UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
x Quarterly Report
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For the
quarterly period ended March
31, 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)
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DELAWARE
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77-0079387
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(State
of incorporation or organization)
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(I.R.S.
Employer Identification Number)
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5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's telephone number,
including area
code: (661)
616-3900
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. YES x NO o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, 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
April 15, 2008, the registrant had 42,664,779 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 April 15, 2008 all of which is held by
an affiliate of the registrant.
BERRY
PETROLEUM COMPANY
FIRST
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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Unaudited
Condensed Balance Sheets at March 31, 2008 and December 31,
2007
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3
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Unaudited
Condensed Statements of Income for the Three Month Periods Ended March 31,
2008 and 2007
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4
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Unaudited
Condensed Statements of Comprehensive Income for the Three Month Periods
Ended March 31, 2008 and 2007
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4
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Unaudited
Condensed Statements of Cash Flows for the Three Month Periods Ended March
31, 2008 and 2007
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5
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Notes
to Unaudited Condensed Financial Statements
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6
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Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
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11
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Item
3. Quantitative and Qualitative Disclosures About Market
Risk
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19
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Item
4. Controls and Procedures
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21
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PART
II.
OTHER
INFORMATION
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Item
1. Legal Proceedings
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22
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Item
1A. Risk Factors
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22
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Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
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22
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Item
3. Defaults Upon Senior Securities
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22
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Item
4. Submission of Matters to a Vote of Security Holders
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22
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Item
5. Other Information
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22
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Item
6. Exhibits
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22
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BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
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March
31, 2008
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December
31, 2007
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ASSETS
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Current
assets:
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Cash
and cash equivalents
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$
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2,679
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$
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316
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Accounts
receivable
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117,235
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117,038
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Fair
value of derivatives
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-
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2,109
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Prepaid expenses and other
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Total
current assets
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175,243
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161,019
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Oil
and gas properties (successful efforts basis), buildings and equipment,
net
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1,333,578
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1,275,091
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Other
assets
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15,308
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15,996
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$
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1,524,129
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$
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1,452,106
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LIABILITIES
AND SHAREHOLDERS' EQUITY
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Accounts
payable
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$
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112,312
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$
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90,354
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Revenue and royalties payable
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Accrued
liabilities
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26,068
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21,653
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Fair
value of derivatives
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130,338
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95,290
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Total current liabilities
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Deferred
income taxes
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134,694
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128,824
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Abandonment
obligation
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36,310
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36,426
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Other long-term liabilities
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Fair value of derivatives
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764,558
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720,763
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Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
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-
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-
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Capital stock, $.01 par value:
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Class
A Common Stock, 100,000,000 shares authorized; 42,663,779 shares issued
and outstanding (42,583,002 in 2007)
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426
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425
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Class B Stock, 3,000,000 shares authorized; 1,797,784 shares
issued and outstanding (liquidation preference of $899) (1,797,784 in
2007)
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Capital
in excess of par value
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70,967
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66,590
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Accumulated
other comprehensive loss
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(163,680
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)
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(120,704
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Total
shareholders' equity
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461,080
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459,974
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$
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1,524,129
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$
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1,452,106
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The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Three
Month Periods Ended March 31, 2008 and 2007
(In
Thousands, Except Per Share Data)
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Three
months ended March 31,
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REVENUES
AND OTHER INCOME ITEMS
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Interest and other income, net
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185,397
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117,479
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Operating
costs - oil and gas production
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41,629
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33,610
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Operating costs - electricity generation
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Production
taxes
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5,967
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3,815
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Depreciation,
depletion & amortization - oil and gas production
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27,076
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18,725
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Depreciation, depletion & amortization - electricity
generation
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Gas
marketing
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2,982
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-
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General
and administrative
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11,383
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10,307
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Commodity
derivatives
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708
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-
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Dry
hole, abandonment, impairment and exploration
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4,126
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649
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114,701
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86,330
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Income
before income taxes
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70,696
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31,149
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Provision
for income taxes
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Basic
net income per share
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Diluted
net income per share
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Weighted
average number of shares of capital stock outstanding used to calculate
basic net income per share
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Effect
of dilutive securities:
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Equity
based compensation
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795
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603
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Director deferred compensation
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Weighted
average number of shares of capital stock used to calculate diluted net
income per share
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Unaudited
Condensed Statements of Comprehensive Income
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Three
Month Periods Ended March 31, 2008 and 2007
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(In
Thousands)
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Unrealized
gains (losses) on derivatives, net of income tax benefits of ($40,349) and
($7,885), respectively
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Reclassification
of realized gains (losses) on derivatives included in net income, net of
income taxes (benefit) of $11,698 and ($361), respectively
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17,547
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(542
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)
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The accompanying notes are an integral
part of these financial statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Three
Month Periods Ended March 31, 2008 and 2007
(In
Thousands)
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Three
months ended March 31,
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Cash
flows from operating activities:
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Depreciation, depletion and amortization
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Dry
hole and impairment
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2,728
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187
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Stock-based compensation expense
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Deferred
income taxes
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22,082
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12,311
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Gain
on sale of oil and gas properties
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(415
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)
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-
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Other,
net
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491
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209
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Cash paid for abandonment
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Increase in current assets other than cash and cash
equivalents
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Decrease
in current liabilities other than book overdraft, line of credit and fair
value of derivatives
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(14,389
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)
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(28,119
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Net
cash provided by operating activities
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87,235
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6,906
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Cash
flows from investing activities:
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Exploration
and development of oil and gas properties
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Property
acquisitions
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(261
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)
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(1,088
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)
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Additions to vehicles, drilling rigs and other fixed
assets
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Deposit on potential sale of asset
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Proceeds from sale of assets
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Net
cash used in investing activities
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Cash
flows from financing activities:
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Proceeds
from issuances on line of credit
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100,600
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21,000
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Payments
on line of credit
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(104,700
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)
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(30,000
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)
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Proceeds
from issuance of long-term debt
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69,200
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90,000
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Payments on long-term debt
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Dividends
paid
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(3,327
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)
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(3,295
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)
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Proceeds from stock option exercises
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Excess tax benefit and other
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Net
cash (used in) provided by financing activities
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Net
increase (decrease) in cash and cash equivalents
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Cash
and cash equivalents at beginning of year
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316
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416
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Cash
and cash equivalents at end of period
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$
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2,679
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$
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95
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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
March 31, 2008 and December 31, 2007 and results of operations and cash
flows for the three month periods ended March 31, 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 March 31, 2008 and
December 31, 2007 is $12.4 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 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, this error has been corrected
during the quarter ended March 31, 2008, with the effect of increasing our sales
of oil and gas and accounts receivable by $10.5 million and $2.4 million,
respectively, and reducing our royalties payable by $8.1 million.
In
December 2007, we entered into a second long-term (ten year) firm transportation
contract for our Colorado natural gas production. This contract is for 25,000
MMBtu/D on the Rockies Express (REX) pipeline for gas production in the Piceance
basin. We have a total of 35,000 MMBtu/D contracted on the REX pipeline. We
pay a demand charge for this capacity and our own production did not fill that
capacity. In order to use as much of the transport as possible, we bought our
partners’ share of the gas produced in the Piceance at the market rate for that
area. We then used our excess transport to move this gas to where it was
eventually sold. The net of our gas marketing revenue and our gas marketing
expense in the Statements of Income is $.2 million in the first quarter ended
March 31, 2008. Our production will eventually reach our firm transportation
capacity on this contract.
In the
first quarter of 2008, we had two items in the dry hole, abandonment, impairment
and exploration expense. Technical difficulties on three wells in the Piceance
basin were encountered before reaching total depth and these holes were
abandoned, for approximately $2.7 million in cost, in favor of drilling to the
same bottom hole location by drilling a new well. In addition, we had $1.4 million of
exploration expense in the DJ basin.
In the
first quarter of 2008, we renegotiated a price-sensitive royalty that burdens
certain of our properties resulting in an increase to net income of $1.4 million
in the first quarter of 2008. We completed negotiations and are finalizing this
amendment which will be a permanent reduction assuming we attain a minimum steam
injection level.
We have
decided we will not proceed with our previously announced plans to organize a
master limited partnership (MLP) due to the unfavorable capital market
conditions. We expensed $.6 million of legal and accounting fees related to the
formation of the MLP.
Proceeds
from the sale of our Prairie Star assets are $1.8 million in the Statements of
Cash Flows and the gain from that sale is $.4 million in the Statements of
Income in the first quarter ended March 31, 2008.
2.
|
Recent Accounting
Developments
|
In
December 2007, the Financial Accounting Standards Board (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 the same as that of the related Statement 141(R).
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
2.
|
Recent Accounting Developments
(Cont’d)
|
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 noncontrolling 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 it 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. Enhanced 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 the additional disclosures
described above.
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 at January 1, 2008.
Determination
of fair value
We have
an established and well-documented process for determining fair values. Fair
value is based upon quoted market prices, where available. To ensure that the
valuations are appropriate, we have various controls in place. These include:
identification of the inputs to the fair value methodology through review of
counterparty statements and other supporting documentation, and 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 are quoted prices (unadjusted) for
identical assets or liabilities in active markets.
• Level
2 - inputs to the valuation methodology 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 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.
Our oil
swaps, natural gas swaps and interest rate swaps are valued using the
counterparties’ marked-to-market statements which are validated by our
internally developed models and are classified within Level 2 of the valuation
hierarchy. Derivatives that are valued based upon models with significant
unobservable market inputs 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.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
3.
|
Fair Value Measurement
(Cont’d)
|
Assets
and liabilities measured at fair value on a recurring basis
March
31, 2008 (in millions)
|
Total
carrying value on the condensed Balance Sheet
|
Level
2
|
Level
3
|
|
|
|
|
Commodity
derivatives
|
$
265.0
|
$
21.1
|
$
243.9
|
Interest
rate swaps
|
8.5
|
8.5
|
-
|
Total
liabilities at fair value
|
$
273.5
|
$
29.6
|
$
243.9
|
Changes
in Level 3 fair value measurements
The table below includes a rollforward
of the Balance Sheet amounts for the first quarter of 2008 (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).
Three
months ended March 31, 2008 (in millions)
|
|
|
|
|
|
|
|
Fair
value, January 1, 2008
|
$
194.3
|
|
|
Total
realized and unrealized gains and (losses) included in Sales of oil and
gas
|
75.6
|
|
|
Purchases,
sales and settlements, net
|
(25.9)
|
|
|
Transfers
in and/or out of Level 3
|
-
|
|
|
Fair
value, March 31, 2008
|
$
243.9
|
|
|
|
|
|
|
Total
unrealized gains and (losses) included in income related to financial
assets and liabilities still on the condensed Balance Sheet at
March 31, 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, as
provided in the Statement.
The
related cash flow impact of all of our hedges is reflected in cash flows from
operating activities. At March 31, 2008, our net fair value of derivatives
liability was $273.6 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 March 31, 2008, we expect to make hedge payments under the
existing derivatives of $128.8 million during the next twelve months. At March
31, 2008, Accumulated Other Comprehensive Loss consisted of $163.7 million, net
of tax, of unrealized losses from our crude oil and natural gas swaps and
collars that qualified for hedge accounting treatment at March 31, 2008.
Deferred net losses recorded in Accumulated Other Comprehensive Loss at March
31, 2008 and subsequent marked-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.
|
These
hedges have been designated as cash flow hedges in accordance with SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities. These swaps were not highly
effective at inception, so we subsequently entered into basis swaps and
established effectiveness at that time. In 2007, we also entered into natural
gas swap contracts that were not highly effective. Thus, we recognized an
unrealized net loss of approximately $.7 million on the income statement under
the caption “Commodity derivatives” for the three months ended March 31,
2008.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
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 three months ended March 31, 2008 (in thousands):
Beginning
balance at January 1
|
|
$
|
36,426
|
|
|
|
|
Liabilities
settled
|
|
|
(971
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance at March 31
|
|
|
|
|
|
|
|
The
effective tax rate was 39% for the first quarter of 2008 compared to 37%
for the fourth quarter of 2007 and 39% for the first quarter of 2007. Our rate
differs from the combined federal and state statutory tax rate (net of the
federal benefit), primarily due to certain business incentives.
As of
March 31, 2008, we had a gross liability for uncertain tax benefits of
$13 million of which $10.6 million, if recognized, would affect the
effective tax rate. There were no significant changes to the calculation since
year end 2007.
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.
7.
|
Long-term
and Short-term Debt Obligations
|
Short-term
debt
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. At March 31, 2008 the
outstanding balance under this Line of Credit was $10.2 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 March 31, 2008 was 3.7%.
Long-term
debt
In 2006,
we issued in a public offering $200 million of 8.25% senior subordinated notes
due 2016 (the Notes). The deferred costs of approximately $5 million associated
with the issuance of this debt are being amortized over the ten year life of the
Notes.
We have a
senior unsecured bank credit facility agreement (the Agreement) with a banking
syndicate through June 30, 2011. The Agreement is a revolving credit facility
for up to $750 million. In 2007, we increased our borrowing base to $550 million
and in the second quarter of 2008, we increased our annual borrowing base to
$650 million with a funding commitment from our banking syndicate to $600
million. The outstanding Line of Credit reduces our borrowing capacity
available under the Agreement.
The total
outstanding debt at March 31, 2008 under the credit facility and the short-term
Line of Credit was $245 million and $10.2 million, respectively, leaving $295
million in borrowing capacity available. Interest on amounts borrowed under this
debt is charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate, with
margins on the various rate options based on the ratio of credit outstanding to
the borrowing base. We are required under the Agreement to pay an annual
commitment fee of .25% to .375% on the unused portion of the credit
facility.
The
maximum amount available is subject to an 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.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
7.
|
Long-term
and Short-term Debt Obligations
(Cont’d)
|
The
Agreement contains restrictive covenants which, among other things, require us
to maintain a certain debt to EBITDA ratio and a minimum current ratio, as
defined. The $200 million Notes are subordinated to our credit facility
indebtedness. As long as the interest coverage ratio (as defined) is met, we may
incur additional debt. We were in compliance with all covenants as of March 31,
2008. The weighted average interest rate on total outstanding borrowings at
March 31, 2008 was 5.7%.
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. These interest rate swaps have been designated
as cash flow hedges.
8.
|
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.
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 will increase its total purchased volumes to 5,000 Bbl/D
beginning June 29, 2008 through June 2013, as provided in our contract. Pricing
under the contract, which includes transportation and gravity adjustments, is at
a fixed percentage of WTI.
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 month periods ended March 31, 2008 and 2007 and our financial condition,
liquidity and capital resources as of March 31, 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 world supply and demand.
The aggregate amount of oil and gas produced may fluctuate based on the success
of development and exploitation of oil and gas reserves pursuant to current
reservoir management. The cost of natural gas used in our steaming operations
and electrical generation, production rates, labor, equipment costs, maintenance
expenses, and production taxes are expected to be the principal influences on
operating costs. Accordingly, our results of operations may fluctuate from
period to period based on the foregoing principal factors, among
others.
Overview. 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:
·
|
Developing
our existing resource base
|
·
|
Acquiring
additional assets with significant growth
potential
|
·
|
Utilizing
joint ventures with respected partners to enter new
basins
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
·
|
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
Notable
First Quarter Items.
·
|
Production
averaged 28,066 BOE/D, up 10% from the first quarter of
2007
|
·
|
Renegotiated
an ongoing royalty which resulted in an increase to net income of $1.4
million in the first quarter of
2008
|
·
|
Production
at Poso Creek averaged 2,700 Bbl/D, up 13% from the fourth quarter of
2007
|
·
|
Increased
Piceance net average production to 16.8 MMcf/D, up 15% from the fourth
quarter 2007
|
·
|
Corrected
our calculation of certain royalties payable over the last three years
which resulted in a one time cumulative increase to net income of $6.4
million in the first quarter of
2008
|
·
|
Announced
headquarters relocation in 2008 to Denver,
Colorado
|
Notable
Items and Expectations for the Second Quarter of 2008.
·
|
Targeting
a production average above 29,000 BOE/D and an exit rate of 30,000 BOE/D
in the second quarter of 2008
|
·
|
Drilling
wells, increasing steam generation capacity and adding supporting
infrastructure to increase production at
diatomite
|
·
|
Received
an upgrade of our corporate credit rating to “BB” and senior subordinated
note rating to “B+” by Standard & Poor’s Rating
Service
|
·
|
Moody’s
Investors Services placed our corporate rating and senior subordinated
note rating under review for possible
upgrade
|
·
|
Increased
our credit facility annual borrowing base to $650 million from $550
million
|
Overview of the
First Quarter of 2008. We had net income of $43 million, or $.95 per
diluted share and net cash from operations was $87 million. We drilled 145 gross
wells and capital expenditures, excluding property acquisitions, totaled $77
million. We experienced no increase in debt in the first quarter of 2008
compared to the fourth quarter of 2007. We achieved average production of 28,066
BOE/D in the first quarter of 2008, up .2% from an average of 28,023 BOE/D in
the fourth quarter of 2007. Our 2008 $295 million capital program is designed to
achieve at least a 10% increase in production and a 10% increase in reserves at
a very competitive finding and development cost while being funded entirely out
of internally generated cash flow from operations. We renegotiated a
price-sensitive royalty that burdens certain of our production resulting in an
increase to net income of $1.4 million in the first quarter of 2008. We
completed negotiations and are finalizing this amendment which will be a
permanent reduction assuming we attain a minimum steam injection level. We
expect that our royalty burden will be reduced by approximately $10 million in
2008 based on current prices and our production plans.
Results of
Operations. The following
companywide results are in millions (except per share data) for the three months
ended:
|
|
March
31, 2008
(1Q08)
|
|
March
31, 2007
(1Q07)
|
1Q08
to 1Q07 Change
|
December
31, 2007
(4Q07)
|
1Q08
to 4Q07
Change
|
Sales
of oil
|
|
$
|
131
|
|
$
|
81
|
62%
|
$
|
109
|
20%
|
Sales
of gas
|
|
|
33
|
|
|
21
|
57%
|
|
24
|
38%
|
Total
sales of oil and gas
|
|
$
|
164
|
|
$
|
102
|
61%
|
$
|
133
|
23%
|
Sales
of electricity
|
|
|
16
|
|
|
15
|
7%
|
|
15
|
7%
|
Other
revenues
|
|
|
5
|
|
|
1
|
400%
|
|
5
|
-%
|
Total
revenues and other income
|
|
$
|
185
|
|
$
|
118
|
57%
|
$
|
153
|
21%
|
Net
income
|
|
$
|
43
|
|
$
|
19
|
126%
|
$
|
32
|
34%
|
Earnings
per share (diluted)
|
|
$
|
.95
|
|
$
|
.42
|
126%
|
$
|
.71
|
34%
|
Global
and California crude oil demand continues to remain strong although pricing is
volatile. Product prices continued to exhibit an overall-strengthening trend in
2008. Oil is a globally priced commodity and is priced according to the supply
and demand of crude oil and its products. Other dominant factors in the pricing
of our crude oil include the condition of the global economy and political
tension in or near oil producing regions. We expect that crude prices will
continue to be volatile in 2008.
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 March 31, 2008 were 20% higher than the three months ended
December 31, 2007 resulting from price increases of 21% and sales volume
increases of 2%. Gas sales in the three months ended March 31, 2008 were 38%
higher than the three months ended December 31, 2007 resulting from production
increases of 2% and a price increase of 36%. Management estimates that
for 2008, a $1.00 per MMBtu change in NYMEX Henry Hub natural gas prices would
result in a $3 million change in annual net income, demonstrating our relative
insensitivity to natural gas prices companywide.
In 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, this error has been corrected
during the quarter ended March 31, 2008, with the effect of increasing our sales
of oil and gas and accounts receivable by $10.5 million and $2.4 million,
respectively, and reducing our royalties payable by $8.1 million.
Operating
data. The following table is for the three months ended:
|
|
|
March
31, 2008
|
%
|
|
March
31, 2007
|
%
|
|
December
31, 2007
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,375
|
58
|
|
16,140
|
63
|
|
16,595
|
59
|
Light
Oil Production (Bbl/D)
|
|
|
3,510
|
13
|
|
3,233
|
13
|
|
3,395
|
12
|
Total
Oil Production (Bbl/D)
|
|
|
19,885
|
71
|
|
19,373
|
76
|
|
19,990
|
71
|
Natural
Gas Production (Mcf/D)
|
|
|
|
|
|
|
|
|
|
|
Total
(BOE/D)
|
|
|
28,066
|
100
|
|
25,490
|
100
|
|
28,023
|
100
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas, per BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
|
|
|
|
|
|
|
|
|
Average
sales price after hedging
|
|
|
60.43
|
|
|
43.84
|
|
|
52.32
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
97.82
|
|
$
|
58.23
|
|
$
|
90.50
|
|
Price
sensitive royalties
|
|
|
(4.47
|
)
|
|
(3.74
|
)
|
|
(6.68
|
)
|
Quality
differential and other
|
|
|
(10.78
|
)
|
|
(8.78
|
)
|
|
(9.92
|
)
|
Crude
oil hedges
|
|
|
(15.60
|
)
|
|
.03
|
|
|
(13.57
|
)
|
Correction
to royalties payable
|
|
|
5.85
|
|
|
-
|
|
|
-
|
|
Average
oil sales price after hedging
|
|
$
|
72.82
|
|
$
|
45.74
|
|
$
|
60.33
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas price:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price per MMBtu
|
|
$
|
8.74
|
|
$
|
7.18
|
|
$
|
7.39
|
|
Conversion
to Mcf
|
|
|
.42
|
|
|
.34
|
|
|
.35
|
|
Natural
gas hedges
|
|
|
(.12
|
)
|
|
.13
|
|
|
.91
|
|
Location,
quality differentials and other
|
|
|
(1.61
|
)
|
|
(1.37
|
)
|
|
(3.21
|
)
|
Average
gas sales price after hedging
|
|
$
|
7.43
|
|
$
|
6.28
|
|
$
|
5.44
|
|
|
Gas Basis
Differential. Natural gas prices in the Rockies have stabilized
since the start of interim service on the REX pipeline in January 2008.
The basis differential between Henry Hub (HH) and Colorado Interstate Gas
(CIG) index has narrowed, as anticipated, due to the increased take away
capacity added by the REX pipeline. We have contracted a total of 35,000
MMBtu/D on this pipeline under two separate transactions to provide firm
transport for our Piceance basin gas production. In the first quarter of
2008, the CIG basis differential per MMBtu, based upon first-of-month
values, averaged $1.07 below HH and ranged from $.91 to $1.19 below HH.
Although related to CIG, the actual basin price varies. Gas from the
Piceance basin traded slightly below the CIG price while Uinta basin gas
sold for approximately $.15 below CIG pricing. After the REX startup in
2008, all of the Piceance basin gas was sold at mid-continent (ANR and
NGPL) indexes which averaged approximately $.17 above the CIG index
pricing before the cost of transportation was included.
|
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 $.85 below the HH index before the cost of transportation
is considered. The remainder of the DJ Basin gas is sold slightly above the CIG
index price.
Gas Marketing.
In December 2007, we entered into a second long-term (ten year) firm
transportation contract for our Colorado natural gas production. This 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 transport to move this gas to
where it was eventually sold. The net of our gas marketing revenue and our
gas marketing expense in the Statements of Income is $.2 million in the first
quarter ended March 31, 2008. Eventually our own production will reach and
exceed our firm transportation capacity on this contract.
Oil Contracts.
Utah - During 2007, our Utah light crude oil was sold under multiple
contracts with different purchasers for varying pricing terms, and in some cases
our realized price was further reduced by transportation charges. As operator we
deliver all produced volumes pursuant to these contracts, although our working
interest partners or royalty owners may take their respective volumes in kind
and market their own volumes. Our Utah crude oil is a paraffinic crude and can
be processed efficiently by only a limited number of refineries within the
region. Increased production of crude oil in the region, the ability of refiners
to process other higher sulfur crudes as a result of capital upgrades, as well
as the increasing availability of Canadian crude oil, put downward pressure on
the sales price of our crude oil.
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 will increase its total
purchased volumes to 5,000 Bbl/D beginning June 29, 2008 through June 2013, as
provided in our contract. Gross oil production averaged approximately 4,200
BOE/D in the quarter ended March 31, 2008 and we are evaluating options on a
quarterly basis to meet the contractual volume. Pricing under the contract,
which includes transportation and gravity adjustments, is at a fixed percentage
of WTI. As global and regional prices of crude oil increased since we entered
into this contract, we are receiving crude oil prices below the posted price,
although this posted price is thinly traded and does not necessarily indicate
the actual price at which a seller can market their crude oil. While our price
differentials have widened as the crude oil price increased, we are able to sell
100% of our crude oil.
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 we purchased. We purchase and transport 12,000
average MMBtu/D on the Kern River Pipeline under our firm transportation
contract and use this gas to produce conventional and 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 prices less than 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
MMBtu/D as fuel for use in our cogeneration facilities in the year ended
December 31, 2007. Rockies natural gas differentials have stabilized near
their historical levels and we do not expect to have significant positive
electricity margins in 2008. We 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. On September 20, 2007, the CPUC
issued a decision (SRAC Decision) that changes prospectively 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. Based on our
preliminary analysis, we do not believe that the proposed pricing changes will
materially affect us in 2008.
The
following table is for the three months ended:
|
|
|
March
31, 2008
|
|
|
March
31, 2007
|
|
|
December
31, 2007
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
15.9
|
|
$
|
14.6
|
|
$
|
14.9
|
|
Operating
costs (in millions)
|
|
|
16.4
|
|
|
14.2
|
|
|
11.0
|
|
Electric
power produced - MWh/D
|
|
|
2,152
|
|
|
2,117
|
|
|
2,099
|
|
Electric
power sold - MWh/D
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
7.94
|
|
$
|
6.70
|
|
$
|
6.10
|
|
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)
|
|
|
|
March
31, 2008
|
|
March
31, 2007
|
|
December
31, 2007
|
|
March
31, 2008
|
|
March
31, 2007
|
|
December
31, 2007
|
|
Operating
costs – oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
4.46
|
|
|
4.49
|
|
|
4.24
|
|
|
11,383
|
|
|
10,307
|
|
|
10,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
35.16
|
|
$
|
30.65
|
|
$
|
33.22
|
|
$
|
89,793
|
|
$
|
70,749
|
|
$
|
85,630
|
|
Our total
operating costs, production taxes, DD&A, G&A and interest expenses for
the three months ended March 31, 2008, stated on a unit-of-production basis,
increased 15% over the three months ended March 31, 2007 and increased 6% as
compared to the three months ended December 31, 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:
|
|
March
31, 2008
(1Q08)
|
March
31, 2007
(1Q07)
|
1Q08
to 1Q07
Change
|
December
31, 2007
(4Q07)
|
1Q08
to 4Q07
Change
|
Average
volume of steam injected (Bbl/D)
|
91,326
|
86,132
|
6%
|
90,894
|
1%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
7.94
|
$
6.70
|
19%
|
$
6.10
|
30%
|
As we
remain in a strong commodity price environment, we anticipate that cost
pressures within our industry may continue due to greater field activity and
rising service costs in general. Based on current plans, we are targeting
average steam injection in 2008 of approximately 110,000 BSPD or a 25% increase
compared to 2007.
·
|
Production
taxes: Our production taxes have increased compared to the first and the
fourth quarters of 2007 as commodity prices and thus the values of our oil
and natural gas has increased. Severance taxes, which are prevalent in
Utah and Colorado, 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 track oil and
gas prices generally.
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE by 30% in the
first three months of 2008 as compared to the first three months of 2007
due to an increase in capital spending in fields with higher drilling and
leasehold acquisition costs, which is in line with our expectations.
DD&A per BOE was similar to the fourth quarter of 2007 as our capital
expenditures have remained
consistent.
|
·
|
General
and administrative: Approximately 70% of our G&A is related to
compensation. The primary reasons for the increase in G&A during the
first quarter of 2008 was recording to expense $.6 million of previously
capitalized legal and accounting fees related to the formation of an
MLP.
|
·
|
Interest
expense: Our total outstanding borrowings were approximately
$455 million at March 31, 2008 compared to $477 million and $459
million at March 31, 2007 and December 31, 2007, respectively. For the
three months ended March 31, 2008, $4.5 million of interest cost has been
capitalized and we expect to capitalize approximately $20 million of
interest cost during the full year of
2008.
|
Estimated 2008
Oil
and Gas Operating, G&A and
Interest Expenses.
We estimate our average 2008 production volume will range between 29,500 BOE/D
and 30,500 BOE/D. Based on actual first quarter and the remainder of 2008 at
NYMEX WTI crude oil price of $100 per barrel and NYMEX HH natural gas price of
$10.00 per MMBtu, we expect our expenses to be within the following
ranges:
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2008
per
BOE
|
|
|
|
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
17.75
to 19.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A
– oil and gas production
|
|
|
|
|
|
|
|
|
|
|
G&A
|
|
|
4.00
to 4.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
35.05
to 38.60
|
|
|
|
|
|
|
|
(1)
We expect operating costs to increase in 2008 as compared to 2007 due to higher
projected natural gas costs.
Income
Taxes. We experienced an effective tax rate in the three months
ended March 31, 2008 of 39%, which is in line with our projections. 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 6 to
the unaudited condensed financial statements.
Development, Exploitation and
Exploration
Activity. We drilled 145 gross (128 net) wells during the first quarter
of 2008. As of March 31, 2008, we have four rigs drilling on our properties
under long-term contracts and six more under short term contracts.
Drilling
Activity. The following table sets
forth certain information regarding drilling activities (including operated and
non-operated wells):
Properties
We have
six asset teams as follows: South Midway-Sunset (S. Midway), North Midway-Sunset
including diatomite (N. Midway), Southern California including Poso Creek and
Placerita (S. Cal), Piceance, Uinta and DJ.
S. Midway
– During the three months ended March 31, 2008, production averaged
approximately 9,200 Bbl/D compared to approximately 9,500 Bbl/D and 9,100 Bbl/D
during the three month periods ended March 31, 2007 and December 31, 2007,
respectively. We will invest $31 million on our S. Midway properties in 2008 to
drill additional deeper horizontal wells along the cold, unswept flanks of the
reservoir. Additional vertical wells will also be drilled to provide steam
support for these horizontal wells. The first seven of the horizontal wells plus
the vertical steam support wells have been drilled and are performing as
expected. We plan to drill the remaining locations during the second quarter of
2008. We will also be developing the Monarch reservoir on our legacy Ethel D
property. In 2008, we plan on drilling 33 wells including a four pattern steam
flood pilot project at Ethel D. During the first quarter we drilled and
completed six of these wells and these wells are currently being steamed. We are
currently in the process of drilling the remaining 27 wells.
N. Midway
– During the three months ended March 31, 2008, production from the area
averaged approximately 2,400 Bbl/D compared to approximately 1,600 Bbl/D and
2,400 Bbl/D during the three month periods ended March 31, 2007 and December 31,
2007, respectively. In October 2007, we embarked on a full-scale, continuous
development program of the Diatomite and we expect to drill non-stop over the
next four years. Over 70 new producers have been drilled since October 2007. We
have just recently started to bring these wells on line as the necessary
infrastructure was installed to adequately steam and produce these wells. We
will nearly triple our producing well count this year from 80 wells at the end
of 2007 to approximately 240 wells by year end 2008. Steam injection necessary
to support our development will also increase dramatically. Our steam generation
capacity, which stood at approximately 10,000 BSPD at the end of 2007, will
increase by 150% to 25,000 BSPD by the end of 2008. The additional wells, steam
and supporting infrastructure should enable us to increase production which
averaged 1,400 BOE/D during the first quarter of 2008 to over 3,000 BOE/D by
year end 2008.
S. Cal –
During the three months ended March 31, 2008, production averaged approximately
4,800 Bbl/D compared to approximately 4,800 Bbl/D and 4,700 Bbl/D during the
three month periods ended March 31, 2007 and December 31, 2007, 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 April 2008, 26 of the
28 planned producers have been drilled and production has continued to increase
and is currently up to 3,200 BOE/D. The remaining producers and steam flood
pattern injectors will be drilled over the second quarter of 2008 and should
help further improve our production.
Piceance – During the
first quarter of 2008, production from the Piceance averaged 16.8 MMcf/D, an
increase of 15% over the fourth quarter of 2007. Of the Berry operated wells, we
drilled 15 gross wells (9 net) during the first quarter of 2008. We are
currently drilling our 20th well of the year and the 90th well since we acquired
our original Piceance basin acreage in early 2006. We continue to operate four
drilling rigs while we continue to see further efficiencies with repeated
drilling durations of 14 to 16 days for a mesa well. We expect significant gains
over the next quarter as we move into the prime summer completion season. The
production of the wells is as expected with the 30 day initial production rates
slightly above our target of 1.2 MMcf/D. In the first quarter of 2008, technical
difficulties on three wells were encountered before reaching total depth and
these holes were abandoned, for approximately $2.7 million in cost, in favor of
drilling to the same bottom hole location by drilling a new well.
Over the
last two years we have re-engineered our mesa drilling operations. We have made
significant investments constructing the needed infrastructure to support our
operations, and we now are realizing improved economic returns as our
manufacturing
process
developing this long term asset continues to improve. Additionally, those
returns are substantially enhanced due to the strong natural gas market and our
ability to transport our gas on the recently opened REX pipeline.
Uinta
–
Average daily production during the first quarter from all Uinta basin
assets was approximately 5,700 net BOE/D. We continue to have one drilling rig
operating in the basin. The development at Brundage Canyon continues to be
focused on drilling the high graded areas in the core of the field where we have
drilled nine wells in the first quarter of 2008 and increased our Uinta
production to an exit rate of over 6,000 BOE/D. Evaluating the waterflood
feasibility at Brundage Canyon has progressed with the selection a final pilot
waterflood pattern and we have begun the permitting process, with first
injection expected by year end 2008. Starting in the second quarter we
anticipate further delineating the Ashley Forest with drilling six to ten wells
under our current environmental approvals and we will 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 first
quarter of 2008, we drilled 37 successful gross Niobrara development wells in
Yuma County, Colorado, with a 100% success rate. Average daily production in the
DJ for the first quarter of 2008 was 18.9 net MMcf/D and we had $1.4 million of
exploration expense in the first quarter. Currently we are interpreting an
additional 75 square miles of 3-D seismic that we acquired over the winter and
anticipate this will continue to replenish and add to our sizeable inventory of
low risk development locations and allow many more years of
drilling.
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 have a senior unsecured revolving bank credit
facility agreement (the Agreement) with a banking syndicate through June 30,
2011. The Agreement is a revolving credit facility for up to $750 million. In
2007, we increased our borrowing base to $550 million and in the second quarter
of 2008, we increased our annual borrowing base to $650 million with a funding
commitment from our banking syndicate to $600 million. In October 2006, we
completed the sale of $200 million of ten year 8.25% senior subordinated
notes.
As of
March 31, 2008, we had total borrowings under the Agreement and Line of Credit
of $255.2 million and $200 million under our senior subordinated ten year
notes.
Capital
Expenditures. We establish a capital
budget for each calendar year based on our development opportunities and the
expected cash flow from operations for that year. Acquisitions are typically
debt financed. We may revise our capital budget during the year as a result of
acquisitions and/or drilling outcomes or significant changes in cash flows.
Excess cash generated from operations is expected to be applied toward
acquisitions, debt reduction or other corporate purposes.
In 2008,
we have a capital program of approximately $295 million, excluding acquisitions.
The capital development program may be revised due to realized commodity prices
and price expectations, equipment availability, permitting and/or changes in our
internal development plans. Our 2008 expenditures will be directed toward
developing reserves, increasing oil and gas production and exploration
opportunities. For 2008, we plan to invest approximately $118 million, or 40%,
in our heavy crude oil assets, and $175 million, or 59%, in our natural gas and
light oil assets. Capital expenditures, excluding property acquisitions, totaled
$77 million during the three months ended March 31, 2008.
Working Capital
and Cash Flows. Cash flow from
operations is dependent upon the price of crude oil and natural gas and our
ability to increase production and manage costs. Crude oil and gas sales in the
three months ended March 31, 2008 were 23% higher than the three months ended
December 31, 2007 resulting from a 21% increase in oil prices (see graphs on
page 12) and a 36% increase in gas prices (see graphs on page 12) and
production increases in natural gas, partially offset by production declines in
oil. Proceeds from the sale of our Prairie Star assets are $1.8 million in the
Statements of Cash Flows and the gain from that sale is $.4 million in the
Statements of Income in the first quarter ended March 31,
2008.
Our
working capital balance fluctuates as a result of the amount of borrowings and
the timing of repayments under our credit arrangements. We use our long-term
borrowings under our credit facility primarily to fund property acquisitions.
Generally, we use excess cash to pay down borrowings under our credit
arrangement. As a result, we often have a working capital deficit or a
relatively small amount of positive working capital.
The table
below compares financial condition, liquidity and capital resources changes for
the three month periods ended (in millions, except for production and average
prices):
|
March
31, 2008
(1Q08)
|
March
31, 2007
(1Q07)
|
1Q08
to 1Q07 Change
|
December
31, 2007
(4Q07)
|
1Q08
to 4Q07 Change
|
Average
production (BOE/D)
|
28,066
|
25,490
|
10%
|
28,023
|
-%
|
Average
oil and gas sales prices, per BOE after hedging
|
$
60.43
|
$
43.84
|
38%
|
$
52.32
|
16%
|
Net
cash provided by operating activities (1)
|
$
87
|
$
7
|
1,143%
|
$
57
|
53%
|
Working
capital
|
$
(123)
|
$
(72)
|
(71%)
|
$
(110)
|
(12%)
|
Sales
of oil and gas
|
$ 164
|
$
102
|
61%
|
$
133
|
23%
|
Total
debt
|
$
455
|
$477
|
(5%)
|
$
459
|
(1%)
|
Capital
expenditures, including acquisitions and deposits on
acquisitions
|
$
77
|
$
76
|
1%
|
$
76
|
1%
|
Dividends
paid
|
$
3.3
|
$
3.3
|
-%
|
$
3.3
|
-%
|
(1) 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.
Contractual
Obligations. Our contractual
obligations as of March 31, 2008 are as follows (in millions):
|
|
|
Total
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Thereafter
|
Total
debt and interest
|
|
$
|
629.8
|
$
|
29.8
|
$
|
25.7
|
$
|
25.7
|
$
|
266.1
|
$
|
16.5
|
$
|
266.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
lease obligations
|
|
|
17.6
|
|
1.8
|
|
2.2
|
|
2.1
|
|
2.1
|
|
2.1
|
|
7.3
|
Drilling
and rig obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
922.1
|
$
|
64.6
|
$
|
67.6
|
$
|
56.8
|
$
|
310.8
|
$
|
39.2
|
$
|
383.1
|
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 March 31, 2008 we have
drilled 15 of these wells.
Other
Obligations.
We
adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of March 31, 2008, we had a gross
liability for uncertain tax benefits of $13 million of which $10.6 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. Gross
oil production averaged approximately 4,200 BOE/D in the quarter ended March 31,
2008 and we are evaluating options on a quarterly basis to meet the contractual
volume. The refiner will increase its total purchased volumes to 5,000 Bbl/D
beginning June 29, 2008 through June 2013. Pricing under the contract, which
includes transportation and gravity adjustments, is at a fixed percentage of
WTI.
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 and we sell our produced gas in Colorado and
Utah at CIG, PEPL and Questar index prices.
The
following table summarizes our hedge position as of March 31, 2008:
|
|
Average
|
|
|
|
|
|
Average
|
|
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Barrels
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Floor/Ceiling
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MMBtu
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Average
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Term
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Per
Day
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Prices
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Term
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Per
Day
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Price
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Crude
Oil Sales (NYMEX WTI) Collars
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Natural
Gas Sales (NYMEX HH TO CIG) Basis Swaps
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Natural
Gas Sales (NYMEX HH TO PEPL) Basis Swaps
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Natural Gas Sales (NYMEX HH)
Swaps
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Crude
Oil Sales (NYMEX WTI) Swaps
|
|
|
|
|
|
Natural Gas Sales (NYMEX HH)
Collars
|
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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 $80.00 per barrel while still participating in any oil
price increase up to the ceiling prices which range from $70.00 to $91.00 per
barrel on the volumes indicated above, and if 2) gas prices decline below
our floor prices which range from $7.50 to $8.00 per MMBtu while still
participating in any gas price increase up to the ceiling prices, which range
from $8.40 to $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 marked-to-market, could have a material
impact on earnings in any given quarter and, thus, add increased volatility to
our net income. The marked-to-market values reflect the liquidation values of
such hedges and not necessarily the values of the hedges if they are held to
maturity.
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 an unrealized
net loss of approximately $.7 million in the Statements of Income under the
caption “Commodity derivatives” for the three months ended March 31,
2008.
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 March 31, 2008 (WTI $95.89; HH $9.96) for the term of our hedges we would expect to make pretax future
cash payments or to receive payments over the remaining term of our crude oil
and natural gas hedges in place as follows:
|
|
|
|
|
|
Impact
of percent change in futures prices
|
|
|
|
|
March
31, 2008
|
|
|
on
pretax future cash (payments) and receipts
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Futures Price (2008 – 2011)
|
|
$
|
95.89
|
|
$
|
76.71
|
|
$
|
86.30
|
|
$
|
105.47
|
|
$
|
115.06
|
|
Average
HH Futures Price (2008 – 2009)
|
|
|
9.96
|
|
|
7.97
|
|
|
8.97
|
|
|
10.96
|
|
|
11.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil gain/(loss) (in millions)
|
|
$
|
(239.9
|
)
|
$
|
(53.8
|
)
|
$
|
(143.0
|
)
|
$
|
(338.4
|
)
|
$
|
(436.8
|
)
|
Natural
Gas gain/(loss) (in millions)
|
|
|
(15.0
|
)
|
|
5.1
|
|
|
(5.3
|
)
|
|
(26.9
|
)
|
|
(37.8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pretax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
(WTI $100.42; HH $10.26)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
(WTI $96.26; HH $9.74)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48.2
|
)
|
|
|
|
|
|
)
|
|
|
)
|
|
|
)
|
2011
(WTI $93.74)
|
|
|
(.3
|
)
|
|
|
|
|
|
|
|
|
)
|
|
|
)
|
Total
|
|
$
|
(254.9
|
)
|
$
|
|
)
|
$
|
|
)
|
$
|
|
)
|
$
|
|
)
|
Interest
Rates. Our
exposure to changes in interest rates results primarily from long-term debt. In
October 2006, we issued $200 million of 8.25% senior subordinated notes due 2016
in a public offering. Total long-term debt outstanding including our short-term
Line of Credit, at March 31, 2008 was $255 million. Interest on amounts
borrowed under our credit facility is charged at LIBOR plus 1.0% to 1.75%, with
the exception of the $100 million of principal for which we have hedged the
interest rate at approximately 5.5% plus the credit facility’s margin through
June 30, 2011. Based on March 31, 2008 credit facility borrowings, a 1% change
in interest rates would have an annual $.9 million after tax impact on our
financial statements.
Item
4. Controls and
Procedures
|
As of
March 31, 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 March 31, 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 March 31, 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 and will not complete such actions on the timetable indicated.
Forward-looking statements are made based on management’s current expectations
and beliefs concerning future developments and their potential effects upon
Berry Petroleum Company. These items are discussed at length in Part I, Item 1A
on page 14 of our Form 10-K/A filed with the Securities and Exchange Commission,
under the heading “Risk Factors” and all material changes are updated in Part
II, Item 1A within this 10-Q.
PART II. OTHER
INFORMATION
|
Item
1. Legal
Proceedings
|
None.
None.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
None.
Item
3. Defaults Upon Senior
Securities
|
None.
Item 4. Submission of Matters to a Vote
of Security Holders
|
None.
Item
5. Other
Information
|
None.
Exhibit
No. Description of
Exhibit
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1
|
Certification
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
32.2
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
|
SIGNATURE
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned thereto
duly authorized.
BERRY
PETROLEUM COMPANY
/s/ Shawn
M. Canaday
Shawn M.
Canaday
Controller
(Principal
Accounting Officer)
Date: April
29, 2008