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, 2009
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 has submitted electronically and posted on
its corporate Web site, if any, every
Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation
S-T (§232.405 of this chapter) during the
preceding
12 months (or for such shorter period that the registrant was required to submit
and post such files). YES o 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 filer x Accelerated
filer o Non-accelerated
filer o Smaller
reporting company o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES o NO x
As of
April 20, 2009, the registrant had 42,790,536 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 20, 2009 all of which is held by
an affiliate of the registrant.
1
BERRY
PETROLEUM COMPANY
FIRST
QUARTER 2009 FORM 10-Q
TABLE
OF CONTENTS
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PART
I. FINANCIAL INFORMATION
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Page
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3
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3
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4
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4
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5
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6
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19
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30
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34
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PART
II. OTHER INFORMATION
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35
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35
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35
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35
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35
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35
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36
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BERRY PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
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March 31,
2009
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December
31, 2008
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|||||||
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ASSETS
|
||||||||
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Current
assets:
|
||||||||
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Cash
and cash equivalents
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$ | 49 | $ | 240 | ||||
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Short-term
investments
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65 | 66 | ||||||
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Accounts
receivable
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72,846 | 65,873 | ||||||
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Fair
value of derivatives
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95,931 | 111,886 | ||||||
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Assets
held for sale
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142,820 | - | ||||||
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Prepaid
expenses and other
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8,035 | 11,015 | ||||||
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Total
current assets
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319,746 | 189,080 | ||||||
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Oil
and gas properties (successful efforts basis), buildings and equipment,
net
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2,096,593 | 2,254,425 | ||||||
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Fair
value of derivatives
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48,641 | 79,696 | ||||||
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Other
assets
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27,649 | 19,182 | ||||||
| $ | 2,492,629 | $ | 2,542,383 | |||||
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LIABILITIES
AND SHAREHOLDERS' EQUITY
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||||||||
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Current
liabilities:
|
||||||||
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Accounts
payable
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$ | 51,257 | $ | 119,221 | ||||
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Revenue
and royalties payable
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14,848 | 34,416 | ||||||
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Accrued
liabilities
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42,088 | 34,566 | ||||||
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Line
of credit
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- | 25,300 | ||||||
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Income
taxes payable
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460 | 187 | ||||||
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Fair
value of derivatives
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2,983 | 1,445 | ||||||
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Deferred
income taxes
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35,191 | 45,490 | ||||||
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Liabilities
held for sale
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4,228 | - | ||||||
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Total
current liabilities
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151,055 | 260,625 | ||||||
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Long-term
liabilities:
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||||||||
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Deferred
income taxes
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272,351 | 270,323 | ||||||
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Long-term
debt
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1,199,400 | 1,131,800 | ||||||
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Abandonment
obligation
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40,105 | 41,967 | ||||||
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Other
long-term liabilities
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4,835 | 5,921 | ||||||
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Fair
value of derivatives
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12,324 | 4,203 | ||||||
| 1,529,015 | 1,454,214 | |||||||
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Shareholders'
equity:
|
||||||||
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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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Capital
stock, $.01 par value:
|
||||||||
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Class
A Common Stock, 100,000,000 shares authorized; 42,783,498 shares issued
and outstanding (42,782,365 in 2008)
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427 | 427 | ||||||
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Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares
issued and outstanding in 2009 and 2008 (liquidation preference of
$899)
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18 | 18 | ||||||
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Capital
in excess of par value
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82,641 | 79,653 | ||||||
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Accumulated
other comprehensive income
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64,142 | 113,697 | ||||||
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Retained
earnings
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665,331 | 633,749 | ||||||
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Total
shareholders' equity
|
812,559 | 827,544 | ||||||
| $ | 2,492,629 | $ | 2,542,383 | |||||
The
accompanying notes are an integral part of these financial
statements.
BERRY PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Three
Months Ended March 31, 2009 and 2008
(In
Thousands, Except Per Share Data)
|
Three
months ended March 31,
|
||||||||
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2009
|
2008
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|||||||
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REVENUES
AND OTHER INCOME ITEMS
|
||||||||
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Sales
of oil and gas
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$ | 127,869 | $ | 151,666 | ||||
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Sales
of electricity
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10,270 | 15,927 | ||||||
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Gas
marketing
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7,581 | 3,231 | ||||||
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Gain
on derivative terminations
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14,270 | - | ||||||
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Gain
(loss) on ineffective commodity derivatives
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22,894 | (708 | ) | |||||
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Interest
and other income, net
|
283 | 830 | ||||||
| 183,167 | 170,946 | |||||||
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EXPENSES
|
||||||||
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Operating
costs - oil and gas production
|
37,384 | 39,340 | ||||||
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Operating
costs - electricity generation
|
8,783 | 16,399 | ||||||
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Production
taxes
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5,652 | 5,183 | ||||||
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Depreciation,
depletion & amortization - oil and gas production
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36,398 | 24,207 | ||||||
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Depreciation,
depletion & amortization - electricity
generation
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959 | 693 | ||||||
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Gas
marketing
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7,284 | 2,982 | ||||||
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General
and administrative
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13,294 | 11,132 | ||||||
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Interest
expense
|
10,050 | 3,327 | ||||||
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Dry
hole, abandonment, impairment and exploration
|
122 | 2,728 | ||||||
| 119,926 | 105,991 | |||||||
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Income
before income taxes
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63,241 | 64,955 | ||||||
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Provision
for income taxes
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21,462 | 25,419 | ||||||
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Income
from continuing operations
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41,779 | 39,536 | ||||||
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(Loss)
income from discontinued operations, net of taxes
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(6,781 | ) | 3,495 | |||||
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Net
income
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$ | 34,998 | $ | 43,031 | ||||
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Basic
net income from continuing operations per share
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$ | .92 | $ | .88 | ||||
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Basic
net (loss) income from discontinued operations per
share
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$ | (.15 | ) | $ | .08 | |||
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Basic
net income per share
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$ | .77 | $ | .96 | ||||
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Diluted
net income from continuing operations per share
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$ | .92 | $ | .86 | ||||
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Diluted
net (loss) income from discontinued operations per
share
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$ | (.15 | ) | $ | .08 | |||
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Diluted
net income per share
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$ | .77 | $ | .94 | ||||
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Dividends
per share
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$ | .075 | $ | .075 | ||||
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Unaudited Condensed Statements of Comprehensive
Income
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||||||||
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Three
Months Ended March 31, 2009 and 2008
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||||||||
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(In
Thousands)
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||||||||
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Net
income
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$ | 34,998 | $ | 43,031 | ||||
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Unrealized
gains (losses) on derivatives, net of income taxes (benefits) of $48,160
and ($40,349), respectively
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78,577 | (60,523 | ) | |||||
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Reclassification
of realized gains on derivatives included in net income, net of income
taxes (benefits) of ($17,788) and $11,698, respectively
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(29,022 | ) | 17,547 | |||||
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Comprehensive
income
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$ | 84,553 | $ | 55 | ||||
The accompanying notes are an integral
part of these financial statements.
BERRY PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Three
Months Ended March 31, 2009 and 2008
(In
Thousands)
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Three months
ended March 31,
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||||||||
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2009
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2008
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|||||||
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Cash
flows from operating activities:
|
||||||||
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Net
income
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$ | 34,998 | $ | 43,031 | ||||
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Depreciation,
depletion and amortization
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39,545 | 27,769 | ||||||
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Dry
hole and impairment
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9,643 | 2,728 | ||||||
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Commodity
derivatives
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(22,842 | ) | 271 | |||||
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Stock-based
compensation expense
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2,988 | 2,107 | ||||||
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Deferred
income taxes
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21,059 | 22,082 | ||||||
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Gain
on sale of oil and gas properties
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- | (415 | ) | |||||
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Other,
net
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(3,952 | ) | 491 | |||||
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Change
in book overdraft
|
(23,510 | ) | 4,609 | |||||
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Cash
paid for abandonment
|
(112 | ) | (971 | ) | ||||
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Increase
in current assets other than cash and cash
equivalents
|
(12,933 | ) | (78 | ) | ||||
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Decrease
in current liabilities other than book overdraft, line of credit and fair
value of derivatives
|
(36,755 | ) | (14,389 | ) | ||||
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Net
cash provided by operating activities
|
8,129 | 87,235 | ||||||
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Cash
flows from investing activities:
|
||||||||
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Exploration
and development of oil and gas properties
|
(49,898 | ) | (75,869 | ) | ||||
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Property
acquisitions
|
(1,173 | ) | (261 | ) | ||||
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Additions
to vehicles, drilling rigs and other fixed assets
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(283 | ) | (909 | ) | ||||
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Proceeds
from sale of assets
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- | 1,809 | ||||||
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Deposits
on asset sales
|
14,000 | - | ||||||
|
Capitalized
interest
|
(5,312 | ) | (4,485 | ) | ||||
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Net
cash used in investing activities
|
(42,666 | ) | (79,715 | ) | ||||
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Cash
flows from financing activities:
|
||||||||
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Proceeds
from issuances on line of credit
|
147,800 | 100,600 | ||||||
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Payments
on line of credit
|
(173,100 | ) | (104,700 | ) | ||||
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Proceeds
from issuance of long-term debt
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159,600 | 69,200 | ||||||
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Payments
on long-term debt
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(92,000 | ) | (69,200 | ) | ||||
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Debt
issuance cost
|
(4,538 | ) | - | |||||
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Dividends
paid
|
(3,416 | ) | (3,327 | ) | ||||
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Proceeds
from stock option exercises
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- | 1,388 | ||||||
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Excess
tax benefit and other
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- | 882 | ||||||
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Net
cash provided by (used in) financing activities
|
34,346 | (5,157 | ) | |||||
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Net
(decrease) increase in cash and cash
equivalents
|
(191 | ) | 2,363 | |||||
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Cash
and cash equivalents at beginning of year
|
240 | 316 | ||||||
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Cash
and cash equivalents at end of period
|
$ | 49 | $ | 2,679 | ||||
The accompanying notes are an integral
part of these financial statements.
Berry Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
|
1.
|
General
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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, 2009 and December 31, 2008 and results of operations and other
comprehensive income and cash flows for the three months ended March 31, 2009
and 2008 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, 2008 financial statements. The December 31, 2008 Form 10-K
should be read in conjunction herewith. The year-end condensed Balance Sheet was
derived from audited financial statements, but does not include all disclosures
required by accounting principles generally accepted in the United States of
America.
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.
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, 2009 and
December 31, 2008 is $8.2 million and $31.8 million, respectively, representing
outstanding checks in excess of the bank balance (book overdraft).
|
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. This FSP became
effective for our fiscal year beginning January 1, 2009 and we expanded our
disclosures accordingly.
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. We adopted this Statement January 1, 2009 and we expanded our
disclosures accordingly.
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 interests in
a subsidiary (formerly called minority interests) and for the deconsolidation of
a subsidiary. We adopted this Statement January 1, 2009 and it did
not have a material effect on our 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 interests 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 statement 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).
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
In June
2008, the FASB issued FASB Staff Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
("FSP EITF 03-6-1"), which clarifies that share-based payment awards
that entitle their holders to receive nonforfeitable dividends before vesting
should be considered participating securities. As participating securities,
these instruments should be included in the earnings allocation in computing
basic earnings per share under the two-class method described in SFAS
No. 128, Earnings per
Share. All prior period earnings per share data presented
shall be adjusted retrospectively to conform with the provisions of this
pronouncement. FSP EITF 03-6-1 is effective for financial statements
issued for fiscal years beginning after December 15, 2008 and interim
periods within those years. We implemented EITF 03-06-1 during the first quarter
of 2009. See Note 10 to the condensed financial
statements.
In April
2009, the FASB issued FSP No. FAS 107-1, Interim Disclosures about Fair Value
of Financial Instruments. FSP 107-1 requires disclosures about fair value of financial
instruments for interim reporting periods as well as in annual financial
statements. FSP 107-1 will be effective for us for the quarter ending
June 30, 2009. The adoption of FSP 107-1 will not have an impact on
our financial position and results of operations.
|
3.
|
Fair
Value Measurements
|
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 for financial instruments on January 1,
2008.
In
February 2008, the FASB issued FSP FAS 157-2, Effective Date of FASB Statement No.
157. This Statement delayed the effective date of SFAS No. 157
for nonfinancial assets and nonfinancial liabilities. We adopted SFAS
157 for nonfinancial assets and nonfinancial liabilities on January 1, 2009 and
it did not have a material effect on our financial statements.
In
February of 2007, the FASB issued SFAS 159 The Fair Value Option for Financial
Assets and Financial Liabilities—Including an amendment of FASB Statement No.
115, 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.
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.
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.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
Assets
and ( liabilities) measured at fair value on a recurring basis
|
March
31, 2009 (in millions)
|
Total
carrying value on the condensed Balance Sheet
|
Level
2
|
Level
3
|
|||||||||
|
Commodity
derivative assets
|
143.5 | 6.0 | 137.5 | |||||||||
|
Interest
rate swaps
|
(14.7 | ) | (14.7 | ) | - | |||||||
|
Total
fair value
|
128.8 | (8.7 | ) | 137.5 | ||||||||
Included in the
total $128.8 million asset above is a $0.5 million liability associated
with our DJ liabilities which are classified as "Liabilities held for sale"
as of March 31, 2009.
|
December
31, 2008 (in millions)
|
Total
carrying value on the condensed Balance Sheet
|
Level
2
|
Level
3
|
|||||||||
|
Commodity
derivatives assets
|
198.4 | 25.9 | 172.5 | |||||||||
|
Interest
rate swap liabilities
|
(12.5 | ) | (12.5 | ) | - | |||||||
|
Total
fair value of derivative assets
|
185.9 | 13.4 | 172.5 | |||||||||
Changes
in Level 3 fair value measurements
The table below includes a rollforward
of the condensed 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 March 31, 2009
|
|||
|
Fair
value of Level 3 derivative assets, beginning of period
|
$ | 172.5 | ||
|
Total
realized and unrealized gains and (losses) included in sales of oil and
gas
|
(22.9 | ) | ||
|
Purchases,
sales and settlements, net
|
(15.5 | ) | ||
|
Transfers
in and/or out of Level 3
|
3.4 | |||
|
Fair
value of Level 3 derivative assets, March 31, 2009
|
$ | 137.5 | ||
|
Total
unrealized gains and (losses) included in income related to financial
assets and liabilities still on the condensed balance sheet at March 31,
2009
|
$ | 22.8 | ||
The fair
value of our DJ basin asset sale determined by our Borad of Directors was
confirmed by the sales price paid to us. The following nonrecurring
fair value measurements were recorded during the three months ended March 31,
2009 in conjunction with the sale of our DJ basin assets:
|
Three
Months Ended
March
31, 2009
|
Significant
Unobservable Inputs
Level
3
|
Total
Gains (Losses)
|
||||||||||
|
Long
lived assets and liabilities held for sale (in millions)
|
$ | 138,592 | $ | 138,592 | $ | (9,637 | ) | |||||
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
|
4.
|
Hedging
|
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. We benefit from lower natural
gas pricing as we are a consumer of natural gas in our California operations and
in the Rocky Mountains and East Texas, 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 also utilize interest
rate derivatives to protect against changes in interest rates on our floating
rate debt.
The
related cash flow impact of all of our hedges is reflected in cash flows from
operating activities. At March 31, 2009, our net fair value of derivative assets
was $128.8 million as compared to $185.9 million at December 31, 2008 which
reflects decreases in commodity prices in the period. Based on NYMEX strip
pricing as of March 31, 2009, we expect to receive hedge proceeds under the
existing derivatives of $104.4 million during the next twelve months. At March
31, 2009, Accumulated Other Comprehensive Income consisted of $64.1 million, net
of tax, of unrealized gains from our crude oil and natural gas swaps and collars
that qualified for hedge accounting treatment at March 31, 2009. Deferred net
gains recorded in “Accumulated Other Comprehensive Income” at March 31, 2009 and
subsequent mark-to-market changes in the underlying hedging contracts are
expected to be reclassified to earnings in the same period that the forecasted
transaction impacts earnings.
We present our derivative assets and
liabilities in our Condensed Balance Sheets on a net basis. We net
derivative assets and liabilities, whenever we have a legally enforceable master
netting agreement with a counterparty to a derivative contract. We use
these agreements to manage and substantially reduce our potential counterparty
credit risk.
The
following table disaggregates our net derivative assets and liabilities into
gross components on a contract-by-contract basis before giving effect to master
netting arrangements. Finally, we identify the line items in our Condensed
Balance Sheets in which these fair value amounts are included. The gross asset and
liability values in the table below are segregated between those derivatives
designated in qualifying hedge accounting relationships and those not designated
in hedge accounting relationships. We use the end of period accounting
designation to determine the classification for each derivative
position.
|
As
of March 31, 2009
|
||||||||||
|
Derivative
Assets
|
Derivative
Liabilities
|
|||||||||
|
(in
millions)
|
Balance
Sheet Location
|
Fair
Value
|
Balance
Sheet Location
|
Fair
Value
|
||||||
|
Commodity
– Oil
|
Current
assets
|
94.6 |
Current
liability
|
2.3 | ||||||
|
Commodity
– Natural Gas
|
Current
assets
|
4.1 |
Current
liability
|
0.3 | ||||||
|
Commodity
– Oil
|
Long
term assets
|
52.4 |
Long
term liabilities
|
6.5 | ||||||
|
Commodity
– Natural Gas
|
Long
term assets
|
0.7 | - | |||||||
|
Commodity
– Natural Gas
|
Long
term liabilities
|
1.1 | - | |||||||
|
Interest
rate contracts
|
- |
Current
assets
|
2.9 | |||||||
|
Interest
rate contracts
|
- |
Long
term assets
|
4.4 | |||||||
|
Interest
rate contracts
|
- |
Current
liabilities
|
0.4 | |||||||
|
Interest
rate contracts
|
- |
Long
term liabilities
|
7.0 | |||||||
|
Total
derivatives designated as hedging instruments under Statement
133
|
152.9 | 23.8 | ||||||||
|
Commodity
– Oil
|
Current
assets
|
0.2 |
Current
liabilities
|
- | ||||||
|
Commodity
– Natural Gas
|
Liabilities
held for sale
|
0.8 |
Liabilities
held for sale
|
1.3 | ||||||
|
Total
derivatives not designated as hedging instruments under Statement
133
|
1.0 | 1.3 | ||||||||
|
Total
Derivatives
|
153.9 | 25.1 | ||||||||
Berry Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
The
tables below summarize the Statement of Income impacts on our derivative
instruments:
|
Derivatives
in Statement 133 cash flow hedging relationships
|
Amount
of gain (loss) Recognized in OCI on Derivative
(Effective portion)
|
Location
of Gain (Loss) Reclassified from AOCI into Income (Effective
Portion)
|
Amount
of Gain (Loss) Reclassified from AOCI into Income (Effective
Portion)
|
Location
of Gain Recognized in Income on Derivative (Ineffective Portion and Amount
Excluded from Effectiveness Testing)
|
Amount
of Gain Recognized in Income on Derivative (Ineffective Portion and
Amount Excluded from Effectiveness Testing)
|
|||||||||
|
Three
Months Ended
March
31, 2009
|
Three
Months Ended
March
31, 2009
|
Three
Months Ended
March
31, 2009
|
||||||||||||
|
Commodity -
Oil
|
$ | 36.5 |
Sales
of oil and gas
|
$ | 41.6 |
Sales
of oil and gas
|
$ | - | ||||||
|
Commodity -
Natural Gas
|
8.9 |
Sales
of oil and gas
|
6.6 |
Sales
of oil and gas
|
- | |||||||||
|
Commodity
– Oil
|
- |
Gain
(loss) on commodity –Oil
|
- |
Gain
(loss) on commodity-Oil
|
22.7 | |||||||||
|
Interest
rate
|
(3.4 | ) |
Interest
expense
|
(1.0 | ) |
Interest
expense
|
- | |||||||
|
Total
|
$ | 42.0 | $ | 47.2 | $ | 22.7 | ||||||||
Amount of
Gain or (Loss) Recognized in Income on Derivatives not designated as Hedging
Instruments under Statement 133:
|
Derivatives
not designated as Hedging Instruments under Statement 133
|
Location
of Gain (Loss) Recognized in Income on Derivative
|
Amount
of Gain (Loss) Recognized in Income on Derivate for Derivatives not
designated as Hedging Instruments under Statement 133
|
|||
|
Three
months ended March 31, 2009
|
|||||
|
Commodity
– Oil
|
Gain
(loss) on ineffective commodity derivatives
|
$ | 0.2 | ||
|
Commodity
- Natural Gas
|
(Loss)
income from discontinued operations, net of tax
|
(0.5 | ) | ||
|
Total
Derivatives
|
$ | (0.3 | ) | ||
We
entered into the following natural gas hedges during the three months ended
March 31, 2009:
|
·
|
Houston
Ship Channel basis swaps on 2,000 MMBtu/D for $0.38 for full year
2010
|
|
·
|
NGPL
basis swaps on 2,000 MMBtu/D for $0.49 for the full year
2010
|
|
·
|
Collars
on 4,000 MMBtu/D with floors of $6.50 and ceilings ranging from $8.75 to
$8.90 for full year 2010
|
These gas
hedges have been designated as cash flow hedges in accordance with SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities.
During
the first quarter of 2009, we entered into natural gas derivatives on behalf of
the purchaser of our DJ assets. We did not elect hedge
accounting for these hedges and recorded the unrealized net loss of $0.5 million
on the income statement under the caption “Income from discontinued
operations, net of taxes.”
In
conjunction with the sale of the DJ assets, during the first quarter of 2009, we
concluded that the forecasted transaction in certain of our hedging
relationships was not probable of occurring. As such, we reclassified
a gain of $14.3 million from accumulated other comprehensive income to the
statement of income under the caption “Gain on derivative
terminations.”
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
We
entered into the following oil collar derivatives during the three months ended
March 31, 2009:
|
Crude
Oil Sales (NYMEX WTI) Collars
|
Average
Barrels Per Day
|
Floor/Ceiling
Prices
|
||||||
|
Full
year 2011
|
1,000 | $ | 55.20 / $70.00 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00 / $70.50 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00 / $68.65 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00 / $68.00 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00 / $71.20 | |||||
|
Full
year 2011
|
1,000 | $ | 60.00 / $76.00 | |||||
|
Full
year 2011
|
1,000 | $ | 60.00 / $81.25 | |||||
These oil
hedge derivatives have been designated as cash flow hedges in accordance with
SFAS No. 133.
We
entered into the following oil swap derivatives during the three months ended
March 31, 2009:
|
Crude
Oil Sales (NYMEX WTI) Collars
|
Average
Barrels Per Day
|
Swap
Price
|
||||||
|
May
2009
|
1,000 | $ | 55.60 | |||||
|
June
2009
|
400 | $ | 57.00 | |||||
|
3rd
Quarter 2009
|
500 | $ | 52.40 | |||||
|
Full
year 2010
|
650 | $ | 56.90 | |||||
|
Full
year 2011
|
250 | $ | 61.80 | |||||
|
Full
year 2011
|
500 | $ | 57.36 | |||||
|
Full
year 2011
|
500 | $ | 57.40 | |||||
|
Full
year 2011
|
500 | $ | 57.50 | |||||
The oil
hedge derivatives have been designated as cash flow hedges in accordance with
SFAS No. 133, except as noted below. We did not elect hedge
accounting for the May and June 2009 hedges and recorded an unrealized net gain
of $0.2 million at March 31, 2009 on the income statement under the caption
“Gain (loss) on ineffective commodity derivatives”.
During
the first quarter of 2009, we also converted 6,000 Bbl/D oil collars ranging
from floors of $55.00 to $60.00 and ceilings of $75.00 to $83.10 for full year
2010 swaps for the same volumes with swap prices ranging from $61.00 to
$64.80.
In
December 2008, Big West Oil of California filed for bankruptcy protection under
Chapter 11 of the United States Bankruptcy Code. Our contract with
Big West provided for an oil price differential that was linked to NYMEX WTI
prices and allowed us to effectively hedge our oil production at the NYMEX WTI
index. Subsequent to the Big West bankruptcy, our crude oil has been
sold at field posting prices which resulted in some ineffectiveness related to
our WTI linked hedges. We recognized an unrealized net gain of
approximately $22.8 million on the income statement under the caption “Gain
(loss) on ineffective commodity derivatives” for the quarter ended March 31,
2009 as a result of this ineffectiveness.
We
entered into the following interest rate hedges during the three months ended
March 31, 2009 which have been designated as cash flow
hedges:
|
Beginning/Maturity
|
Rate
|
Notional
Amount (in millions)
|
||||||
|
4/15/09
– 7/15/12
|
1.89 | % | $ | 25 | ||||
|
12/15/09
– 7/15/12
|
2.15 | % | $ | 25 | ||||
|
12/15/09
– 7/15/12
|
2.05 | % | $ | 25 | ||||
|
12/15/09
– 7/15/12
|
2.00 | % | $ | 25 | ||||
|
12/15/09
– 7/15/12
|
2.00 | % | $ | 25 | ||||
|
12/15/09
– 7/15/12
|
1.94 | % | $ | 25 | ||||
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
Our hedge
contracts have been primarily executed with the counterparties that are party to
our senior secured revolving credit facility. Neither we nor our counterparties
are required to post collateral in connection with our derivative positions and
netting agreements are in place with each of our counterparties allowing us to
offset our derivative asset and liability positions. The credit
rating of each of these counterparties is AA-/Aa2, or better. Our
derivatives are held with a small number of counterparties and as of March 31,
2009, our largest two counterparties accounted for 80% of the value of our total
derivative positions.
As of
March 31, 2009, we had the following outstanding commodity
contracts:
|
Commodity
Hedges
|
||||||||||||||||
|
2009
|
2010
|
2011
|
2012
|
|||||||||||||
|
Oil
Bbl/D:
|
17,435 | 14,930 | 9,020 | 1,000 | ||||||||||||
|
Natural
Gas MMBtu/D:
|
5,000 | 9,000 | - | - | ||||||||||||
|
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.
The
following table summarizes the change in abandonment obligation for the three
months ended March 31, 2009 (in thousands):
|
Beginning
balance at January 1, 2009
|
$
|
41,967
|
||
|
Liabilities
incurred
|
-
|
|||
|
Liabilities
settled
|
(113
|
)
|
||
|
Revisions
in estimated liabilities
|
-
|
|||
|
Accretion
expense
|
1,002
|
|||
|
Ending
balance at March 31, 2009
|
$
|
42,856
|
Included
in the total of $42.9 million above is $2.8 million in AROs that are associated
with our DJ liabilities which are classified as "Liabilities held for sale"
as of March 31, 2009.
|
6.
|
Dispositions and Discontinued
Operations
|
On March
3, 2009, we entered into an agreement to sell our DJ basin assets and related
hedges for $154 million before customary closing adjustments. The $14
million sale of our DJ basin related hedges was completed in March
2009. The hedge forecasted transaction is no longer expected to occur
and the gain on the sale of these hedges is recorded under the caption “Gain on
derivative terminations” in the condensed statement of income and is included in
operating cash flows for the three months ended March 31, 2009. We received
a deposit of $14 million on the sale of the DJ basin assets which is included in
“Accrued Liabilities” on the condensed balance sheet as of March 31,
2009. The closing date of the sale was April 1, 2009. In
accordance with SFAS No. 144, these properties have been separately presented in
the accompanying condensed balance sheet at fair value less the cost to sell, as
of March 31, 2009. The sales cost associated with the DJ basin assets were $1.2
million. We recorded a pre-tax impairment loss of $9.6
million, which is aggregated within the $6.8 million “(loss) income from
discontinued operations, net of tax” on our statement of income for the three
months ended March 31, 2009.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
Income
(loss) from discontinued operations, net of tax on our accompanying statements
of income is comprised of the following (in thousands):
|
For
the Three Months Ended March 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Oil
and gas revenue
|
$ | 5,396 | $ | 12,829 | ||||
|
Other
revenue
|
622 | 914 | ||||||
|
Total
Revenue
|
6,018 | 13,743 | ||||||
|
Operating
expenses
|
2,576 | 2,289 | ||||||
|
Production
taxes
|
195 | 784 | ||||||
|
DD&A
|
2,188 | 2,869 | ||||||
|
General
and administrative
|
388 | 251 | ||||||
|
Interest
expense
|
815 | 411 | ||||||
|
Commodity
derivatives
|
484 | - | ||||||
|
Dry
hole, abandonment, impairment and exploration
|
9,637 | 1,398 | ||||||
|
Total
Expenses
|
16,283 | 8,002 | ||||||
|
Income
(loss) from discontinued operations, before income taxes
|
(10,265 | ) | 5,741 | |||||
|
Income
tax benefit (expense)
|
3,484 | (2,246 | ) | |||||
|
Income
(loss) from discontinued operations
|
$ | (6,781 | ) | $ | 3,495 | |||
The
following is a summary of the assets and liabilities held for sale related to
the DJ Basin sale at March 31, 2009 (in thousands):
|
March
31, 2009
|
||||
|
Inventory
|
$
|
1,275
|
||
|
Oil
and gas properties, net of accumulated depreciation and
impairment
|
140,730
|
|||
|
Other
Assets
|
815
|
|||
|
Total
assets
|
$
|
142,820
|
||
|
Asset
retirement obligation
|
$
|
2,751
|
||
|
Other
liabilities
|
1,477
|
|||
|
Total
liabilities
|
$
|
4,228
|
||
|
7.
|
Dry
Hole, Abandonment and Impairment
|
During the three months
ended March 31, 2009 and 2008, we recorded dry hole, abandonment, impairment and
exploration expense of $0.1 million and $2.7 million,
respectively. In the first quarter of 2008, technical
difficulties on three wells in the Piceance basin were encountered before
reaching total depth and these holes were abandoned in favor of drilling to the
same bottom hole location by drilling a new well.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
8. Pro
Forma Results
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 $668 million cash (East Texas Acquisition) including an initial purchase
price of $622 million, and normal post closing adjustments of $46
million.
The
unaudited pro forma results presented below for the three months ended March 31,
2008 have been prepared to give effect to the East Texas Acquisition on the
Company’s results of continuing operations under the purchase method of
accounting as if it had been consummated at January 1, 2008. The
unaudited pro forma results (in millions) do not purport to represent the
results of continuing 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
March
31, 2008
|
||||
|
Pro
forma revenue
|
$ | 185,960 | ||
|
Pro
forma income from operations
|
$ | 60,073 | ||
|
Pro
forma net income
|
$ | 36,942 | ||
|
Pro
forma basic earnings per share
|
$ | 0.82 | ||
|
Pro
forma diluted earnings per share
|
$ | 0.81 | ||
|
9.
|
Income
Taxes
|
The
effective income tax rate was 33.9% for the first quarter of 2009 compared
to 45.1% for the fourth quarter of 2008 and 39% for the first quarter of
2008. The decrease in rate for first quarter is primarily due to a decrease
in anticipated state taxes. 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
March 31, 2009, we had a gross liability for uncertain tax benefits of
$11.2 million of which $10.0 million, if recognized, would affect the
effective tax rate. There were no significant changes to the calculation since
year end 2008.
We
anticipate the balance of our unrecognized tax benefits could be reduced during
the next 12 months as the IRS finalizes certain examinations which are in
progress, however, we cannot reasonably estimate the impact of the examination
at this time.
|
10.
|
Earnings
per Share
|
In SFAS
No. 128, “Earnings per Share (as amended)”, the two-class method is an earnings
allocation formula that determines earnings per share for each class of stock
according to dividends declared (or accumulated) and participation rights in
undistributed earnings. In June 2008, the FASB issued FASB Staff
Position No. EITF 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities
("FSP EITF 03-6-1"), which clarifies that share-based payment awards
that entitle their holders to receive nonforfeitable dividends before vesting
should be considered participating securities. As participating securities,
these instruments should be included in the earnings allocation in computing
basic earnings per share under the two-class method described in SFAS
No. 128. All prior period earnings per share data presented were
adjusted retrospectively to conform with the provisions of this pronouncement.
FSP EITF 03-6-1 is effective for financial statements issued for
fiscal years beginning after December 15, 2008 and interim periods within
those years. Accordingly, we have adopted this pronouncement as of
January 1, 2009.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
Undistributed
and distributed earnings allocated to shareholders are calculated as follows for
the three month periods ended:
|
March
31, 2009
|
March
31, 2008
|
|||||||
|
Income
from continuing operations
|
$ | 41,779 | $ | 39,536 | ||||
|
Less:
|
||||||||
|
Dividends
paid - shareholders
|
3,344 | 3,289 | ||||||
|
Dividends
paid - unvested shares and deferred stock units
|
72 | 38 | ||||||
|
Undistributed
income from continuing operations
|
$ | 38,363 | $ | 36,209 | ||||
|
(Loss)
income from discontinued operations
|
$ | (6,781 | ) | $ | 3,495 | |||
|
March
31, 2009
|
March
31, 2008
|
|||||||
|
Income
from continuing operations available to shareholders
|
||||||||
|
Distributed
earnings to shareholders
|
$ | 3,344 | $ | 3,289 | ||||
|
Allocation
of undistributed earnings to shareholders
|
37,387 | 35,705 | ||||||
|
Total
income from continuing operations available to
shareholders
|
$ | 40,731 | $ | 38,994 | ||||
|
Income
from discontinued operations available to
shareholders
|
||||||||
|
Distributed
earnings to shareholders
|
$ | - | $ | - | ||||
|
Allocation
of undistributed (loss) earnings available to
shareholders
|
(6,608 | ) | 3,445 | |||||
|
Total
(loss) income from discontinued operations available to
shareholders
|
$ | (6,608 | ) | $ | 3,445 | |||
Undistributed
earnings available to shareholders is calculated by dividing weighted average
shares outstanding by the total of weighted shares outstanding plus weighted
average of unvested shares outstanding plus the weighted average of deferred
stock units outstanding multiplied by undistributed earnings. Shares
issued during the period and shares reacquired during the period are weighted
for the portion of the period in which the shares were
outstanding. The weighted average number of unvested shares and
deferred stock units for the three month periods ended March 31, 2009 and 2008
is 1,164,391 and 628,685, respectively.
Weighted
average shares outstanding and dilutive shares outstanding are calculated as
follows:
|
March
31, 2009
|
March
31, 2008
|
|||||||
|
Weighted
average shares outstanding:
|
44,581 | 44,392 | ||||||
|
Add:
dilutive effects of stock options
|
12 | 623 | ||||||
|
Weighted
average shares outstanding, including the effects of dilutive common
shares
|
44,593 | 45,015 | ||||||
Options
to purchase 2.3 million and .2 million shares were outstanding at March 31, 2009
and 2008, respectively, and were excluded from the calculation of diluted
earnings per share because the options’ exercise price was greater than the
average market price of the shares.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
Basic and
dilutive earnings per share from continuing and discontinued operations are
calculated as follows:
|
March
31, 2009
|
March
31, 2008
|
|||||||
|
Basic
|
||||||||
|
Income
from continuing operations available to shareholders
|
$ | 40,731 | $ | 38,994 | ||||
|
shares
outstanding
|
44,581 | 44,392 | ||||||
|
Basic
earnings per share from continuing operations
|
$ | .92 | $ | .88 | ||||
|
(Loss)
income from discontinued operations available to
shareholders
|
$ | (6,608 | ) | $ | 3,445 | |||
|
Shares
outstanding
|
44,581 | 44,392 | ||||||
|
Basic
(loss) earnings per share from discontinued
operations
|
$ | (.15 | ) | $ | .08 | |||
|
Basic
earnings per share
|
$ | .77 | $ | .96 | ||||
|
Dilutive
|
||||||||
|
Income
from continuing operations available to shareholders
|
$ | 40,731 | $ | 38,994 | ||||
|
Dilutive
shares
|
44,593 | 45,015 | ||||||
|
Dilutive
earnings per share from continuing operations
|
$ | .92 | $ | .86 | ||||
|
(Loss)
income from discontinued operations available to
shareholders
|
$ | (6,608 | ) | $ | 3,445 | |||
|
Dilutive
shares
|
44,593 | 45,015 | ||||||
|
Dilutive
(loss) earnings per share from discontinued
operations
|
$ | (.15 | ) | $ | .08 | |||
|
Dilutive
earnings per share
|
$ | .77 | $ | .94 | ||||
Upon
adoption, both basic income and dilutive income per share for the first quarter
of 2008 decreased by $.01 for continuing operations. Basic income and
dilutive income per share was unchanged for discontinued
operations.
|
11.
|
Debt
Obligations
|
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 by our assets. At March 31, 2009 and
December 31, 2008, the outstanding balance under this Line of Credit was $0 and
$25.3 million, respectively. Interest on amounts borrowed is charged at
LIBOR plus a margin of approximately 1%.
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 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. Interest on amounts borrowed under the Agreement was
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. An annual commitment fee of .25% to .375%
was charged on the unused portion of this credit facility.
On
October 17, 2008, we amended the Agreement which increased our borrowing base
from $1.0 billion to $1.25 billion with commitments of $1.08 billion and a new
maturity date of July 15, 2012. Commitments were increased during the
fourth quarter of 2008 with the addition of $130 million in commitments bringing
the total commitments under the facility to $1.21 billion from 19
banks.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
On
February 19, 2009, we executed another amendment to the Agreement which modified
our covenants as follows:
|
Total
funded debt to EBITDAX ratio
|
||||||||||
|
2009
|
2010
|
Thereafter
|
||||||||
| 4.75 | 4.50 | 4.00 | ||||||||
|
Senior
secured debt to EBITDAX ratio
|
||||||||||||||
|
to
Sep 2010
|
Mar
2011
|
Sep
2011
|
Thereafter
|
|||||||||||
| 3.75 | 3.50 | 3.25 | 3.0 | |||||||||||
Additionally,
the write off of $38.5 million to bad debt expense associated with the
bankruptcy of Big West is excluded from the calculation of
EBITDAX. There were no changes to the current ratio covenant which,
as defined, must be at least 1.0. The LIBOR and prime rate margins
increased to between 2.25% and 3.0% based on the ratio of credit outstanding to
the borrowing base. Additionally, the annual commitment fee on the
unused portion of the credit facility increased to 0.50%, regardless of the
amount outstanding. This transaction was accounted for in
accordance with Emerging Issues Task Force (EITF) 98-14, Debtor’s Accounting for Changes in
Line-of-Credit or Revolving-Debt Arrangements.
The total
outstanding debt at March 31, 2009 under the Agreement, as amended, and the Line
of Credit was $999 million and $0, respectively, and $3 million in letters of
credit have been issued under the facility, leaving $208 million in borrowing
capacity available. The maximum amount available is subject to
semi-annual redeterminations of the borrowing base, based on the value of our
proved oil and gas reserves, in April and October of each year in accordance
with the lenders’ customary procedures and practices. Both we and the
banks have the bilateral right to one additional redetermination each
year.
We
further amended the Agreement on April 27, 2009. See Note 13
“Subsequent Events.”
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. Under the Notes, as long as the
interest coverage ratio (as defined) is greater than 2.5 times, we may incur
additional debt. 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.
Financial
Covenants
The
senior secured revolving credit facility contains restrictive covenants which,
among other things, require us to currently maintain a debt to EBITDAX ratio of
not greater than 4.75 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 March 31, 2009.
|
As
of
March
31, 2009
|
||||
|
Current
Ratio (Not less than 1.0)
|
2.9
|
|||
|
EBITDAX
To Total Funded Debt Ratio (Not greater than 4.75)
|
2.8
|
|||
|
Interest
Coverage Ratio (Not less than 2.5)
|
7.4
|
|||
The
weighted average interest rate on total outstanding borrowings at March 31, 2009
was 4.2%.
|
12.
|
Contingencies
and Commitments
|
We have
no material 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.
During
the California energy crisis in 2000 and 2001, we had electricity sales
contracts with various utilities and a portion of the electricity prices paid to
us under such contracts from December 2000 to March 27, 2001 has been under a
degree of legal challenge since that time. It is possible that we may
have a liability pending the final outcome of the CPUC proceedings on the
matter. There are ongoing proceedings before the CPUC in which
Edison and PG&E are seeking credit against future payments they are to make
for electricity purchases based on retroactive adjustment to pricing under
contracts with us. Whether or not retroactive adjustments will be
ordered, how such adjustments would be calculated and what period they would
cover are too uncertain to estimate at this time.
Berry
Petroleum Company
Notes
to the Unaudited Condensed Financial Statements
In
December 2008, Flying J, Inc., and its wholly owned subsidiary Big West Oil and
its wholly owned subsidiary BWOC filed for bankruptcy protection under Chapter
11 of the United States Bankruptcy Code. Also in December 2008, BWOC
informed the Company that it was unable to receive the Company’s
production. Included in our allowance for doubtful accounts is $38.5
million due from BWOC. Of the $38.5 million due from BWOC, $12.4 million
represents December crude oil sales by the Company and $26.1 million represents
November crude oil sales. BWOC will also be liable to us for damages
under this contract. We have guarantees from Big West Oil and from
Flying J, Inc. in the amount of $75 million each, in the event that our claim is
not fully collectible from BWOC. While we believe that we may recover some or
all of the amounts due from BWOC, the data received from the bankruptcy
proceedings to date has not provided us with adequate data from which to make a
conclusion that any amounts will be collected.
On March
20, 2009, we entered into a crude oil purchase contract with a refiner for
the sale of all of the Company’s crude oil production from the Midway Sunset
Field. The volume approximates 12,000 Bbl/d. The agreement
is effective April 1, 2009 and continues until September 30, 2009.
In
February 2007, we entered into a multi-staged crude oil sales contract with a
refiner for our Uinta light crude oil. Under the agreement, the refiner began
purchasing 3,200 Bbl/D in July 2007. After partial completion of its refinery
expansion in Salt Lake City in March 2008, the refiner increased its total
purchase capacity to 5,000 Bbl/D. This contract is in effect through
June 30, 2013. Pricing under the contract, which includes
transportation and gravity adjustments, is at a fixed percentage of
WTI, which ranges from $10 to $15 per barrel at WTI prices between
$40 and $60 per barrel. This contract is our only sales contract for
our Uinta oil.
We have
two long-term firm transportation contracts 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 $0.3 million and $0.2 million for the three month periods ended March 31,
2009 and 2008, respectively.
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.
|
13.
|
Subsequent
Events
|
On April
1, 2009, we completed the sale of our DJ basin assets. Total proceeds
received for the sale were $139 million, including closing adjustments and the
$14 million deposit received in March 2009.
On April
27, 2009, we completed the scheduled redetermination of the borrowing under our
credit facility. Our borrowing base was reduced from $1.25 billion to
$1.05 billion, with $100 million of the reduction resulting from the sale of our
DJ basin assets. Also on April 27, 2009 we completed a $140 million
second lien credit facility, with lenders from among our current lending group,
which matures on January 16, 2013. Interest on the facility is
charged at LIBOR plus a margin of eight percent with a minimum LIBOR rate of
three percent. Covenants under this facility are similar but slightly
less restrictive than our senior secured credit facility. Our Line of
Credit is suspended as long as the second lien credit facility is outstanding.
Additionally, each dollar outstanding under the second lien credit facility
reduces the borrowing base under our senior secured credit facility by 30 cents
such that the $140 million second lien facility reduces our borrowing base from
$1.05 billion to $1.0 billion. Proceeds from the second lien facility were used
to pay down borrowings under our senior secured credit facility. On April 27,
2009, following the closing of the second lien credit facility, the outstanding
amount under our senior secured credit facility was approximately $735 million
providing us with approximately $275 million of liquidity.
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 months ended March 31, 2009 and 2008 and our financial condition,
liquidity and capital resources as of March 31, 2009. 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
|
|
|
·
|
Calibrating
our cost structure to the current commodity price
environment
|
|
|
·
|
Acquiring
additional assets with significant growth
potential
|
|
|
·
|
Accumulating
significant acreage positions near our producing
operations
|
Notable
First Quarter Items.
|
|
·
|
Achieved
production averaging 33,330 BOE/D, up 19% from the first quarter of
2008
|
|
|
·
|
Announced
the sale of our DJ basin assets and related hedges for approximately $154
million
|
|
|
·
|
Entered
into short-term sales contracts for our California crude oil to replace
our terminated contract with Big
West
|
|
|
·
|
Continued
to return California wells to production after the December 2008 Big West
bankruptcy, increasing average California production from 16,000 Bbl/D in
the fourth quarter of 2008 to 16,440 Bbl/D in the first quarter of
2009
|
|
|
·
|
Increased
Diatomite net production to an average of 2,670 BOE/D, up 94% from the
first quarter of 2008
|
|
|
·
|
Amended
the covenants under our credit facility providing increased financial
flexibility going forward
|
|
|
·
|
Added
to our oil hedge positions increasing 2011 hedged volumes to 9,000 BOE/D
and 2012 volumes to 2,000 BOE/D
|
|
|
·
|
Increased
our fixed rate debt position to $725 million utilizing interest rate
swaps
|
Notable
Items and Expectations for the Second Quarter and Full Year 2009.
|
|
·
|
Closed
on the sale of our DJ assets using proceeds for the repayment of
debt
|
|
|
·
|
Completed
the redetermination of our credit facility with a borrowing base of $1.05
billion with no changes to the terms or interest rate
margins
|
|
|
·
|
Completed
a $140 million second lien facility, with existing lenders, increasing our
liquidity to approximately $275
million
|
|
|
·
|
Expect
production to average approximately 30,000 BOED with no future
contributions from the DJ assets which averaged approximately 3,100 BOE/D
in the first quarter of 2009.
|
Overview of the
first Quarter of 2009. We had net income from continuing operations of
$41.8 million, or $0.92 per diluted share, and net cash from operations was $8.1
million in the first quarter of 2009. We drilled 26 gross wells and capital
expenditures, excluding property acquisitions, totaled $50.2
million. We achieved average production of 33,330 BOE/D in the first
quarter of 2009, down 6% from an average of 35,583 BOE/D in the fourth quarter
of 2008.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Results of
Operations. The following results
from continuing operations are in millions (except per share data) for the three
months ended:
|
March
31, 2009
(1Q09)
|
March
31, 2008
(1Q08)
|
1Q09
to 1Q08 Change
|
December
31, 2008
(4Q08)
|
1Q09
to 4Q08 Change
|
||||||||||||||||
|
Sales
of oil
|
$ | 99 | $ | 131 | (24 | %) | $ | 97 | 2 | % | ||||||||||
|
Sales
of gas
|
29 | 21 | 38 | % | 38 | (24 | %) | |||||||||||||
|
Total
sales of oil and gas
|
$ | 128 | $ | 152 | (16 | %) | $ | 135 | (6 | %) | ||||||||||
|
Sales
of electricity
|
10 | 16 | (38 | %) | 12 | (17 | %) | |||||||||||||
|
Gas
Marketing
|
8 | 3 | 167 | % | 8 | - | ||||||||||||||
|
Gain
on sale of assets
|
- | - | - | (2 | ) | - | ||||||||||||||
|
Gain
on hedge terminations
|
14 | - | - | - | - | |||||||||||||||
|
Gain
(loss) on commodity derivatives
|
23 | (1 | ) | - | (2 | ) | - | |||||||||||||
|
Interest
and other income, net
|
- | 1 | - | 1 | - | |||||||||||||||
|
Total
revenues and other income
|
$ | 183 | $ | 171 | 7 | % | $ | 152 | 20 | % | ||||||||||
|
Net
income (loss) from continuing operations
|
$ | 42 | $ | 40 | $ | (12 | ) | |||||||||||||
|
Diluted
earnings (loss) per share from continuing operations
|
$ | 0.92 | $ | 0.88 | $ | (.26 | ) | |||||||||||||
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, 2009 were relatively flat with the three
months ended December 31, 2008 resulting from price increases of 5% offset by
sales volume decreases of 3%. Total oil sales volumes decreased
primarily from lower sales volumes in the Uinta basin where no capital activity
occurred during the first quarter of 2009 offset by increased production in
California where wells were brought back online after disruptions from the Big
West bankruptcy. The decrease in revenue when compared to the first quarter of
2008 is primarily the result of a 23% decrease in realized
prices. Natural gas revenues decreased from the quarter ended
December 31, 2008 as a result of a 13% decrease in volumes from our Piceance and
Uinta properties where no capital activity occurred during the quarter and a 9%
decrease in realized prices. Natural gas revenues were higher in the
first quarter of 2009 compared to the first quarter of 2008 from volume
increases of 69%, primarily due to the contribution of our East Texas assets and
the results of our 2008 capital program offset by a 32% decrease in realized
prices.
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.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Operating
data. The following table is for the three months ended:
|
March
31, 2009
|
%
|
March
31, 2008
|
%
|
December
31, 2008
|
%
|
|||||||||||||||||||
|
Heavy
Oil Production (Bbl/D)
|
16,436 | 50 | 16,375 | 58 | 15,999 | 45 | ||||||||||||||||||
|
Light
Oil Production (Bbl/D)
|
3,066 | 9 | 3,510 | 13 | 3,659 | 10 | ||||||||||||||||||
|
Total
Oil Production (Bbl/D)
|
19,502 | 59 | 19,885 | 71 | 19,658 | 55 | ||||||||||||||||||
|
Natural
Gas Production (Mcf/D)
|
82,979 | 41 | 49,086 | 29 | 95,548 | 45 | ||||||||||||||||||
|
Total
operations (BOE/D)
|
33,332 | 100 | 28,066 | 100 | 35,583 | 100 | ||||||||||||||||||
|
DJ
Basin Production (BOE/D)
|
3,101 | 3,157 | 3,415 | |||||||||||||||||||||
|
Production
- Continuing Operations (BOE/D)
|
30,231 | 24,909 | 32,168 | |||||||||||||||||||||
|
Oil
and gas BOE for continuing operations
|
||||||||||||||||||||||||
|
Average
sales price before hedging
|
$ | 29.36 | $ | 75.11 | $ | 40.61 | ||||||||||||||||||
|
Average
sales price after hedging
|
47.11 | 62.44 | 45.57 | |||||||||||||||||||||
|
Oil,
per Bbl, for continuing operations:
|
||||||||||||||||||||||||
|
Average
WTI price
|
$ | 43.24 | $ | 97.82 | $ | 59.08 | ||||||||||||||||||
|
Price
sensitive royalties
|
(1.02 | ) | (4.47 | ) | (1.69 | ) | ||||||||||||||||||
|
Quality
differential and other
|
(9.53 | ) | (10.78 | ) | (8.55 | ) | ||||||||||||||||||
|
Crude
oil hedges
|
23.79 | (15.60 | ) | 4.69 | ||||||||||||||||||||
|
Correction
to royalties payable
|
- | 5.85 | - | |||||||||||||||||||||
|
Average
oil sales price after hedging
|
$ | 56.48 | $ | 72.82 | $ | 53.53 | ||||||||||||||||||
|
Natural
gas price for continuing operations:
|
||||||||||||||||||||||||
|
Average
Henry Hub price per MMBtu
|
$ | 4.90 | $ | 8.74 | $ | 6.95 | ||||||||||||||||||
|
Conversion
to Mcf
|
.25 | .44 | .35 | |||||||||||||||||||||
|
Natural
gas hedges
|
1.14 | (.19 | ) | .89 | ||||||||||||||||||||
|
Location,
quality differentials and other
|
(1.27 | ) | (1.56 | ) | (2.67 | ) | ||||||||||||||||||
|
Average
gas sales price after hedging per Mcf
|
$ | 5.02 | $ | 7.43 | $ | 5.52 | ||||||||||||||||||
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
 |
Gas Basis
Differential. Natural gas prices in the Rockies continue
to decline due to various factors, including takeaway pipeline capacity,
supply / inventory volumes, and regional demand issues. We have contracted
a total of 35,000 MMBtu/D on the Rockies Express Pipeline under two
separate transactions to provide firm transport for our Piceance gas
production. The CIG basis differential per MMBtu, based upon
first-of-month values, averaged $2.81 below HH and ranged from $0.93 to
$6.61 below HH in 2008. For the first quarter of 2009, the CIG
basis averaged $1.62 below HH. The Piceance gas was sold in the
first quarter of 2009 based upon a mid-continent index such as
PEPL. For the first three months of 2009, the mid-continent
PEPL index averaged $1.51 below HH. Correspondingly, most of
the Uinta Basis gas is sold based upon a Questar index which averaged
$1.72 below HH. For E. Texas, the Texas Eastern - East Texas
index averaged $0.78 below HH for the first quarter of
2009.
|
Gas Marketing.
We have two long-term (ten year) firm transportation contracts for our
Piceance 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
Statement of Income is $0.3 million in the three month period ended March 31,
2009.
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 in 2011. As part of this
agreement and in order to access the Ruby pipeline, we also secured firm
transportation from Piceance to Opal.
Oil Contracts.
California - On March 20, 2009, we entered into a crude oil purchase
contract with a refiner for the sale of all of the Company’s crude oil
production from the Midway Sunset field. The volume approximates
12,000 barrels per day. The agreement is effective on April 1, 2009
and continues until September 30, 2009.
We
continue to market our California crude oil production, other than production
from the Midway Sunset field discussed above, to various parties. The
term of these contracts range from nine months to one
month.
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 3,280
BOE/D in the quarter ended March 31, 2009. The differential under the contract,
which includes transportation and gravity adjustments, is linked to WTI and
would range from $10 to $15 per barrel at WTI prices between $40 and $60. This
contract provides us an outlet to sell all of our current oil production in the
Uinta basin.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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.
Our
electricity margins continued to benefit from lower Rockies natural gas prices
during 2009. 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 Rocky Mountain
natural gas price differentials have been greater than California differentials
allowing us to purchase a portion of our gas at a discount to the California
price. As our electricity revenue is linked to California prices, the fuel we
purchased at lower Rocky Mountain prices is the primary contributor to our
electricity margin.
Revenues
and operating costs were down for the quarter ended March 31, 2009 from the
quarter ended March 31, 2008 due to 35% lower electricity prices and 50% lower
natural gas prices. Revenues and operating costs were down for
the quarter ended March 31, 2009 from the quarter ended December 31, 2008 due to
16% lower electricity prices and 16% lower natural gas prices, respectively. We
purchased approximately 27 MMBtu/D as fuel for use in our cogeneration
facilities in both the quarter ended March 31, 2009 and the quarter ended March
31, 2008.
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 first quarter of 2009, our margin on electricity
increased to $1.5 million.
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 is being reconsidered by
the CPUC. We do not believe that the proposed pricing changes will
materially affect us in 2009.
The
following table is for the three months ended:
|
March
31, 2009
|
March
31, 2008
|
December
31, 2008
|
||||||||||
|
Electricity
|
||||||||||||
|
Revenues
(in millions)
|
$ | 10.3 | $ | 15.9 | $ | 12.3 | ||||||
|
Operating
costs (in millions)
|
$ | 8.8 | $ | 16.4 | $ | 9.3 | ||||||
|
Electric
power produced - MWh/D
|
2,068 | 2,152 | 2,086 | |||||||||
|
Electric
power sold - MWh/D
|
1,939 | 1,959 | 1,904 | |||||||||
|
Average
sales price/MWh
|
$ | 58.85 | $ | 90.48 | $ | 69.94 | ||||||
|
Fuel
gas cost/MMBtu (including transportation)
|
$ | 4.01 | $ | 7.94 | $ | 4.80 | ||||||
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Oil and Gas
Operating, Production Taxes, G&A and Interest Expenses.
The following table presents information about our continuing operating
expenses for each of the three month periods ended:
|
Amount
per BOE
|
Amount
(in thousands)
|
|||||||||||||||||||||||
|
March
31, 2009
|
March
31, 2008
|
December
31, 2008
|
March
31, 2009
|
March
31, 2008
|
December
31, 2008
|
|||||||||||||||||||
|
Operating
costs – oil and gas production
|
$ | 13.74 | $ | 17.36 | $ | 15.07 | $ | 37,384 | $ | 39,340 | $ | 44,598 | ||||||||||||
|
Production
taxes
|
2.08 | 2.29 | 2.10 | 5,652 | 5,183 | 6,213 | ||||||||||||||||||
|
DD&A
– oil and gas production
|
13.38 | 10.68 | 12.89 | 36,398 | 24,207 | 38,133 | ||||||||||||||||||
|
G&A
|
4.89 | 4.91 | 6.07 | 13,294 | 11,132 | 17,972 | ||||||||||||||||||
|
Interest
expense
|
3.69 | 1.47 | 3.05 | 10,050 | 3,327 | 9,032 | ||||||||||||||||||
|
Total
|
$ | 37.78 | $ | 36.71 | $ | 39.18 | $ | 102,778 | $ | 83,189 | $ | 115,948 | ||||||||||||
|
|
·
|
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:
|
|
March
31, 2009
(1Q09)
|
March
31, 2008
(1Q08)
|
1Q09
to
1Q08 Change
|
December
31, 2008
(4Q08)
|
1Q09
to 4Q08 Change
|
||||||||||||||||
|
Average
volume of steam injected (Bbl/D)
|
103,342 | 91,326 | 13 | % | 105,443 | (2 | %) | |||||||||||||
|
Fuel
gas cost/MMBtu (including transportation)
|
$ | 4.01 | $ | 7.94 | (49 | %) | $ | 4.80 | (16 | %) | ||||||||||
|
Approximate
net fuel gas volume consumed in steam generation (MMBtu/D)
|
26,427 | 21,634 | 22 | % | 27,978 | (6 | %) | |||||||||||||
Operating
costs decreased by $7.2 million or 16% between the fourth quarter of 2008 and
the first quarter of 2009. The majority of the decrease came from
decreased fuel gas costs of $4 million from decreased natural gas prices and a
$1 million decrease in compression, gathering and dehydration from lower natural
gas production volumes. The remainder of the decrease is due to
decreased activity levels and our cost reduction efforts. The
decrease in operating costs from the first quarter of 2008 to the first quarter
of 2009 was also primarily due to natural gas prices which decreased 49%,
offset, on an absolute basis by the addition of our East Texas
assets.
|
|
·
|
Production
taxes: 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.
Our production taxes have remained consistent on a per BOE basis and
primarily fluctuates with changes in oil and natural gas
prices.
|
|
|
·
|
Depreciation,
depletion and amortization: DD&A increased per BOE by 25% and 4%
in the first quarter of 2009 as compared to the first quarter of 2008 and
fourth quarter of 2008, respectively. The increase per BOE is 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 reasons for the increase in G&A during the
first quarter of 2009 as compared to the first quarter of 2008 were due to
director compensation of $0.9 million which was paid in the first quarter
of 2009 and additional staffing related to our 2008 East Texas
acquisition. General and administrative costs for the quarter
ended December 31, 2008 included $2.3 million of rig termination
penalties, $0.6 million of costs to complete the relocation of our
corporate headquarters and the costs to establish our regional office in
E. Texas.
|
|
|
·
|
Interest
expense: Our total outstanding borrowings were approximately $1.2 billion
at March 31, 2009 compared to $455 million and $1.2 billion at March
31, 2008 and December 31, 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 March
31, 2009, $5 million of interest cost has been capitalized and we expect
to capitalize approximately $25 million of interest cost during the full
year of 2009.
|
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Estimated 2009
and Actual Three Months Ended March 31, 2009 and 2008 Oil and Gas
Operating, G&A and
Interest Expenses.
Based upon our reduced activity in the fourth quarter of 2008, we estimate our
average 2009 production volume will be approximately 30,000
BOE/D.
|
Anticipated
range
|
||||||||||||
|
Full
Year 2009
per
BOE
|
Three
months ended March 31, 2009
|
Three
months ended March 31, 2008
|
||||||||||
|
Operating
costs-oil and gas production
|
$ | 13.50 - 15.00 | $ | 13.74 | $ | 17.36 | ||||||
|
Production
taxes
|
1.50 - 2.50 | 2.08 | 2.29 | |||||||||
|
DD&A
– oil and gas production (1)
|
13.50 - 14.50 | 13.38 | 10.68 | |||||||||
|
G&A
|
4.25 - 4.75 | 4.89 | 4.91 | |||||||||
|
Interest
expense
|
4.00 - 4.75 | 3.69 | 1.47 | |||||||||
|
Total
|
$ | 36.75- 41.50 | $ | 37.78 | $ | 36.71 | ||||||
(1)
Full year estimate includes both oil and gas and electricity
Asset
Dispositions. On March 3, 2009, we entered into an agreement
to sell our DJ basin assets and related hedges for $154 million before
customary closing adjustments. The $14 million sale of our DJ basin related
hedges was completed in March 2009 and is recorded under the caption “Gain on
hedge terminations” in the condensed statements of income and is included in
operating cash flows for the three months ended March 31, 2009. We received
a deposit of $14 million on the sale of the DJ basin assets which is included in
“Accrued Liabilities” on the condensed balance sheets as of March 31,
2009. The closing date of the sale of our DJ basin assets was April
1, 2009. In accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, these properties have been separately
presented in the accompanying balance sheet at fair value less estimated costs
to sell, which were determined as of March 31, 2009. We recorded an impairment
charge of $9.6 million, which is aggregated within “(loss) income from
discontinued operations, net of tax,” on the condensed statements of income for
the three months ended March 31, 2009.
Dry
Hole, Abandonment, impairment and exploration. In the
three months ended March 31, 2009 and 2008, we recorded dry hole, abandonment,
impairment and exploration expense of $0.1 million and $2.7 million,
respectively. In the first quarter of 2008, technical
difficulties on three wells in the Piceance basin were encountered before
reaching total depth and these holes were abandoned, in favor of drilling to the
same bottom hole location by drilling a new well.
Income
Taxes. We experienced an effective tax rate of 33.9% and 39.1% in the
three months ended March 31, 2009 and March 31, 2008,
respectively. 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. See Note 9 to the condensed
financial statements.
Development, Exploitation and
Exploration Activity. We drilled 26 gross (26 net) wells during the first
quarter of 2009.
Drilling
Activity. The following table sets
forth certain information regarding drilling activities (including operated and
non-operated wells):
|
Three
months ended March 31, 2009
|
||||||||
|
Asset
Team
|
Gross
Wells
|
Net
Wells
|
||||||
|
S.
Midway
|
8 | 8 | ||||||
|
N.
Midway
|
15 | 15 | ||||||
|
Texas
|
3 | 3 | ||||||
|
Totals
|
26 | 26 | ||||||
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
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. This FSP became
effective for our fiscal year beginning January 1, 2009 and we expanded our
disclosures accordingly.
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 adopted this Statement January 1, 2009 and it did
not have a material effect on our 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. We adopted this Statement January 1, 2009 and we expanded our
disclosures accordingly.
In June
2008, the FASB issued FASB Staff Position No. EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities ("FSP EITF 03-6-1"), which clarifies that
share-based payment awards that entitle their holders to receive nonforfeitable
dividends before vesting should be considered participating securities. As
participating securities, these instruments should be included in the earnings
allocation in computing basic earnings per share under the two-class method
described in SFAS No. 128, Earnings per Share. All prior period
earnings per share data presented shall be adjusted retrospectively to conform
with the provisions of this pronouncement. FSP EITF 03-6-1 is
effective for financial statements issued for fiscal years beginning after
December 15, 2008 and interim periods within those years. We implemented
EITF 03-06-1 during the first quarter of 2009, see Note 10 to the financial
statements.
In April
2009, the FASB issued FSP No. FAS 107-1, Interim Disclosures about Fair Value
of Financial Instruments. FSP 107-1 requires disclosures about fair value of financial
instruments for interim reporting periods as well as in annual financial
statements. FSP 107-1 will be effective for us for the quarter ending
June 30, 2009. The adoption of FSP 107-1 will not have an impact on
our financial position and results of operations.
Properties
Asset
Team Descriptions
To
improve the efficiency of our operations we have consolidated our S.
Cal Asset Team into the S. Midway and N. Midway Asset Teams. The Poso
Creek Field has been incorporated into the S. Midway Asset Team and the
Placerita Field into our N. Midway Asset Team.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
S. Midway
– Our S. Midway Asset Team now includes four assets (Poso Creek, Ethel D,
Homebase and Formax). We are in the process of drilling 10 additional
Homebase horizontal wells. These wells have been placed deeper and
closer to the oil-water contact. The first 8 of these wells are
currently on production and performing in line with expectations. At
Ethel D we are evaluating the steam flood pilots in preparation for future steam
flood expansion. Poso Creek production is recovering from the
disruptions associated with the Big West bankruptcy. Further
production recovery is expected as the number of steam flood patterns is
increased and as the steam flood patterns developed in 2008
respond. The team is focused on improving steam-oil ratios and
lowering operating expenses in all of its operations. Average daily
production during the three months ended March 31, 2009 from all S. Midway
assets was approximately 11,350 BOE/D.
N.
Midway – Our N. Midway Asset Team now includes three assets
(Diatomite, N. Midway, and Placerita). We began the full scale
development of our N. Midway diatomite asset in late 2006 and through the end of
2008 drilled 190 wells on this property. The delineation drilling in 2008
increased our original oil in place estimates by 35% to 330 million barrels. We
are targeting ultimate recovery between 23% and 40%, similar to other diatomite
developments in California.
We plan
to invest $37 million during 2009 to drill an additional 44 diatomite wells and
install additional steam generation facilities during 2009 and have drilled 15
of these wells. Additionally, we are seeking operating and capital cost
reductions through initiatives such as steam management to improve our steam oil
ratio and improved project management to reduce overall well costs. Production
in the first quarter of 2009 was 2,670 Bbl/D and is expected to average over
3,000 Bbl/D for the year. Average daily production during the three months
ended March 31, 2009 from all N. Midway assets was approximately 5,085
BOE/D.
Piceance – During the
three months ended March 31, 2009, production from the Piceance basin averaged
20 MMcf/D. No drilling or completion activity was performed during
the quarter. Currently we have an inventory of 44 initial completions
and recompletions that will be evaluated for supplemental capital should
commodity prices warrant.
Uinta
–
Average daily production during the three months ended March 31, 2009
from all Uinta basin assets was approximately 5,410 BOE/D. No
drilling or completion activity was performed during the quarter. The
Ashley Forest Development EIS continues to progress with approval now expected
in the second half of 2009.
DJ – In March 2009, we
announced the sale of our DJ basin assets and related hedges for approximately
$154 million. Our assets in the DJ basin produced 3,100 BOE/D during
the first quarter of 2009. The sale of these assets closed on April
1, 2009.
E. Texas
– During the
three months ended March 31, 2009, production from our East Texas assets
averaged 30 MMcf/D. We continue to operate a one rig program and
drilled three vertical wells in the Oakes field during the first quarter of
2009. We are currently drilling the fourth of the five planned
vertical Oakes wells for 2009. After completion of drilling in the
Oakes field, we expect to begin drilling in the Darco Field with our first
horizontal Haynesville well.
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.
Liquidity. The
total outstanding debt at March 31, 2009 under the Agreement and the Line of
Credit was $999 million and $0, respectively, and $3 million in letters of
credit have been issued under the facility, leaving $208 million in borrowing
capacity available under the Agreement at March 31,
2009.
On April
27, 2009, we completed the scheduled redetermination of the borrowing under our
credit facility. Our borrowing base was reduced from $1.25 billion to
$1.05 billion, with $100 million of the reduction resulting from the sale of our
DJ basin assets. Also on April 27, 2009 we completed a $140 million
second lien credit facility, with lenders from among our existing lending group,
which matures on January 16, 2013. Interest on the facility is
charged at LIBOR plus a margin of eight percent with a minimum LIBOR rate of
three percent. Each dollar outstanding under the second lien credit
facility reduces the borrowing base under our senior secured credit facility by
30 cents such that the $140 million second lien facility reduces our borrowing
base from $1.05 billion to $1.0 billion. Proceeds from the second lien facility
were used to pay down borrowings under our senior secured credit facility. On
April 27, 2009, following the closing of the second lien credit facility, the
outstanding amount under our senior secured credit facility was approximately
$735 million providing us with $275 million of liquidity. With the
second lien facility in place, we expect our weighted average interest rate to
increase from 4.2% at March 31, 2009 to 5.0% for the remainder of 2009,
based on current LIBOR rates.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Capital
Expenditure and Cash
Flows. 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 2009,
we have a capital program of approximately $100 million and we expect to fully
fund this program from operating cash flow which should approximate $175
million. Cash provided by operating activities was impacted in the
first quarter of 2009 by an annual royalty payment of $22 million which is paid
each February and a reduction in accounts payable which, at year-end 2008,
reflected our higher 2008 capital budget. Approximately 90% of our
oil production is hedged for 2009 and thus our sensitivity to changes in oil
prices is limited. A ten dollar change in oil prices impacts our
annual operating cash flow by approximately $2 million in 2009. A one
dollar change in natural gas prices impacts our annual operating cash flow by
approximately $5 million.
Capital
expenditures, excluding property acquisitions, totaled $50.2 million during the
three months ended March 31, 2009. A portion of our capital budget
reflects expenditures to complete projects initiated during 2008 and we expect
lower quarterly expenditures for the remainder of 2009.
Working
Capital. Cash flow from
operations is dependent upon the price of crude oil and natural gas and our
ability to increase production and manage costs. Our working capital balance
fluctuates as a result of the amount of borrowings and the timing of repayments
under our credit arrangements. We use our long-term borrowings under our credit
facility primarily to fund property acquisitions. Generally, we use excess cash
to pay down borrowings under our credit arrangement. As a result, we often have
a working capital deficit or a relatively small amount of positive working
capital.
The table
below compares continuing operations, financial condition, liquidity
and capital resources changes for the three month periods ended (in millions,
except for production and average prices):
|
March
31, 2009
(1Q09)
|
March
31, 2008
(1Q08)
|
1Q09
to 1Q09 Change
|
December
31, 2008
(4Q08)
|
1Q09
to 4Q08 Change
|
||||||||||||||||
|
Average
production (BOE/D)
|
33,332 | 28,066 | 19 | % | 35,583 | (6 | %) | |||||||||||||
|
Average
oil and gas sales prices, per BOE after hedging
|
$ | 47.11 | $ | 62.44 | (25 | %) | $ | 45.57 | 3 | % | ||||||||||
|
Net
cash provided by operating activities
|
$ | 8 | $ | 87 | (91 | %) | $ | 78 | (90 | %) | ||||||||||
|
Working
capital (deficit)
|
$ | 169 | $ | (123 | ) | 237 | % | $ | (72 | ) | 335 | % | ||||||||
|
Sales
of oil and gas
|
$ | 128 | $ | 152 | (16 | %) | $ | 135 | (5 | %) | ||||||||||
|
Total
debt
|
$ | 1,199 | $ | 455 | 164 | % | $ | 1,157 | 4 | % | ||||||||||
|
Capital
expenditures
|
$ | 50 | $ | 76 | (34 | %) | $ | 92 | (46 | %) | ||||||||||
|
Dividends
paid
|
$ | 3.4 | $ | 3.3 | 3 | % | $ | 3.4 | - | % | ||||||||||
Contractual
Obligations. Our contractual
obligations as of March 31, 2009 are as follows (in millions):
|
Total
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
||||||||||||||||||||||
|
Total
debt and interest
|
$ | 1,358.8 | $ | 46.8 | $ | 46.8 | $ | 46.8 | $ | 952.3 | $ | 16.5 | $ | 249.6 | ||||||||||||||
|
Abandonment
obligations
|
40.1 | 1.6 | 1.6 | 1.6 | 1.6 | 1.6 | 32.1 | |||||||||||||||||||||
|
Operating
lease obligations
|
17.8 | 1.9 | 2.4 | 2.5 | 2.4 | 2.5 | 6.1 | |||||||||||||||||||||
|
Drilling
and rig obligations
|
45.6 | 11.4 | 8.0 | 8.0 | 18.2 | - | - | |||||||||||||||||||||
|
Firm
natural gas transportation contracts
|
160.1 | 14.9 | 19.8 | 19.8 | 19.7 | 17.5 | 68.4 | |||||||||||||||||||||
|
Total
|
$ | 1,622.4 | $ | 76.6 | $ | 78.6 | $ | 78.7 | $ | 994.2 | $ | 38.1 | $ | 356.2 | ||||||||||||||
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, 2009 we have
drilled 29 of these wells and we expect to meet our February 2011
obligation.
Berry
Petroleum Company
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
Other Obligations -
As of March 31, 2009 we had a gross liability for uncertain tax benefits of
$11.2 million of which $10.0 million, if recognized, would affect the effective
tax rate. We are unable to predict the year in which these uncertain
tax positions will be settled and have excluded these commitments from the table
above.
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 $10 to $15 per barrel at WTI prices between $40 and
$60. Gross oil production averaged approximately 3,280 BOE/D in the
quarter ended March 31, 2009.
Berry
Petroleum Company
Quantitative
and Qualitative Disclosures About Market Risk
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.
Berry
Petroleum Company
Quantitative
and Qualitative Disclosures About Market Risk
The
following table summarizes our hedge position as of March 31, 2009:
|
Average
|
||||||||
|
Barrels
|
Average
|
|||||||
|
Term
|
Per
Day
|
Prices
|
||||||
|
Crude Oil Sales (NYMEX WTI)
Collars
|
||||||||
|
Full
year 2009
|
295 | $ | 80.00/$91.00 | |||||
|
Full
year 2009
|
1,000 | $ | 100.00/$163.60 | |||||
|
Full
year 2009
|
1,000 | $ | 100.00/$150.30 | |||||
|
Full
year 2009
|
1,000 | $ | 100.00/$160.00 | |||||
|
Full
year 2009
|
1,000 | $ | 100.00/$150.00 | |||||
|
Full
year 2009
|
1,000 | $ | 100.00/$157.48 | |||||
|
Full
year 2010
|
1,000 | $ | 65.15 / $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 2010
|
1,000 | $ | 70.00/$86.00 | |||||
|
Full
year 2011
|
270 | $ | 80.00 / $90.00 | |||||
|
Full
year 2011
|
1,000 | $ | 55.20/$70.00 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00 / $70.50 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00/$68.65 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00/$68.00 | |||||
|
Full
year 2011
|
1,000 | $ | 55.00/$71.20 | |||||
|
Full
year 2011
|
1,000 | $ | 60.00/$76.00 | |||||
|
Full
year 2011
|
1,000 | $ | 60.00/$81.25 | |||||
|
Full
year 2012
|
1,000 | $ | 63.00/$82.60 | |||||
|
Crude
Oil Sales (NYMEX WTI) Swaps
|
||||||||
|
May
2009
|
1,000 | $ | 55.60 | |||||
|
June
2009
|
400 | $ | 57.00 | |||||
|
Full
year 2009
|
240 | $ | 71.50 | |||||
|
Full
year 2009
|
1,000 | $ | 70.30 | |||||
|
Full
year 2009
|
1,000 | $ | 70.50 | |||||
|
3rd
Quarter 2009
|
500 | $ | 52.40 | |||||
|
2nd,
3rd & 4th Quarters 2009
|
2,000 | $ | 55.00 | |||||
|
Full
year 2009
|
1,000 | $ | 54.67 | |||||
|
Full
year 2009
|
2,000 | $ | 54.10 | |||||
|
Full
year 2009
|
5,000 | $ | 54.39 | |||||
|
Full
year 2010
|
1,000 | $ | 61.00 | |||||
|
Full
year 2010
|
1,000 | $ | 61.25 | |||||
|
Full
year 2010
|
1,000 | $ | 64.80 | |||||
|
Full
year 2010
|
1,000 | $ | 62.03 | |||||
|
Full
year 2010
|
1,000 | $ | 63.00 | |||||
|
Full
year 2010
|
1,000 | $ | 63.75 | |||||
|
Full
year 2010
|
650 | $ | 56.90 | |||||
|
Full
year 2011
|
500 | $ | 57.36 | |||||
|
Full
year 2011
|
500 | $ | 57.40 | |||||
|
Full
year 2011
|
500 | $ | 57.50 | |||||
|
Full
year 2011
|
250 | $ | 61.80 | |||||
|
Average
|
||||||||
|
MMBtu
|
Average
|
|||||||
|
Term
|
Per
Day
|
Price
|
||||||
|
Natural
Gas Sales (NYMEX HH TO PEPL) Basis Swaps
|
||||||||
|
4th
quarter 2009
|
4,000 | $ | 1.05 | |||||
|
Full
year 2009
|
2,000 | $ | 1.24 | |||||
|
Full
year 2009
|
3,000 | $ | 1.19 | |||||
|
Full
year 2010
|
2,000 | $ | 1.05 | |||||
|
Full
year 2010
|
3,000 | $ | 1.00 | |||||
|
Natural
Gas Sales (NYMEX HH) Swaps
|
||||||||
|
Full
year 2009
|
2,000 | $ | 6.15 | |||||
|
Full
year 2009
|
3,000 | $ | 6.19 | |||||
|
4th
quarter 2009
|
4,000 | $ | 8.50 | |||||
|
Natural
Gas Sales (NYMEX HH) Collars
|
||||||||
|
Full
year 2010
|
2,000 | $ | 6.00/$8.60 | |||||
|
Full
year 2010
|
3,000 | $ | 6.00/$8.65 | |||||
|
Full
year 2010
|
1,000 | $ | 6.50/$8.75 | |||||
|
Full
year 2010
|
1,000 | $ | 6.50/$8.85 | |||||
|
Full
year 2010
|
2,000 | $ | 6.50/$8.90 | |||||
|
Natural Gas Sales (NYMEX HH TO
NGPL) Basis Swaps
|
||||||||
|
Full
year 2010
|
2,000 | $ | 0.49 | |||||
|
Natural
Gas Sales (NYMEX HH TO HSC) Basis Swaps
|
||||||||
|
Full
year 2010
|
2,000 | $ | 0.38 | |||||
Berry
Petroleum Company
Quantitative
and Qualitative Disclosures About Market Risk
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if prices decline below our floor prices while still
participating in any price increase up to the ceiling prices. 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, a portion of the hedges
related to the movement in the WTI to California heavy crude oil price
differential will likely 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
mark-to-market values reflect the fair values of such hedges and not necessarily
the values of the hedges if they are held to maturity.
In
December 2008, Big West Oil of California filed for bankruptcy protection under
Chapter 11 of the United States Bankruptcy Code. Our contract with
Big West provided for an oil price differential that was linked to NYMEX WTI
prices and allowed us to effectively hedge our oil production at the NYMEX WTI
index. Subsequent to the Big West bankruptcy, our crude oil has been
sold at field posting prices which resulted in some ineffectiveness related to
our WTI linked hedges. We recognized an unrealized net gain of
approximately $22.8 million in the condensed statement of income under the
caption “Gain (loss) on ineffective commodity derivatives” for the quarter ended
March 31, 2009 as a result of this ineffectiveness.
We have
entered into interest rate hedges as shown below to swap the floating rate under
our senior secured credit facility (LIBOR) for a fixed interest
rate These interest rate swaps have been designated as cash flow
hedges.
|
Notional
|
||||||||
|
Amount
|
||||||||
|
Hedge
Term
|
$MM
|
Fixed
Rate
|
||||||
|
4/1/2009
– 6/30/2012
|
100 | 4.74 | % | |||||
|
4/15/2009
– 7/15/2012
|
150 | 1.95 | % | |||||
|
9/15/2009
– 7/15/2012
|
150 | 2.44 | % | |||||
|
12/15/2009
– 7/15/2012
|
125 | 2.03 | % | |||||
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.
Berry
Petroleum Company
Quantitative
and Qualitative Disclosures About Market Risk
Based on
average NYMEX futures prices as of March 31, 2009 (WTI $63.88; HH $5.15) for the
term of our hedges we would expect to make pre-tax future cash payments or to
receive payments over the remaining term of our crude oil and natural gas hedges
in place as follows:
|
Impact
of percent change in futures prices
|
||||||||||||||||||||
|
March
31, 2009
|
on
pre-tax future cash (payments) and receipts
|
|||||||||||||||||||
|
NYMEX
Futures
|
-40 | % | -20 | % | + 20 | % | +40 | % | ||||||||||||
|
Average
WTI Futures Price (2009 – 2012)
|
$ | 63.88 | $ | 38.33 | $ | 51.11 | $ | 76.66 | $ | 89.43 | ||||||||||
|
Average
HH Futures Price (2009 – 2010)
|
5.15 | 3.09 | 4.12 | 6.19 | 7.22 | |||||||||||||||
|
Crude
Oil gain/(loss) (in millions)
|
$ | 153.8 | $ | 472.0 | $ | 297.9 | $ | 6.1 | $ | (159.5 | ) | |||||||||
|
Natural
Gas gain/(loss) (in millions)
|
3.1 | 21.4 | 18.6 | 14.8 | 15.2 | |||||||||||||||
|
Total
|
$ | 156.9 | $ | 493.4 | $ | 316.5 | $ | 20.9 | $ | (144.3 | ) | |||||||||
|
Net
pre-tax future cash (payments) and receipts by year (in millions) based on
average price in each year:
|
||||||||||||||||||||
|
2009
(WTI $53.70; HH $4.25)
|
$ | 80.5 | $ | 192.1 | $ | 139.1 | $ | 33.0 | $ | (20.1 | ) | |||||||||
|
2010
(WTI $61.92; HH $5.84)
|
81.1 | 237.3 | 162.7 | 24.8 | (39.0 | ) | ||||||||||||||
|
2011
(WTI $67.24)
|
(4.7 | ) | 56.4 | 12.1 | (36.4 | ) | (79.5 | ) | ||||||||||||
|
2012
(WTI $70.12)
|
- | 7.6 | 2.6 | (0.5 | ) | (5.7 | ) | |||||||||||||
|
Total
|
$ | 156.9 | $ | 493.4 | $ | 316.5 | $ | 20.9 | $ | (144.3 | ) | |||||||||
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 March 31, 2009, total
long-term debt outstanding was $1.2 billion. Interest on amounts borrowed under
our credit facility is charged at LIBOR plus 2.25% to 3.0%, with the exception
of the principal for which we have hedged, plus the credit facility’s margin
through July 15, 2012. Based on March 31, 2009 credit facility borrowings, a 1%
change in interest rates would have an annualized $3 million after tax
impact on our financial statements.
Berry
Petroleum Company
Controls
and Procedures
Item 4. Controls and Procedures
As of
March 31, 2009, 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, 2009, 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, and include controls and procedures designed
to ensure that information required to be disclosed by us in such reports is
accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure.
There was
no change in our internal control over financial reporting that occurred during
the three months ended March 31, 2009 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 15 of our Form 10-K dated February 25, 2009, 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.
Berry
Petroleum Company
Part II. Other
Information
PART II. OTHER
INFORMATION
Item
1. Legal Proceedings
None.
Item
1A. Risk Factors
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.
Berry
Petroleum Company
Part II. Other
Information
Item
6. Exhibits
|
Exhibit No.
|
Description of Exhibit
|
|
10.1*
|
Crude
Oil Purchase Contract dated March 20, 2009 between the [Registrant] and
Tesoro Corporation.
|
|
10.2
|
Third
Amendment to Amended and Restated Credit Agreement dated April 27, 2009 by
and among Registrant, Wells Fargo Bank National Association, individually
and as administrative agent, and certain financial institutions, as
lenders.
|
|
10.3
|
Second
Lien Credit Agreement dated April 27, 2009 among Registrant, Wells Fargo
Energy Capital, Inc., as administrative agent, and certain financial
institutions, as Lenders and agents.
|
|
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
|
*
Portions of this exhibit have been omitted pursuant to a request for
confidential treatment.
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: April
30, 2009
36