |
|
|
|
88,711 |
|
|
|
19 |
% |
|
|
97,853 |
|
|
|
8 |
% |
Fuel
gas cost/MMBtu (including transportation)
|
|
$ |
8.20 |
|
|
$ |
4.84 |
|
|
|
69 |
% |
|
$ |
10.01 |
|
|
|
(18 |
%) |
Approximate
net fuel gas volume consumed in steam generation (MMBtu/D)
|
|
|
29,362 |
|
|
|
23,348 |
|
|
|
26 |
% |
|
|
27,382 |
|
|
|
7 |
% |
Operating
costs increased by $1 million or 2% between the second and third quarters of
2008. The East Texas Acquisition increased our total operating costs
on a nominal basis with the impact of decreasing per barrel costs as these
natural gas assets have lower per barrel operating costs. This
increase was offset by a $4 million decrease in fuel gas costs due to a decrease
in natural gas prices offset by increased fuel gas consumption. Our
total cost to purchase fuel for our steam operations decreased by $1.81 per
MMBtu or 18% in the three months ended September 30, 2008 compared to the three
months ended June 30, 2008 as the SoCal border natural gas price decreased over
this time period. We plan to increase our fuel gas consumption by
3,000 MMBtu/D in the fourth quarter of 2008 as we add additional steam
generation capacity at Poso Creek and the Diatomite.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
·
|
Production
taxes: Our production taxes have increased compared to the third quarter
of 2007 as commodity prices and thus the value of our oil and natural gas
has increased. The increase from the second quarter of 2008 is
primarily due to an increase in the assessed value of our properties in
California. Severance taxes paid in Utah, Colorado and
Texas are directly related to the field sales price of the commodity. In
California, our production is burdened with ad valorem taxes on our total
proved reserves. We expect production taxes to fluctuate with oil and gas
prices.
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE by 32% and 14%
in the third quarter of 2008 as compared to the third quarter of 2007 and
as compared to the second quarter of 2008, respectively, due to an
increase in the contribution of our development properties with higher
drilling and leasehold acquisition costs and the integration of our East
Texas assets which have higher finding and development costs than our
legacy assets.
|
·
|
General
and administrative: Approximately 70% of our G&A is related to
compensation. The primary reason for the increase in G&A during the
third quarter of 2008 as compared to the third quarter of 2007 was due to
due to additional staffing and the costs associated with the 2008
relocation of our corporate office from Bakersfield, California to Denver,
Colorado.
|
·
|
Interest
expense: Our total outstanding borrowings were approximately $1.1 billion
at September 30, 2008 compared to $440 million and $511 million at
September 30, 2007 and June 30, 2008, respectively. Our average borrowings
increased since June 30, 2008 primarily due to the East Texas acquisition
in the third quarter of 2008. For the three months ended
September 30, 2008, $7 million of interest cost has been capitalized and
we expect to capitalize approximately $23 million of interest cost during
the full year of 2008.
|
Estimated 2008
and Actual Nine Months Ended September 30, 2008 and 2007 Oil and Gas
Operating, G&A and
Interest Expenses.
Based upon our reduced activity in the fourth quarter of 2008, we estimate our
average 2008 production volume will range between 32,000 BOE/D and 33,000
BOE/D.
|
|
Anticipated
range
Full
Year 2008
per
BOE
|
|
|
Nine
months ended
September
30, 2008
|
|
|
Nine
months ended
September
30, 2007
|
|
Operating
costs-oil and gas production
|
|
$ |
17.00
to 19.00 |
|
|
$ |
18.14 |
|
|
$ |
14.27 |
|
|
|
|
|
|
|
2.74 |
|
|
|
1.70 |
|
DD&A
– oil and gas production (1)
|
|
|
|
|
|
11.46 |
|
|
|
9.04 |
|
G&A
|
|
4.00
to 4.50
|
|
|
|
4.40 |
|
|
|
4.05 |
|
|
|
|
|
|
|
1.95 |
|
|
|
1.88 |
|
Total
|
|
$ |
36.75
to 40.75 |
|
|
$ |
38.69 |
|
|
$ |
30.94 |
|
(1)
Full year estimate includes both oil and gas and electricity
Our total
operating costs, production taxes, DD&A, G&A and interest expenses for
the nine months ended September 30, 2008, stated on a unit-of-production basis,
increased 25% over the nine months ended September 30, 2007. The changes were
primarily related to the following items:
|
·
|
Operating
costs: The majority of the increase in our operating costs was due to
higher steam costs resulting from higher fuel costs. The following table
presents steam information:
|
|
|
Nine
months ended
September
30, 2008
|
|
|
Nine
months ended
September
30, 2007
|
|
|
Change
|
|
Average
volume of steam injected (Bbl/D)
|
|
|
98,050 |
|
|
|
86,157 |
|
|
|
14 |
% |
Fuel
gas cost/MMBtu (including transportation)
|
|
$ |
8.70 |
|
|
$ |
5.78 |
|
|
|
51 |
% |
Approximate
net fuel gas volume consumed in
steam
generation (MMBtu/D)
|
|
|
26,128 |
|
|
|
21,698 |
|
|
|
20 |
% |
Our total
cost to purchase fuel for our steam operations increased by $2.92 per MMBtu or
51% in the nine months ended September 30, 2008 compared to the nine months
ended September 30, 2007 as the SoCal border natural gas price increased over
this time period. We consumed an additional 4,430 MMBtus per day in
the first nine months of 2008 when compared to the first nine months of 2007
primarily related to increased conventional steam generation
consumption.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
·
|
Production
taxes: Production taxes per BOE in the nine months ended September 30,
2008 were 61% higher than the comparable period in 2007 as commodity
prices and thus the value of our oil and natural gas has increased.
Severance taxes paid in Utah, Colorado and Texas are directly related to
the field sales price of the commodity. In California, our production is
burdened with ad valorem taxes on our total proved
reserves.
|
·
|
Depreciation,
depletion and amortization: DD&A per BOE was 27% higher in the nine
months ended September 30, 2008 compared to the same period in the prior
year due to an increase in the contribution of our development properties
with higher drilling and leasehold acquisition costs and the integration
of our East Texas acquisition.
|
·
|
General
and administrative: G&A per BOE increased by 9% in the nine months
ended September 30, 2008 compared to the same period in the prior year due
to additional staffing and higher overall compensation costs associated
with our growth activities and the relocation of our corporate
headquarters.
|
·
|
Interest
expense: Our total outstanding borrowings was approximately
$1.1 billion at September 30, 2008 compared to approximately
$440 million at September 30, 2007. Our average borrowings increased
since September 30, 2007 primarily due to the East Texas acquisition in
the third quarter of 2008. For the nine months ended September
30, 2008, $16 million of interest cost has been
capitalized.
|
Royalties. The
price sensitive royalty that impacts our Formax property in the South Midway
Sunset field has changed. We previously paid a royalty equal to 75%
of the amount of the heavy oil posted above a price of $16.11. This
price escalates at 2% annually. Effective January 1, 2008, the
royalty rate is reduced from 75% to 53% as long as we maintain a minimum steam
injection level, which we expect to meet, that reduces over
time. Current net production from this property is approximately
2,300 Bbl/D.
Dry Hole,
Abandonment, impairment and exploration. In the first nine
months of 2008, we recorded a total of $9.2 million in dry hole, abandonment,
impairment and exploration expense. Charges of $2.7 million, $2.6
million and $1.5 million were recorded during the first, second and third
quarters of 2008, respectively, for technical difficulties that were encountered
on five wells in the Piceance basin before reaching total
depth. These holes were abandoned in favor of drilling to the
same bottom hole location by drilling new wells. In addition, $2.3
million of
exploration expense was recorded for exploration activities which were primarily
3-D seismic activity in the DJ basin.
Income
Taxes. We experienced an effective tax rate of 36.5% in both the
three months ended September 30, 2008 and the three months ended September 30,
2007. Our rate differs from the combined federal and state statutory
tax rate (net of the federal benefit), primarily due to certain business
incentives. See Note 9 to the unaudited condensed financial
statements.
Development, Exploitation and
Exploration
Activity. We drilled 118 gross (101 net) wells during the third quarter
of 2008.
Drilling
Activity. The following table sets
forth certain information regarding drilling activities (including operated and
non-operated wells):
|
|
|
|
|
Nine
months ended
September
30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
|
|
68 |
|
|
|
68 |
|
|
|
|
23 |
|
|
|
23 |
|
|
|
92 |
|
|
|
92 |
|
S.
Cal
|
|
|
- |
|
|
|
- |
|
|
|
25 |
|
|
|
25 |
|
|
|
|
26 |
|
|
|
16 |
|
|
|
65 |
|
|
|
37 |
|
|
|
|
16 |
|
|
|
16 |
|
|
|
45 |
|
|
|
45 |
|
|
|
|
33 |
|
|
|
26 |
|
|
|
79 |
|
|
|
65 |
|
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
|
|
|
118 |
|
|
|
101 |
|
|
|
383 |
|
|
|
341 |
|
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Properties
Asset
Team Descriptions
S. Midway
– During the three months ended September 30, 2008, production averaged
approximately 8,950 Bbl/D compared to approximately 9,350 Bbl/D and 9,100 Bbl/D
during the three month periods ended September 30, 2007 and June 30, 2008,
respectively. In 2008 we drilled 18 deeper horizontal wells in the reservoir.
This series of horizontal wells, coupled with targeted steam placement, has
helped offset the natural decline of the mature resource. In addition
we drilled two horizontal wells on the Formax property following the
renegotiation of the price sensitive royalty. In 2008, we also began
developing the Monarch reservoir on our Ethel D property. We drilled
32 wells in the Monarch in the first nine months of the year and production
averaged 1,200 Bbl/D using cyclic steam injection. We believe that
Ethel D production can be further enhanced through a steamflood and we will be
expanding the pilot we began in 2007 later this year.
N. Midway
– During the three months ended September 30, 2008, production from the area
averaged approximately 3,000 Bbl/D compared to approximately 2,200 Bbl/D and
2,600 Bbl/D during the three month periods ended September 30, 2007 and June 30,
2008, respectively. In October 2007, we embarked on a full-scale, continuous
development program of the Diatomite and we expect to drill continuously over
the next four years. Over 98 new producers have been drilled since October 2007.
We are bringing these wells on production as the necessary infrastructure is
installed to steam and produce these wells. The additional wells,
steam and supporting infrastructure has enabled us to increase production of the
Diatomite which averaged 1,700 BOE/D during the second quarter of 2008 to over
2,100 BOE/D during the third quarter of 2008.
S. Cal –
During the three months ended September 30, 2008, production averaged
approximately 5,350 Bbl/D compared to approximately 4,300 Bbl/D and 5,300 Bbl/D
during the three month periods ended September 30, 2007 and June 30, 2008,
respectively. This year’s plans at Poso Creek call for further expansion
including the addition of a fourth steam generator, which we brought on line in
February, drilling 28 producers and expanding the steam flood. As of September
2008, all 28 planned producers have been drilled and Poso Creek production is
currently averaging 3,300 BOE/D. During the fourth quarter of 2008, additional
steam injectors will be drilled and a fifth steam generator will be installed to
further increase our production from this asset.
Piceance – During the
three months ended September 30, 2008, production from the Piceance basin
averaged 22.7 MMcf/D, an increase of 37% from the prior quarter. Of the Company
operated wells, we drilled 26 gross wells (16 net) during the third quarter of
2008. We have drilled over 130 wells since we acquired our original Piceance
basin acreage in early 2006. We are currently operating two drilling rigs and
continue to realize further efficiencies with repeated drilling times reduced to
9 to 13 days for a mesa well. Throughout the third quarter of 2008,
we realized increasing production from the summer completion season with current
production now over 30 MMcf/D. Initial production rates from these
wells have been in line with our expectations.
Uinta
–
Average daily production during the three months ended September 30, 2008
from all Uinta basin assets was approximately 6,400 BOE/D, an increase of 6%
from the prior quarter. During the three months ended September 30, 2008, we
returned to a one rig drilling program at Brundage Canyon following the
temporary operation of two drilling rigs during the prior quarter. The
development at Brundage Canyon continues to be focused on drilling high
potential areas in the core of the field where we drilled 11 wells in the third
quarter of 2008. Evaluating the waterflood feasibility at Brundage Canyon
has progressed and we anticipate receiving regulatory approval before year-end
with first injection in early 2009. During the third quarter of 2008, we further
delineated the Ashley Forest by drilling 4 wells under our existing
environmental approvals and currently we are drilling the 8th and
final well of our 2008 Ashley Forest program. We continue to optimize and
pace our Uinta drilling program while the Ashley Forest Development EIS
progresses towards its anticipated approval in early 2009.
DJ – During the three
months ended September 30, 2008, we drilled 33 gross Niobrara development wells
in Yuma County, Colorado, with a 100% success rate. Average daily production in
the DJ basin for the three months ended September 30, 2008 was 20
MMcf/D. Earlier this year we completed the interpretation of an
additional 75 square miles of 3-D seismic that we acquired over the
winter. The seismic surveys replenished our low risk repeatable
drilling inventory and we are currently permitting many of those drilling
locations for our 2009 capital program.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
East
Texas – On July 15,
2008, we acquired
certain interests in natural gas producing properties on 4,500 net acres in
Limestone and Harrison Counties in East Texas. We have assembled our asset team
and plan to take over operations from the seller on November 1,
2008. Production should increase from its current level of
approximately 30 MMcf/d as our team transitions field, drilling and completion
operations. We drilled 9 wells on the property during the
quarter and have brought 2 of these wells on production. We plan to
drill approximately 8 wells during the fourth quarter and complete the remaining
wells drilled during the third quarter of 2008. We have drilled
four vertical Haynesville appraisal wells which demonstrate productivity to
support a horizontal development of this resource. We expect to drill
our first Haynesville horizontal well during the first half of
2009.
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, production rates
and operating expenses have been the primary reason for changes in our cash flow
from operating activities.
We had a
senior unsecured revolving bank credit facility agreement (the Agreement) with a
banking syndicate through June 30, 2011. The Agreement was a revolving
credit facility for up to $750 million with a borrowing base as of June 30, 2008
of $600 million. As of June 30, 2008, we had total borrowings under
the Agreement and Line of Credit of $311 million and $200 million under our
senior subordinated ten year notes.
On July
15, 2008, we entered into a five-year amended and restated secured credit
agreement (the Credit Agreement) with Wells Fargo Bank, N.A as administrative
agent and other lenders. The total outstanding debt at September 30,
2008 under the Agreement and the short-term Line of Credit was $910 million and
$19 million, respectively, and $8 million in letters of credit have been issued
under the facility leaving $63 million in borrowing capacity
available under the Agreement and $100 million available under our $100
million senior unsecured credit facility.
On
October 17, 2008, we amended our $1.5 billion Credit Agreement with the
Company’s syndicate of seventeen banks which increased our borrowing base from
$1.0 billion to $1.25 billion with current commitments of $1.08 billion and a
new maturity date of July 15, 2012. The amendment includes an
accordion feature which allows the Company to increase borrowing commitments to
$1.25 billion without further bank approval, and modifies the annual commitment
fee and interest rate margins. As of October 27, 2008 we had
$144 million in borrowing capacity available. The maximum amount
available is subject to a semi-annual redetermination of the borrowing base in
accordance with the lender's customary procedures and practices. Both we and the
banks have bilateral rights to one additional redetermination each
year.
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 and/or drilling outcomes or significant changes in cash
flows.
In 2008,
we had an original capital program of approximately $295 million, excluding
acquisitions. The capital development program was increased by $75 million
during the second quarter of 2008 in conjunction with the East Texas Acquisition
to a total of $370 million. Increases in steel prices and other
services will likely result in total capital spending for the full year 2008 of
approximately $400 million. While we have reduced our activity during
the fourth quarter of 2008, we do not expect to see the results of this
reduction until early in the first quarter of 2009 as we complete projects and
release rigs after contractual commitments are complete. Excess cash
generated from operations is expected to be applied toward acquisitions, debt
reduction or other corporate purposes.
Capital
expenditures, excluding property acquisitions, totaled $135 million and $306
million during the three and nine months ended September 30, 2008,
respectively.
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.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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, 2008
(3Q08)
|
|
|
September
30, 2007
(3Q07)
|
|
|
3Q07
to 3Q08
Change
|
|
|
June
30, 2008
(2Q08)
|
|
|
2Q08
to 3Q08
Change
|
|
Average
production (BOE/D)
|
|
|
35,150 |
|
|
|
26,873 |
|
|
|
31 |
% |
|
|
29,000 |
|
|
|
21 |
% |
Average
oil and gas sales prices, per BOE after hedging
|
|
$ |
64.98 |
|
|
$ |
47.93 |
|
|
|
36 |
% |
|
$ |
69.77 |
|
|
|
(7 |
)% |
Net
cash provided by operating activities (1)
|
|
$ |
137 |
|
|
$ |
93 |
|
|
|
47 |
% |
|
$ |
107 |
|
|
|
28 |
% |
Working
capital
|
|
$ |
(148 |
) |
|
$ |
(91 |
) |
|
|
(63 |
)% |
|
$ |
(225 |
) |
|
|
34 |
% |
Sales
of oil and gas
|
|
$ |
208 |
|
|
$ |
119 |
|
|
|
75 |
% |
|
$ |
185 |
|
|
|
12 |
% |
Total
debt
|
|
$ |
1,129 |
|
|
$ |
440 |
|
|
|
157 |
% |
|
$ |
511 |
|
|
|
1,21 |
% |
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
|
$ |
742 |
|
|
$ |
63 |
|
|
|
1,078 |
% |
|
$ |
154 |
|
|
|
382 |
% |
Dividends
paid
|
|
$ |
3.4 |
|
|
$ |
3.4 |
|
|
|
- |
% |
|
$ |
3.4 |
|
|
|
- |
% |
(1)
|
The
change in the book overdraft line in the Statements of Cash Flows is
classified as an operating activity to reflect the use of these funds in
operations, rather than their prior year classification as a financing
activity.
|
Contractual
Obligations. Our contractual
obligations as of September 30, 2008 are as follows (in millions):
|
|
Total
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
Thereafter
|
|
Total
debt and interest
|
|
$ |
1,524.7 |
|
|
$ |
37.7 |
|
|
$ |
70.6 |
|
|
$ |
70.6 |
|
|
$ |
70.6 |
|
|
$ |
70.6 |
|
|
$ |
1,204.6 |
|
|
|
|
40.4 |
|
|
|
.4 |
|
|
|
1.7 |
|
|
|
1.7 |
|
|
|
1.6 |
|
|
|
1.6 |
|
|
|
33.4 |
|
Operating
lease obligations
|
|
|
17.5 |
|
|
|
.6 |
|
|
|
2.3 |
|
|
|
2.3 |
|
|
|
2.3 |
|
|
|
2.3 |
|
|
|
7.7 |
|
Drilling
and rig obligations
|
|
|
74.4 |
|
|
|
12.4 |
|
|
|
27.6 |
|
|
|
15.0 |
|
|
|
19.4 |
|
|
|
- |
|
|
|
- |
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
161.9 |
|
|
|
3.9 |
|
|
|
19.5 |
|
|
|
19.5 |
|
|
|
19.5 |
|
|
|
19.1 |
|
|
|
80.4 |
|
Total
|
|
$ |
1,818.9 |
|
|
$ |
55.0 |
|
|
$ |
121.7 |
|
|
$ |
109.1 |
|
|
$ |
113.4 |
|
|
$ |
93.6 |
|
|
$ |
1,326.1 |
|
Drilling obligations
- Under our June 2006 joint venture agreement in the Piceance basin we are
required to have 120 wells drilled by February 2011 to avoid penalties of $.2
million per well or a maximum of $24 million. As of September 30, 2008 we have
drilled 29 of these wells and we expect to meet our obligation to have the
remaining wells drilled by February 2011.
Other Obligations -
We adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of September 30, 2008, we had a
gross liability for uncertain tax benefits of $11.9 million of which $9.6
million, if recognized, would affect the effective tax rate.
In
February 2007, we entered into a multi-staged crude oil sales contract with a
refiner for our Uinta basin light crude oil. Under the agreement, the refiner
began purchasing 3,200 Bbl/D in July 2007, as provided in our
contract. The refiner has increased its total purchase capacity to
5,000 Bbl/D as provided in our contract. The differential under the contract,
which includes transportation and gravity adjustments, is linked to WTI and
would range from $15 to $20 per barrel at WTI prices between $60 and
$80. Gross oil production averaged approximately 4,150 BOE/D in the
quarter ended September 30, 2008.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Item
3.
Quantitative
and Qualitative Disclosures About Market
Risk
|
As
discussed in Note 4 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, we enter into crude oil and natural gas
hedge contracts from time to time. 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 some
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 or Rockies gas price and we sell our
produced gas in Colorado and Utah at various index prices.
The
following table summarizes our hedge position as of September 30,
2008:
|
|
Average
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Barrels
|
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
|
Average
|
|
Term
|
|
Per
Day
|
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
|
Price
|
|
Crude
Oil Sales (NYMEX WTI) Collars
|
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO CIG) Basis Swaps
|
|
|
|
|
|
|
Full
year 2008
|
|
|
10,000 |
|
|
$ |
47.50
/ $70.00 |
|
4th
Quarter 2008
|
|
|
21,000 |
|
|
$ |
1.46 |
|
Full
year 2009
|
|
|
10,000 |
|
|
$ |
47.50
/ $70.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2009
|
|
|
295 |
|
|
$ |
80.00
/ $91.00 |
|
Natural
Gas Sales (NYMEX HH TO PEPL) Basis Swaps
|
|
|
|
|
|
|
|
|
Full
year 2009
|
|
|
1,000 |
|
|
$ |
100.00
/ $163.60 |
|
1st
Quarter 2009
|
|
|
15,400 |
|
|
$ |
1.17 |
|
Full
year 2009
|
|
|
1,000 |
|
|
$ |
100.00
/ $150.30 |
|
2nd
Quarter 2009
|
|
|
15,400 |
|
|
$ |
1.12 |
|
Full
year 2009
|
|
|
1,000 |
|
|
$ |
100.00
/ $160.00 |
|
3rd
Quarter 2009
|
|
|
15,400 |
|
|
$ |
0.97 |
|
Full
year 2009
|
|
|
1,000 |
|
|
$ |
100.00
/ $150.00 |
|
4th
Quarter 2009 |
|
|
15,400 |
|
|
$ |
1.05 |
|
Full
year 2009
|
|
|
1,000 |
|
|
$ |
100.00
/ $157.48 |
|
Natural Gas Sales (NYMEX HH)
Swaps
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
60.00
/ $80.00 |
|
4th
Quarter 2008
|
|
|
16,200 |
|
|
$ |
8.04 |
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
55.00
/ $76.20 |
|
Full
year 2009
|
|
|
15,400 |
|
|
$ |
8.50 |
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
55.00
/ $77.75 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
55.00
/ $77.70 |
|
Natural Gas Sales (NYMEX HH)
Collars
|
|
|
|
|
|
Floor/Ceiling
Prices
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
55.00
/ $83.10 |
|
4th
Quarter 2008
|
|
|
4,800 |
|
|
$ |
8.00
/ $9.50 |
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
60.00
/ $75.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
65.50
/ $78.50 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
280 |
|
|
$ |
80.00
/ $90.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
100.00
/ $161.10 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
100.00
/ $150.30 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
100.00
/ $160.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
100.00
/ $150.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2010
|
|
|
1,000 |
|
|
$ |
100.00
/ $158.50 |
|
|
|
|
|
|
|
|
|
|
Full
year 2011
|
|
|
270 |
|
|
$ |
80.00
/ $90.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil Sales (NYMEX WTI) Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Full
year 2008
|
|
|
335 |
|
|
$ |
92.00 |
|
|
|
|
|
|
|
|
|
|
Full
year 2009
|
|
|
240 |
|
|
$ |
71.50 |
|
|
|
|
|
|
|
|
|
|
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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 $100.00 per barrel while still participating in any oil
price increase up to the ceiling prices which range from $70.00 to $163.60 per
barrel on the volumes indicated above, and if 2) gas prices decline below
our floor price of $8.00 per MMBtu while still participating in any gas price
increase up to the ceiling price of $9.50 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 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 mark-to-market, could have a material
impact on earnings in any given quarter and, thus, add increased volatility to
our net income. The mark-to-market values reflect the liquidation values of such
hedges and not necessarily the values of the hedges if they are held to
maturity.
In November
2007 we entered into natural gas swaps at an index that did not correlate with
the index at which the gas is sold and therefore those 2008 gas hedges are not
highly effective. In January 2008 we entered into natural gas swaps which were
not highly effective at inception, so we subsequently entered into basis swaps
and established effectiveness at that time. Thus, we recognized unrealized net
gains of approximately $.6 million and unrealized net losses of approximately
$.2 million in the Statements of Income under the caption Commodity derivatives
for the three months ended September 30, 2008 and for the nine months ended
September 30, 2008, respectively.
Additionally,
in 2006 we entered into five year interest rate swaps for a fixed rate of
approximately 5.5% on $100 million of our outstanding borrowings under our
credit facility. These interest rate swaps have been designated as cash flow
hedges.
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 and are
booked at fair value.
Based on average NYMEX futures prices as of September 30, 2008 (WTI $103.73; HH $8.20) 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:
|
|
September
30, 2008
|
|
|
Impact
of percent change in futures prices
on
pretax future cash (payments) and receipts
|
|
|
|
NYMEX
Futures
|
|
|
|
-40 |
% |
|
|
-20 |
% |
|
|
+
20 |
% |
|
|
+40 |
% |
Average
WTI Futures Price (2008 – 2011)
|
|
$ |
103.73 |
|
|
$ |
62.24 |
|
|
$ |
82.98 |
|
|
$ |
124.48 |
|
|
$ |
145.22 |
|
Average
HH Futures Price (2008 – 2009)
|
|
|
8.20 |
|
|
|
4.92 |
|
|
|
6.56 |
|
|
|
9.85 |
|
|
|
11.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$ |
(243.6 |
) |
|
$ |
151.7 |
|
|
$ |
(9.7 |
) |
|
$ |
(416.5 |
) |
|
$ |
(589.4 |
) |
Natural
Gas gain/(loss) (in millions)
|
|
|
4.5 |
|
|
|
29.2 |
|
|
|
16.9 |
|
|
|
(7.3
|
) |
|
|
(19.5
|
) |
|
|
$ |
(239.1 |
) |
|
$ |
180.9 |
|
|
$ |
7.2 |
|
|
$ |
(423.8 |
) |
|
$ |
(608.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
(WTI $100.47; HH $7.71)
|
|
$ |
(27.1 |
) |
|
$ |
12.2 |
|
|
$ |
(2.7 |
) |
|
$ |
(51.0 |
) |
|
$ |
(75.2 |
) |
2009
(WTI $102.10; HH $8.33)
|
|
|
(120.6
|
) |
|
|
92.8 |
|
|
|
(0.2
|
) |
|
|
(208.4
|
) |
|
|
(296.3
|
) |
|
|
|
(89.9
|
) |
|
|
74.3 |
|
|
|
10.1 |
|
|
|
(160.8
|
) |
|
|
(231.7
|
) |
2011
(WTI $105.31)
|
|
|
(1.5
|
) |
|
|
1.6 |
|
|
|
- |
|
|
|
(3.6
|
) |
|
|
(5.7
|
) |
Total
|
|
$ |
(239.1 |
) |
|
$ |
180.9 |
|
|
$ |
7.2 |
|
|
$ |
(423.8 |
) |
|
$ |
(608.9 |
) |
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Interest
Rates. Our
exposure to changes in interest rates results primarily from long-term debt. In
October 2006, we issued, in a public offering, $200 million of 8.25% senior
subordinated notes due 2016. At September 30, 2008, total long-term
debt outstanding including our short-term Line of Credit, was $1.1 billion.
Interest on amounts borrowed under our credit facility is charged at LIBOR plus
1.25% to 1.875%, with the exception of the $100 million of principal for which
we have hedged the interest rate at approximately 5.5% plus the credit
facility’s margin through July 15, 2013. Based on September 30, 2008 credit
facility borrowings, a 1% change in interest rates would have an annual
$5.2 million after tax impact on our financial
statements.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
Item
4. Controls and
Procedures
|
As of
September 30, 2008, we have carried out an evaluation under the supervision of,
and with the participation of, our 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, 2008, 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 by
us 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 that occurred during
the three months ended September 30, 2008 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting. We may make changes in our internal control procedures from time to
time in the future.
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),” “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. 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 14 of our Form 10-K/A dated February 27, 2008, 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 Form
10-Q.
|
PART II. OTHER
INFORMATION
|
|
Item
1. Legal
Proceedings
|
None.
It is
possible that the borrowing base of our senior secured revolving credit facility
may decrease. Our borrowing base is subject to a semi-annual
redetermination each April and October and our Lenders and the Company have the
right to one incremental redetermination each year. Our borrowing
base of $1.25 billion that was confirmed on October 17, 2008 was determined
based on lender criteria which vary in commodity price by individual
lender. Should lender price assumptions decrease significantly, our
borrowing base may decrease to an amount less than our current outstanding in
which case we would be required to fund such deficiency. Subsequent
to a redetermination any amount outstanding in excess of our borrowing base must
be cured in two equal installments 90 and 180 days after our lenders give us
notice of such deficiency.
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
|
|
Item
5. Other
Information
|
None.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Exhibit
No. Description of
Exhibit
10.1*
|
Amended
and Restated Credit Agreement, by and among Berry Petroleum Company, Wells
Fargo Bank, N.A., and other financial institutions, dated July 15, 2008
(previously filed on July 25, 2008, as Exhibit 10.1 to Registrant’s
Quarterly Report on Form 10-Q File No
1-9735)
|
10.2
|
Credit
Agreement by and among Berry Petroleum Company, Société Générale, SG
Americas Securities, LLC, BNP Paribas Securities Corp., BNP Paribas, and
other financial institutions dated July 31,
2008
|
10.3*
|
First
Amendment to Amended and Restated Credit Agreement, by and between Berry
Petroleum Company, Wells Fargo Bank, N.A. and other financial
institutions, dated as of October 17, 2008 (previously filed on October
17, 2008, as Exhibit 10.1 to Registrant’s Current Report on Form 8-K File
No 1-9735)
|
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
32.1
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
32.2
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
*
Incorporated herein by reference
|
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
BERRY
PETROLEUM COMPANY
/s/ Shawn
M. Canaday
Shawn M.
Canaday
Vice
President and Controller
(Principal
Accounting Officer)
Date: October
29, 2008