BERRY PETROLEUM COMPANY FORM 10-Q FOR THE FIRST QUARTER ENDED 03-31-07
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, 2007
oTransition
Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934
For
the
transition period from __to
___
Commission
file number
1-9735
BERRY
PETROLEUM COMPANY
(Exact
name of registrant as specified in its charter)
|
DELAWARE
|
|
77-0079387
|
|
|
(State
of incorporation or organization)
|
|
(I.R.S.
Employer Identification Number)
|
|
5201
Truxtun Avenue, Suite 300
Bakersfield,
California 93309
(Address
of principal executive offices, including zip code)
Registrant's
telephone number, including area code: (661)
616-3900
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. YES
x
NO
o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filerx Accelerated
filero Non-accelerated
filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). YES
o
NO
x
As
of
April 18, 2007, the registrant had 42,196,896 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 18, 2007 all of which is held
by
an affiliate of the registrant.
BERRY
PETROLEUM COMPANY
FIRST
QUARTER 2007 FORM 10-Q
TABLE
OF CONTENTS
PART
I. FINANCIAL INFORMATION
|
|
Page
|
|
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|
|
Item
1. Financial Statements
|
|
|
|
|
|
Unaudited
Condensed Balance Sheets at March 31, 2007 and December 31,
2006
|
3
|
|
|
|
|
Unaudited
Condensed Statements of Income for the Three Month Periods Ended
March 31,
2007 and 2006
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income for the Three Month
Periods
Ended March 31, 2007 and 2006
|
4
|
|
|
|
|
Unaudited
Condensed Statements of Cash Flows for the Three Month Periods Ended
March
31, 2007 and 2006
|
5
|
|
|
|
|
Notes
to Unaudited Condensed Financial Statements
|
6
|
|
|
|
|
Item
2. Management’s Discussion and Analysis of Financial Condition and Results
of Operations
|
10
|
|
|
|
|
Item
3. Quantitative and Qualitative Disclosures About Market
Risk
|
18
|
|
|
|
|
Item
4. Controls and Procedures
|
20
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|
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|
|
|
|
|
|
|
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|
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PART
II.
OTHER
INFORMATION
|
|
|
|
|
|
|
Item
1. Legal Proceedings
|
21
|
|
|
|
|
Item
1A. Risk Factors
|
21
|
|
|
|
|
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
|
21
|
|
|
|
|
Item
3. Defaults Upon Senior Securities
|
21
|
|
|
|
|
Item
4. Submission of Matters to a Vote of Security Holders
|
21
|
|
|
|
|
Item
5. Other Information
|
21
|
|
|
|
|
Item
6. Exhibits
|
21
|
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Balance Sheets
(In
Thousands, Except Share Information)
|
|
|
March
31, 2007
|
|
|
December
31, 2006
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
95
|
|
$
|
416
|
|
Short-term
investments
|
|
|
665
|
|
|
665
|
|
Accounts
receivable
|
|
|
77,893
|
|
|
67,905
|
|
Deferred
income taxes
|
|
|
5,415
|
|
|
-
|
|
Fair
value of derivatives
|
|
|
7,936
|
|
|
7,349
|
|
Assets
held for sale
|
|
|
8,870
|
|
|
8,870
|
|
Prepaid
expenses and other
|
|
|
15,813
|
|
|
13,604
|
|
Total
current assets
|
|
|
116,687
|
|
|
98,809
|
|
Oil
and gas properties (successful efforts basis), buildings and equipment,
net
|
|
|
1,142,892
|
|
|
1,080,631
|
|
Fair
value of derivatives
|
|
|
700
|
|
|
2,356
|
|
Other
assets
|
|
|
16,618
|
|
|
17,201
|
|
|
|
$
|
1,276,897
|
|
$
|
1,198,997
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
63,884
|
|
$
|
69,914
|
|
Property
acquisition payable
|
|
|
54,400
|
|
|
54,400
|
|
Revenue
and royalties payable
|
|
|
13,801
|
|
|
45,845
|
|
Accrued
liabilities
|
|
|
24,848
|
|
|
20,415
|
|
Line
of credit
|
|
|
7,000
|
|
|
16,000
|
|
Other
current liabilities
|
|
|
1,691
|
|
|
-
|
|
Deferred
income taxes
|
|
|
-
|
|
|
745
|
|
Fair
value of derivatives
|
|
|
22,942
|
|
|
8,084
|
|
Total
current liabilities
|
|
|
188,566
|
|
|
215,403
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
102,758
|
|
|
103,515
|
|
Long-term
debt
|
|
|
470,000
|
|
|
390,000
|
|
Abandonment
obligation
|
|
|
30,958
|
|
|
26,135
|
|
Unearned
revenue
|
|
|
1,133
|
|
|
1,437
|
|
Other
long-term liabilities
|
|
|
9,290
|
|
|
-
|
|
Fair
value of derivatives
|
|
|
39,936
|
|
|
34,807
|
|
|
|
|
654,075
|
|
|
555,894
|
|
Shareholders'
equity:
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 2,000,000 shares authorized; no shares
outstanding
|
|
|
-
|
|
|
-
|
|
Capital
stock, $.01 par value:
|
|
|
|
|
|
|
|
Class
A Common Stock, 100,000,000 shares authorized; 42,191,896 shares
issued
and outstanding (42,098,551 in 2006)
|
|
|
422
|
|
|
421
|
|
Class
B Stock, 3,000,000 shares authorized; 1,797,784 shares issued and
outstanding (liquidation preference of $899)
|
|
|
18
|
|
|
18
|
|
Capital
in excess of par value
|
|
|
53,594
|
|
|
50,166
|
|
Accumulated
other comprehensive loss
|
|
|
(32,347
|
)
|
|
(19,977
|
)
|
Retained
earnings
|
|
|
412,569
|
|
|
397,072
|
|
Total
shareholders' equity
|
|
|
434,256
|
|
|
427,700
|
|
|
|
$
|
1,276,897
|
|
$
|
1,198,997
|
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Income
Three
Month Periods Ended March 31, 2007 and 2006
(In
Thousands, Except Per Share Data)
|
|
|
|
|
|
Three
months ended March 31,
|
|
|
|
|
|
|
|
2007
|
|
|
2006
(1)
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
Sales
of oil and gas
|
|
|
|
|
$
|
101,773
|
|
$
|
101,932
|
|
Sales
of electricity
|
|
|
|
|
|
14,596
|
|
|
15,169
|
|
Interest
and other income, net
|
|
|
|
|
|
1,110
|
|
|
493
|
|
|
|
|
|
|
|
117,479
|
|
|
117,594
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Operating
costs - oil and gas production
|
|
|
|
|
|
33,610
|
|
|
25,738
|
|
Operating
costs - electricity generation
|
|
|
|
|
|
14,170
|
|
|
14,332
|
|
Production
taxes
|
|
|
|
|
|
3,815
|
|
|
3,233
|
|
Depreciation,
depletion & amortization - oil and gas production
|
|
|
|
|
|
18,725
|
|
|
13,223
|
|
Depreciation,
depletion & amortization - electricity generation
|
|
|
|
|
|
762
|
|
|
767
|
|
General
and administrative
|
|
|
|
|
|
10,307
|
|
|
8,314
|
|
Interest
|
|
|
|
|
|
4,292
|
|
|
1,577
|
|
Commodity
derivatives
|
|
|
|
|
|
-
|
|
|
4,828
|
|
Dry
hole, abandonment, impairment and exploration
|
|
|
|
|
|
649
|
|
|
7,498
|
|
|
|
|
|
|
|
86,330
|
|
|
79,510
|
|
Income
before income taxes
|
|
|
|
|
|
31,149
|
|
|
38,084
|
|
Provision
for income taxes
|
|
|
|
|
|
12,294
|
|
|
14,833
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
18,855
|
|
$
|
23,251
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
net income per share
|
|
|
|
|
$
|
.43
|
|
$
|
.53
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
net income per share
|
|
|
|
|
$
|
.42
|
|
$
|
.52
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
per share
|
|
|
|
|
$
|
.075
|
|
$
|
.065
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of shares of capital stock outstanding (used to calculate
basic net income per share)
|
|
|
|
|
|
43,916
|
|
|
43,988
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
Equity
based compensation
|
|
|
|
|
|
603
|
|
|
918
|
|
Director
deferred compensation
|
|
|
|
|
|
112
|
|
|
98
|
|
Weighted
average number of shares of capital stock used to calculate diluted
net
income per share
|
|
|
|
|
|
44,631
|
|
|
45,004
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Condensed Statements of Comprehensive Income
|
|
Three
Month Periods Ended March 31, 2007 and 2006
|
(In
Thousands)
|
Net
income
|
|
|
|
|
$
|
18,855
|
|
$
|
23,251
|
|
Unrealized
gains (losses) on derivatives, net of income taxes of ($7,885) and
($14,184), respectively
|
|
|
|
|
|
(11,828
|
)
|
|
(21,276
|
)
|
Reclassification
of realized losses included in net income net of income taxes of
($361)
and ($2,545), respectively
|
|
|
|
|
|
(542
|
)
|
|
(3,818
|
)
|
Comprehensive
income
|
|
|
|
|
$
|
6,485
|
|
$
|
(1,843
|
)
|
The
accompanying notes are an integral part of these financial
statements.
(1)
The
2006 per share and share amounts have been restated to give retroactive effect
to the two-for-one stock split that became effective on May 17, 2006. See Note
2.
BERRY
PETROLEUM COMPANY
Unaudited
Condensed Statements of Cash Flows
Three
Month Periods Ended March 31, 2007 and 2006
(In
Thousands)
|
|
|
|
|
|
Three
months ended March 31,
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
Cash
flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
$
|
18,855
|
|
$
|
23,251
|
|
Depreciation,
depletion and amortization
|
|
|
|
|
|
19,487
|
|
|
13,990
|
|
Dry
hole
|
|
|
|
|
|
188
|
|
|
5,209
|
|
Abandonment
and impairment
|
|
|
|
|
|
(256
|
)
|
|
(224
|
)
|
Commodity
derivatives
|
|
|
|
|
|
439
|
|
|
4,828
|
|
Stock-based
compensation expense, net of taxes
|
|
|
|
|
|
1,792
|
|
|
1,014
|
|
Deferred
income taxes, net
|
|
|
|
|
|
12,311
|
|
|
7,464
|
|
Other,
net
|
|
|
|
|
|
209
|
|
|
52
|
|
(Increase)
in current assets other than cash, cash equivalents and short-term
investments
|
|
|
|
|
|
(13,289
|
)
|
|
(1,936
|
)
|
(Decrease)
in current liabilities other than book overdraft, line of credit,
property
acquisition payable and fair value of derivatives
|
|
|
|
|
|
(28,119
|
)
|
|
(28,331
|
)
|
Net
cash provided by operating activities
|
|
|
|
|
|
11,617
|
|
|
25,317
|
|
Cash
flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
Exploration
and development of oil and gas properties
|
|
|
|
|
|
(73,472
|
)
|
|
(41,345
|
)
|
Property
acquisitions
|
|
|
|
|
|
(1,088
|
)
|
|
(159,016
|
)
|
Additions
to vehicles, drilling rigs and other fixed assets
|
|
|
|
|
|
(1,018
|
)
|
|
(5,723
|
)
|
Deposit
on potential sale of asset
|
|
|
|
|
|
3,000
|
|
|
-
|
|
Capitalized
interest and other
|
|
|
|
|
|
(3,998
|
)
|
|
-
|
|
Net
cash used in investing activities
|
|
|
|
|
|
(76,576
|
)
|
|
(206,084
|
)
|
Cash
flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of line of credit
|
|
|
|
|
|
21,000
|
|
|
51,000
|
|
Payment
of line of credit
|
|
|
|
|
|
(30,000
|
)
|
|
(53,000
|
)
|
Proceeds
from issuance of long-term debt
|
|
|
|
|
|
90,000
|
|
|
219,750
|
|
Payment
of long-term debt
|
|
|
|
|
|
(10,000
|
)
|
|
(45,750
|
)
|
Dividends
paid
|
|
|
|
|
|
(3,295
|
)
|
|
(2,867
|
)
|
Change
in book overdraft
|
|
|
|
|
|
(4,711
|
)
|
|
9,881
|
|
Repurchase
of shares of common stock
|
|
|
|
|
|
-
|
|
|
(1,802
|
)
|
Proceeds
from stock option exercises
|
|
|
|
|
|
1,148
|
|
|
1,144
|
|
Excess
tax benefit and other
|
|
|
|
|
|
496
|
|
|
1,806
|
|
Net
cash provided by financing activities
|
|
|
|
|
|
64,638
|
|
|
180,162
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
decrease in cash and cash equivalents
|
|
|
|
|
|
(321
|
)
|
|
(605
|
)
|
Cash
and cash equivalents at beginning of year
|
|
|
|
|
|
416
|
|
|
1,990
|
|
Cash
and cash equivalents at end of period
|
|
|
|
|
$
|
95
|
|
$
|
1,385
|
|
Supplemental
non-cash activity:
|
|
|
|
|
|
|
|
|
|
|
(Decrease)
in fair value of derivatives:
|
|
|
|
|
|
|
|
|
|
|
Current
(net of income taxes of $5,358 and $5,468, respectively)
|
|
|
|
|
$
|
(8,037
|
)
|
$
|
(8,203
|
)
|
Non-current
(net of income taxes of $2,889 and $11,261, respectively)
|
|
|
|
|
|
(4,333
|
)
|
|
(16,891
|
)
|
Net
(decrease) to accumulated other comprehensive income
|
|
|
|
|
$
|
(12,370
|
)
|
$
|
(25,094
|
)
|
The
accompanying notes are an integral part of these financial
statements.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
1. General
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, 2007 and December 31, 2006 and results of operations and cash
flows for the three month periods ended March 31, 2007 and 2006 have been
included. All such adjustments are of a normal recurring nature. The results
of
operations and cash flows are not necessarily indicative of the results for
a
full year.
The
accompanying unaudited condensed financial statements have been prepared on
a
basis consistent with the accounting principles and policies reflected in the
December 31, 2006 financial statements. The December 31, 2006 Form 10-K
should be read in conjunction herewith. The year-end condensed balance sheet
was
derived from audited financial statements, but does not include all disclosures
required by accounting principles generally accepted in the United States of
America.
Our
cash
management process provides for the daily funding of checks as they are
presented to the bank. Included in accounts payable at March 31, 2007, December
31, 2006 and March 31, 2006 is $12.5 million, $17.2 million and $11.8 million,
respectively, representing outstanding checks in excess of the bank balance
(book overdraft).
In
December 2004, Statement of Financial Accounting Standards (SFAS)
No. 123(R), Share-Based
Payment,
was
issued which establishes standards for transactions in which an entity exchanges
its equity instruments for goods or services. As a result, we adopted this
statement beginning January 1, 2006. This standard requires us to measure
the cost of employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award. Accordingly, the
adoption of SFAS No. 123(R) using the modified prospective method did not
have a material impact on our condensed financial statements for the year ended
December 31, 2006. We previously adopted the fair value recognition provisions
of SFAS No. 123, Accounting
for Stock-Based Compensation
effective January 1, 2004. The modified prospective method was selected as
described in SFAS No. 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
this method, we recognized stock option compensation expense as if it had
applied the fair value method to account for unvested stock options from its
original effective date.
2. Stock
Split
On
March
1, 2006, our Board of Directors approved a two-for-one stock split to
shareholders of record on May 17, 2006, subject to obtaining shareholder
approval of an increase in our authorized shares. On May 17, 2006 our
shareholders approved the authorized share increase and on June 2, 2006 each
shareholder received one additional share for each share owned on May 17, 2006.
This did not change the proportionate interest a shareholder maintained in
Berry
Petroleum Company on May 17, 2006. All historical shares, equity awards and
per
share amounts have been restated for the two-for-one stock split.
3. Recent
Accounting Developments
In
June
2006, the FASB issued Interpretation (FIN) No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109,
Accounting for Income Taxes.
This
interpretation requires that realization of an uncertain income tax position
must be “more likely than not” (i.e. greater than 50% likelihood of receiving a
benefit) before it can be recognized in the financial statements. Further,
this
interpretation prescribes the benefit to be recorded in the financial statements
as the amount most likely to be realized assuming a review by tax authorities
having all relevant information and applying current conventions. This
interpretation also clarifies the financial statement classification of
tax-related penalties and interest and sets forth new disclosures regarding
unrecognized tax
benefits. This interpretation is effective for fiscal years beginning after
December 15, 2006, and we adopted this interpretation in the first quarter
of 2007. See Note 6.
In
September 2006, SFAS No. 157, Fair
Value Measurements was
issued by the Financial Accounting Standards Board (FASB). This statement
defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. SFAS No. 157 will become
effective for our fiscal year beginning January 1, 2008, and we are currently
assessing the potential impact of this Statement on our financial
statements.
In
September 2006, Staff Accounting Bulletin (“SAB”) No. 108,
Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements.
Registrants must quantify the impact on current period financial statements
of
correcting all misstatements, including both those occurring in the current
period and the effect of reversing those that have accumulated from prior
periods. This SAB was adopted at December 31, 2006. The adoption of
SAB No. 108 had no effect on our financial position or on the results
of our operations.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
3. Recent
Accounting Developments (Cont’d)
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities,
which
permits an entity to measure certain financial assets and financial liabilities
at fair value. The objective of SFAS No. 159 is to improve financial reporting
by allowing entities to mitigate volatility in reported earnings caused by
the
measurement of related assets and liabilities using different attributes,
without having to apply complex hedge accounting provisions. Under SFAS No.
159,
entities that elect the fair value option (by instrument) will report unrealized
gains and losses in earnings at each subsequent reporting date. The fair value
option election is irrevocable, unless a new election date occurs. SFAS No.
159
establishes presentation and disclosure requirements to help financial statement
users understand the effect of the entity’s election on its earnings, but does
not eliminate disclosure requirements of other accounting standards. Assets
and
liabilities that are measured at fair value must be displayed on the face of
the
balance sheet. This statement is effective beginning January 1, 2008 and we
are
evaluating this pronouncement.
4. Hedging
The
related cash flow impact of all of our hedges are reflected in cash flows from
operating activities. At March 31, 2007, our net fair value of derivatives
liability was $54.2 million as compared to $33.2 million at December 31, 2006.
At March 31, 2007, Accumulated Other Comprehensive Loss consisted of $32.3
million, net of tax, of unrealized losses from our crude oil and natural gas
swaps and collars that qualified for hedge accounting treatment at March 31,
2007. Deferred net losses recorded in Accumulated Other Comprehensive Loss
at
March 31, 2007 and subsequent marked-to-market changes in the underlying hedging
contracts are expected to be reclassified to earnings over the life of these
contracts. Our liability is primarily related to the time value of the
underlying instruments and based on current prices the amount expected to be
reclassified to earnings over the next 12 months is not
significant.
As
of
February 28, 2007, we have converted 2,000 Bbl/D of our 2007 oil collars
beginning on March 1, 2007 to a swap with a strike price of $60 West Texas
Intermediate (WTI). This swap is considered to be an effective cash flow hedge.
Additionally, we entered into oil swaps for 1,000 Bbl/D at $64.55 from March
2007 through December 2007 and entered into oil collars for 1,000 Bbl/D at
$60
floor and $75 ceiling prices for 2010.
Additionally,
on June 8, 2006 and July 10, 2006, we entered into five year interest rate
swaps
for a fixed rate of approximately 5.5% on $100 million of our outstanding
borrowings under our credit facility for five years. These interest rate swaps
have been designated as cash flow hedges.
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. In 2007, we reassessed our estimate as costs have increased
due to demand for related services, resulting in an increase in the ARO balance
at quarter end.
Under
SFAS 143, the following table summarizes the change in abandonment obligation
for the quarter ended March 31, 2007 (in thousands):
|
|
|
|
|
|
Beginning
balance at January 1
|
|
$
|
26,135
|
|
|
|
|
Liabilities
incurred
|
|
|
1,274
|
|
|
|
|
Liabilities
settled
|
|
|
(256
|
)
|
|
|
|
Revisions
in estimated liabilities
|
|
|
3,272
|
|
|
|
|
Accretion
expense
|
|
|
533
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending
balance at March 31
|
|
$
|
30,958
|
|
|
|
|
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
6. Income
Taxes
The
effective tax rate was 39% for the first quarter of 2007 compared to 38% for
the
fourth quarter of 2006 and 39% for the first quarter of 2006.
In
June
2006, the FASB issued FIN
No. 48,
Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109,
Accounting for Income Taxes.
The
Interpretation addresses the determination of whether tax benefits claimed
or
expected to be claimed on a tax return should be recorded in the financial
statements. Under FIN No. 48, we may recognize the tax benefit from an uncertain
tax position only if it is more likely than not that the tax position will
be
sustained on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements
from such a position should be measured based on the largest benefit that has
a
greater than fifty percent likelihood of being realized upon ultimate
settlement. FIN No. 48 also provides guidance on derecognition, classification,
interest and penalties on income taxes, accounting in interim periods and
requires increased disclosures.
We
adopted the provisions of FIN No. 48 on January 1, 2007 and recognized no
material adjustment to retained earnings. As of the date of adoption, we had
a
gross liability for uncertain tax benefits of $14.6 million of which $10.8
million if recognized, would affect the effective tax rate. We recognize
potential accrued interest and penalties related to unrecognized tax benefits
in
income tax expense, which is consistent with the recognition of these items
in
prior reporting periods. As of January 1, 2007, we had accrued approximately
$.9
million of interest related to our uncertain tax positions.
We
have
not had any material changes to our unrecognized tax benefits since adoption,
nor do we anticipate significant changes to the total amount of unrecognized
tax
benefits within the next 12 months.
As
of
January 1, 2007, we remain subject to examination in the following major tax
jurisdictions for the tax years indicated below:
Jurisdiction:
|
Tax
Years Subject to Exam:
|
Federal
|
2003
- 2006
|
California
|
2002
- 2006
|
Colorado
|
2002
- 2006
|
Utah
|
2003
- 2006
|
7. Long-term
and Short-term Obligations
Long-term
debt
In
October 2006, we issued in a public offering $200 million of 8.25% senior
subordinated notes due 2016 (the Notes). The deferred costs of approximately
$5
million associated with the issuance of this debt are being amortized over
the
ten year life of the Notes. The net proceeds from the offering were used to
1)
repay approximately $145 million of borrowings under the bank credit facility,
which were $170 million as of the issuance date after the application of
this payment, and 2) approximately $50 million was used to pay the November
1,
2006 installment under the joint venture agreement to develop properties in
the
Piceance basin.
In
April
2006, we completed a new unsecured five year bank credit facility agreement
(the
Agreement) with a banking syndicate and extended the term by one year to July
2011. The Agreement is a revolving credit facility for up to $750 million and
replaces the previous $500 million facility. The current borrowing base was
established at $500 million, as compared to the previous $350 million. This
transaction was accounted for in accordance with Emerging Issues Task Force,
(EITF) 98-14, Debtor’s
Accounting for Changes in Line-of-Credit or Revolving-Debt
Arrangements.
The
total
outstanding debt under the credit facility’s borrowing base was $270 million and
the short-term line of credit was $7 million at March 31, 2007, leaving $223
million in borrowing capacity available. Interest on amounts borrowed under
this
debt is charged at LIBOR plus a margin of 1.00% to 1.75% or the prime rate,
with
margins on the various rate options based on the ratio of credit outstanding
to
the borrowing base. We are required under the Agreement to pay a commitment
fee
of .25% to .375% on the unused portion of the credit facility
annually.
BERRY
PETROLEUM COMPANY
Notes
to the Unaudited Condensed Financial Statements
7. Long-term
and Short-term Obligations (Cont’d)
The
Agreement contains restrictive covenants which, among other things, require
us
to maintain a certain debt to EBITDA ratio and a minimum current ratio, as
defined. The $200 million Notes are subordinated to our credit facility
indebtedness. Our Notes covenants limit debt to the greater of $750 million
or
40% of Adjusted Consolidated Net Tangible Assets (as defined). Additionally,
as
long as the interest coverage ratio (as defined) is met, we may incur additional
debt. We were in compliance with all such covenants as of March 31, 2007. The
weighted average interest rate on the long-term outstanding credit facility
borrowings at March 31, 2007 was 6.6%.
Short-term
debt
In
November 2005, we completed an unsecured uncommitted money market line of credit
(Line of Credit). Borrowings under the Line of Credit may be up to $30 million
for a maximum of 30 days. The Line of Credit may be terminated at any time
upon
written notice by either us or the lender. At March 31, 2007 the outstanding
balance under this Line of Credit was $7 million. Interest on amounts borrowed
is charged at LIBOR plus a margin of approximately 1%. The weighted average
interest rate on outstanding borrowings on the Line of Credit at March 31,
2007
was 6.2%.
8.
Contingencies
and Commitments
We
have
no accrued environmental liabilities for our sites, including sites in which
governmental agencies have designated us as a potentially responsible party,
because it is not probable that a loss will be incurred and the minimum cost
and/or amount of loss cannot be reasonably estimated. However, because of the
uncertainties associated with environmental assessment and remediation
activities, future expense to remediate the currently identified sites, and
sites identified in the future, if any, could be accrued. Management believes,
based upon current site assessments, that the ultimate resolution of any matters
will not require substantial accruals. We are involved in various other
lawsuits, claims and inquiries, most of which are routine to the nature of
our
business. In the opinion of management, the resolution of these matters will
not
have a material effect on our financial position, or on the results of
operations or liquidity.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly Corporation (Holly) for a portion of our
Uinta basin crude oil. Under the agreement, Holly will begin purchasing 3,200
Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross refinery
expansion in Salt Lake City, which is expected in late 2008, Holly will increase
total purchased volumes to 5,000 Bbl/D through June 30, 2013. During
the term of the contract, the minimum number of delivered units (“base daily
volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion
of the refinery upgrade. Holly may, but is not obligated to, purchase volumes
in
excess of the base daily volumes when notified by us at the beginning of any
contract year.
9. Assets
Held for Sale
Net
oil
and gas properties and equipment classified as held for sale is $8.9 million
at
March 31, 2007 in accordance with SFAS No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets.
On
March 19, 2007 we announced that we have entered into an agreement to sell
our
non-core West Montalvo assets, near Ventura, California. We estimate a sales
price of approximately $63 million before adjustments and expect to transfer
the
properties in the second quarter of 2007. The completion of the transaction
is
subject to certain conditions and there is no assurance that all such conditions
will be satisfied.
10. Subsequent
Event
We
paid
the third and final installment of approximately $54 million utilizing our
credit facility on May 1, 2007 for the North Parachute Ranch property located
in
the Piceance basin.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
General.
The
following discussion provides information on the results of operations for
the
three month periods ended March 31, 2007 and 2006 and our financial condition,
liquidity and capital resources as of March 31, 2007. The financial statements
and the notes thereto contain detailed information that should be referred
to in
conjunction with this discussion.
The
profitability of our operations in any particular accounting period will be
directly related to the realized prices of oil, gas and electricity sold, the
type and volume of oil and gas produced and electricity generated and the
results of development, exploitation, acquisition, exploration and hedging
activities. The realized prices for natural gas and electricity will fluctuate
from one period to another due to regional market conditions and other factors,
while oil prices will be predominantly influenced by world supply and demand.
The aggregate amount of oil and gas produced may fluctuate based on the success
of development and exploitation of oil and gas reserves pursuant to current
reservoir management. The cost of natural gas used in our steaming operations
and electrical generation, production rates, labor, equipment costs, maintenance
expenses, and production taxes are expected to be the principal influences
on
operating costs. Accordingly, our results of operations may fluctuate from
period to period based on the foregoing principal factors, among
others.
Overview.
Our
mission is to increase shareholder value through consistent growth in our
production and reserves, both through the drill bit and acquisitions. We strive
to operate our properties in an efficient manner to maximize the cash flow
and
earnings of our assets. The strategies to accomplish these goals
include:
· |
Developing
our existing resource base
|
· |
Acquiring
additional assets with significant growth
potential
|
· |
Utilizing
joint ventures with respected partners to enter new
basins
|
· |
Accumulating
significant acreage positions near our producing
operations
|
· |
Investing
our capital in a disciplined manner and maintaining a strong financial
position
|
Notable
First Quarter Items.
· |
Production
averaged 25,490 BOE/D, up 9% from the first quarter of
2006
|
· |
Entered
into a long-term crude oil sales contract for our Uinta basin, Utah
production
|
· |
Restored
Uinta basin production to approximately 6,000 BOE/D from a low of
3,800
BOE/D in January 2007
|
· |
Production
at Midway-Sunset diatomite averaged 600 Bbl/D compared to 400 Bbl/D
in the
fourth quarter of 2006
|
· |
Improvements
made in the Piceance basin program in personnel, services, rigs,
drilling
and completions
|
· |
Entered
into an agreement to sell our non-core West Montalvo assets, near
Ventura,
California for an estimated sales price of approximately $63 million
cash
before adjustments
|
Notable
Items and Expectations for the Second Quarter of
2007.
· |
Completing
over 20 Piceance basin wells with total Piceance net production estimated
at 9.6 MMcf/D
|
· |
Production
at Midway-Sunset diatomite is approaching 1,000 BOE/D and the steam
to oil
ratio is improving
|
· |
Accelerating
Poso Creek development by drilling 40 wells and installing an additional
steam generator
|
· |
Transferring
Montalvo properties with proceeds estimated at $63 million before
adjustments
|
· |
Production
is projected to average between 26,500 BOE/D and 27,500 BOE/D for
the
second quarter of 2007
|
Overview
of the First Quarter of 2007.
In the first quarter we were unable to sell all of our Uinta basin
production due to a refinery shutdown. On February 27, 2007, we entered
into a six year multi-staged crude oil sales contract with a subsidiary of
Holly
for a portion of our Uinta basin crude oil. This
contract will allow us to stabilize our basis differentials on these barrels
beginning on July 1, 2007 and assures us of the ability to sell this regional
crude oil. Our
activities in the Piceance basin included completion of a pipeline. Eleven
wells
have been connected since the pipeline was completed, allowing production to
rise to over 8.5 net MMcf/D in April from 6.4 net MMcf/D in the first quarter
of
2007.
View
to the Second Quarter.
Our 2007
drilling program will continue to drive our production growth. Operationally,
we
are focused on executing our drilling program on our Piceance basin asset where
we expect to drill 16 wells during the second quarter of 2007. Furthermore,
based on higher than expected performance at Poso Creek, we
are
planning to accelerate development there by drilling 40 wells and installing
a
third steam generator during the second quarter. On
May 1,
2007, the final installment for our Piceance
basin joint venture
was
paid.
Results
of Operations. The
following companywide results are in millions (except per share data) for the
three months ended:
|
|
March
31, 2007
(1Q07)
|
|
March
31, 2006
(1Q06)
|
1Q07
to 1Q06 Change
|
December
31, 2006
(4Q06)
|
1Q07
to 4Q06 Change
|
Sales
of oil
|
|
$
|
80.9
|
|
$
|
83.3
|
(3%)
|
$
|
84.2
|
(4%)
|
Sales
of gas
|
|
|
20.9
|
|
|
18.6
|
12%
|
|
17.6
|
19%
|
Total
sales of oil and gas
|
|
$
|
101.8
|
|
$
|
101.9
|
-%
|
$
|
101.8
|
-%
|
Sales
of electricity
|
|
|
14.6
|
|
|
15.2
|
(4%)
|
|
13.4
|
9%
|
Interest
and other income, net
|
|
|
1.1
|
|
|
.5
|
120%
|
|
1.0
|
10%
|
Total
revenues and other income
|
|
$
|
117.5
|
|
$
|
117.6
|
-%
|
$
|
116.2
|
1%
|
Net
income
|
|
$
|
18.9
|
|
$
|
23.3
|
(19%)
|
$
|
19.1
|
(1%)
|
Net
income per share (diluted)
|
|
$
|
.42
|
|
$
|
.52
|
(19%)
|
$
|
.43
|
(2%)
|
Our
revenues may vary significantly from period to period as a result of changes
in
commodity prices and/or production volumes. For the three months ended March
31,
2007, gas sales improved while oil sales declined when compared to three months
ended March 31, 2006. Improvement to gas sales is due to higher production
primarily from our Piceance basin acquisition, partially offset by lower gas
prices. Oil sales decreased due to lower prices partially offset by higher
volumes primarily from our NMWSS and Poso Creek properties.
Similarly,
for the three months ended March 31, 2007 compared to the three months ended
December 31, 2006, gas sales improved while oil sales declined. Improvement
in realized gas prices during the first three months of 2007 were due
to increased weather related demand and a tighter supply and demand
balance, while oil sales declined primarily due
to
lower production.
Operating
data.
The
following table is for the three months ended:
|
|
|
March
31, 2007
|
%
|
|
March
31, 2006
|
%
|
|
December
31, 2006
|
%
|
Oil
and Gas
|
|
|
|
|
|
|
|
|
|
|
Heavy
Oil Production (Bbl/D)
|
|
|
16,140
|
63
|
|
15,407
|
66
|
|
16,833
|
63
|
Light
Oil Production (Bbl/D)
|
|
|
3,233
|
13
|
|
3,303
|
14
|
|
3,363
|
13
|
Total
Oil Production (Bbl/D)
|
|
|
19,373
|
76
|
|
18,710
|
80
|
|
20,196
|
76
|
Natural
Gas Production (Mcf/D)
|
|
|
36,704
|
24
|
|
28,507
|
20
|
|
40,157
|
24
|
Total
(BOE/D)
|
|
|
25,490
|
100
|
|
23,461
|
100
|
|
26,889
|
100
|
|
|
|
|
|
|
|
|
|
|
|
Per
BOE:
|
|
|
|
|
|
|
|
|
|
|
Average
sales price before hedging
|
|
$
|
43.62
|
|
$
|
50.04
|
|
$
|
41.53
|
|
Average
sales price after hedging
|
|
|
43.84
|
|
|
48.45
|
|
|
42.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil,
per Bbl:
|
|
|
|
|
|
|
|
|
|
|
Average
WTI price
|
|
$
|
58.23
|
|
$
|
63.48
|
|
$
|
60.17
|
|
Price
sensitive royalties
|
|
|
(3.74
|
)
|
|
(5.41
|
)
|
|
(4.28
|
)
|
Quality
differential and other
|
|
|
(8.78
|
)
|
|
(6.36
|
)
|
|
(9.06
|
)
|
Crude
oil hedges
|
|
|
.03
|
|
|
(2.04
|
)
|
|
(.01
|
)
|
Average
oil sales price after hedging
|
|
$
|
45.74
|
|
$
|
49.67
|
|
$
|
46.82
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas,
per MMBtu:
|
|
|
|
|
|
|
|
|
|
|
Average
Henry Hub price
|
|
$
|
7.18
|
|
$
|
7.92
|
|
$
|
7.24
|
|
Natural
gas hedges
|
|
|
.13
|
|
|
(.03
|
)
|
|
.33
|
|
Location,
quality differentials and other
|
|
|
(.70
|
)
|
|
(1.05
|
)
|
|
(2.68
|
)
|
Average
gas sales price after hedging
|
|
$
|
6.61
|
|
$
|
6.84
|
|
$
|
4.89
|
|
|
Gas
Basis Differential. The
gas prices in the Rockies continue to be volatile due to various
factors,
including takeaway pipeline capacity, supply volumes, and regional
demand
issues. We expect the basis differential to narrow upon the startup
of the
Rockies Express pipeline which is anticipated in 2008. We have contracted
10,000 Mcf/D on this pipeline to provide assurance of gas delivery.
The
Colorado
Interstate Gas (CIG)
basis differential averaged $1.18 below Henry Hub (HH) and ranged
from
$.51 to $1.67 below HH in the first quarter. Although related to
CIG, the
actual basin price varies. Gas from the DJ basin was sold slightly
above
the CIG price, Piceance basin gas was slightly below the CIG price
while
Uinta basin gas sold for approximately $.40 below CIG
pricing.
|
Oil
Contracts. Utah
- As
of March 31, 2007, our Utah light crude oil is sold under multiple contracts
with different purchasers for varying pricing terms and ranging from one month
to six months. In April 2007, contracts were in place to sell approximately
5,000 BOE/D during the month. These contracts have marginally improved since
December 31, 2006 and are currently priced at approximately $12 to $17 per
barrel below WTI with certain volumes tied to field posting, and in some cases
our realized price is further reduced by transportation charges. As operator
we
deliver all produced volumes pursuant to these contracts, although our working
interest partners or royalty owners have the right to take their respective
volumes in kind and market their own volumes. Our net volumes from our Brundage
Canyon properties approximate 80% of the total gross volumes. Assuming all
the
Brundage Canyon wells are producing, the gross production could exceed these
contracted volumes. Our Utah crude oil is a paraffinic crude and can be
processed efficiently by only a limited number of refineries.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly for a portion of our Uinta basin crude
oil.
Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July
1,
2007. Holly has begun to take delivery of approximately 1,000 Bbl/D in the
first
quarter of 2007, which stabilizes our realized sales price and reduces our
transportation costs. Upon completion of their Woods Cross refinery expansion
in
Salt Lake City, which is expected in late 2008, Holly will increase total
purchased volumes to 5,000 Bbl/D through June 30, 2013. Pricing under the
contract, which includes transportation, is a fixed percentage of WTI and
approximates our expected field posted price of $13 to $16 below WTI. This
contract provides the pricing assurance we need to proceed with the long-term
development of our Uinta basin assets. From October 1, 2003 through
April 30, 2006 we were able to sell our Utah crude oil at approximately
$2.00 per barrel below WTI and from May 1, 2006 through September 30,
2006, we were selling the majority of our Utah crude at approximately $9.00
per
barrel below WTI. We may adjust our capital expenditures in the Uinta basin
due
to various factors, including the timing of refinery demand for the Uinta basin
barrels and the actual or expected change in our realized price.
Hedging.
See
Note
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 economic production of heavy oil. Revenue and operating costs
for the three months ended March 31, 2007 were down from the three months ended
March 31, 2006 due to 6% lower electricity prices and 12% lower fuel gas cost,
respectively. Conversely, revenue and operating costs in the three months ended
March 31, 2007 were up from the three months ended December 31, 2006 due to
8%
higher electricity prices and 4% higher natural gas prices, respectively. The
following table is for the three months ended:
|
|
|
March
31, 2007
|
|
|
March
31, 2006
|
|
|
December
31, 2006
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
Revenues
(in millions)
|
|
$
|
14.6
|
|
$
|
15.2
|
|
$
|
13.4
|
|
Operating
costs (in millions)
|
|
$
|
14.2
|
|
$
|
14.3
|
|
$
|
12.1
|
|
Electric
power produced - MWh/D
|
|
|
2,117
|
|
|
2,080
|
|
|
2,093
|
|
Electric
power sold - MWh/D
|
|
|
1,914
|
|
|
1,884
|
|
|
1,861
|
|
Average
sales price/MWh
|
|
$
|
81.08
|
|
$
|
85.93
|
|
$
|
75.05
|
|
Fuel
gas cost/MMBtu (including transportation)
|
|
$
|
6.70
|
|
$
|
7.65
|
|
$
|
6.44
|
|
Oil
and Gas Operating, Production Taxes, G&A and Interest Expenses.
The
following table presents information about our operating expenses for each
of
the three month periods ended:
|
|
Amount
per BOE
|
|
Amount
(in thousands)
|
|
|
|
March
31, 2007
|
|
March
31, 2006
|
|
December
31, 2006
|
|
March
31, 2007
|
|
March
31, 2006
|
|
December
31, 2006
|
|
Operating
costs - oil and gas production
|
|
$
|
14.65
|
|
$
|
12.19
|
|
$
|
13.69
|
|
$
|
33,610
|
|
$
|
25,738
|
|
$
|
33,804
|
|
Production
taxes
|
|
|
1.66
|
|
|
1.53
|
|
|
1.15
|
|
|
3,815
|
|
|
3,233
|
|
|
2,840
|
|
DD&A
- oil and gas production
|
|
|
8.16
|
|
|
6.26
|
|
|
8.24
|
|
|
18,725
|
|
|
13,223
|
|
|
20,335
|
|
G&A
|
|
|
4.49
|
|
|
3.94
|
|
|
4.55
|
|
|
10,307
|
|
|
8,314
|
|
|
11,231
|
|
Interest
expense
|
|
|
1.69
|
|
|
.75
|
|
|
1.27
|
|
|
4,292
|
|
|
1,577
|
|
|
3,503
|
|
Total
|
|
$
|
30.65
|
|
$
|
24.67
|
|
$
|
28.90
|
|
$
|
70,749
|
|
$
|
52,085
|
|
$
|
71,713
|
|
Our
total
operating costs, production taxes, G&A and interest expenses for the three
months ended March 31, 2007, stated on a unit-of-production basis, increased
24%
over the three months ended March 31, 2006 and increased 6% over the three
months ended December 31, 2006. The changes were primarily related to the
following items:
|
·
|
Operating
costs: Operating costs per BOE in the first quarter of 2007 were
20%
higher than the first quarter of 2006 primarily due to an increase
in
steam costs, company and contract labor as well as transportation,
compression and gathering costs. Similarly, operating costs per BOE
were
7% higher in the first quarter of 2007 as compared to the fourth
quarter
of 2006, as production volumes were down. Cost pressures do remain,
but we
are working to offset them with improved efficiencies. The cost of
our
steaming operations on our heavy oil properties in California varies
depending on the cost of natural gas used as fuel and the volume
of steam
injected. The following table presents steam information:
|
|
March
31, 2007
|
March
31, 2006
|
1Q07
to 1Q06 Change
|
December
31, 2006
|
1Q07
to 4Q06 Change
|
Average
volume of steam injected (Bbl/D)
|
86,132
|
75,138
|
15%
|
85,349
|
1%
|
Fuel
gas cost/MMBtu (including transportation)
|
$
6.70
|
$
7.65
|
(12%)
|
$
6.44
|
4%
|
As
we
remain in a strong commodity price environment, we anticipate that cost
pressures within our industry may continue due to greater field activity and
rising service costs in general. Based on current plans, we are targeting
average steam injection in 2007 of approximately 90,000 to 95,000 barrels of
steam per day (BSPD). Natural gas prices impact our cost structure in California
by approximately $1.60 per California BOE for each $1.00 change in natural
gas
price.
· |
Production
taxes: Our production taxes have increased over 2006 as the value
of our
oil and natural gas assets has increased. Severance taxes, which
are
prevalent in Utah and Colorado, are directly related to the cost
of the
field sales price of the commodity. In California, our production
is
burdened with ad valorem taxes on our total proved reserves. We expect
production taxes, in general, to track the commodity price.
|
· |
Depreciation,
depletion and amortization: DD&A increased per BOE in the three months
ended March 31, 2007 compared to the same period in the prior year
due to
an increase in capital spending over the last year and particularly
more
extensive development in fields with higher drilling costs and leasehold
acquisition costs. Our capital program is also experiencing cost
pressures
in our labor and for goods and services commensurate with other energy
developers. As these costs increase, our DD&A rates per BOE will also
increase.
|
· |
General
and administrative: Approximately 70% of our G&A is compensation or
compensation related costs. To remain competitive in workforce
compensation and achieve our growth goals, our general and administrative
cost increased significantly due to additional staffing, higher
compensation levels, bonuses, stock compensation and benefit costs.
We
also incurred higher employee travel and other G&A costs associated
with our growth activities.
|
· |
Interest
expense: Our outstanding borrowings, including our senior unsecured
money
market line of credit and senior subordinated notes, was $477 million
at March 31, 2007 compared to $406 million at December 31, 2006. Our
average borrowings increased during the three months ended March
31, 2007
as a result of our capital expenditure program and due to the annual
payment of a price-based royalty for $38 million. Beginning in 2006,
a
certain portion of our interest cost related to our Piceance basin
acquisition and joint venture has been capitalized into the basis
of the
assets, and we anticipate a portion will continue to be capitalized
until
the remainder of our probable reserves have been recategorized to
proved
developed reserves. For the quarter ended March 31, 2007, $4 million
has
been capitalized and we expect to capitalize approximately $20 million
of
interest cost during the full year of
2007.
|
Estimated
2007 Oil and Gas Operating, G&A and Interest
Expenses.
|
|
Anticipated
range
|
|
|
|
|
|
|
|
in
2007 per BOE
|
|
|
|
|
|
Operating
costs-oil and gas production (1)
|
|
$
|
14.50
to 15.50
|
|
|
|
|
|
|
|
Production
taxes
|
|
|
1.50
to 2.00
|
|
|
|
|
|
|
|
DD&A
|
|
|
7.75
to 8.75
|
|
|
|
|
|
|
|
G&A
|
|
|
3.50
to 4.00
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
1.00
to 2.00
|
|
|
|
|
|
|
|
Total
|
|
$
|
28.25
to 32.25
|
|
|
|
|
|
|
|
(1)
Assuming natural gas prices of approximately NYMEX HH $7.50 MMBtu, we plan
to
inject approximately 15% greater steam levels in 2007 compared to 2006
levels.
Income
Taxes.
See Note
6 to the unaudited condensed financial statements. Our effective tax rate will
be similar in 2007 as compared to 2006. We experienced an effective tax rate
in
the three months ended March 31, 2007 of 39%, which is in line with our
projections.
Development,
Exploitation and Exploration Activity.
We
drilled 124 gross (88 net) wells during the first quarter of 2007, realizing
a
gross success rate of 99 percent. Excluding any future acquisitions, our
targeted 2007 developmental capital budget is between $227 million and $267
million. As of March 31, 2007, we have five rigs drilling on our properties
under long-term contracts and have one more rig scheduled to begin in mid-2007.
Drilling
Activity. The
following table sets forth certain information regarding drilling activities
for
the three months ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
Gross
Wells
|
|
|
Net
Wells
|
|
|
|
|
SMWSS
|
|
|
|
20
|
|
|
20
|
|
|
|
|
NMWSS
|
|
|
|
11
|
|
|
11
|
|
|
|
|
Socal
|
|
|
|
18
|
|
|
18
|
|
|
|
|
Piceance
|
|
|
|
18
|
|
|
5
|
|
|
|
|
Uinta
|
|
|
|
15
|
|
|
13
|
|
|
|
|
DJ
(1)
|
|
|
|
42
|
|
|
21
|
|
|
|
|
Totals
|
|
|
|
124
|
|
|
88
|
|
|
|
|
|
(1)
|
Includes
1 gross well (.5 net well) that was a dry hole in Yuma County,
Colorado.
|
Production
California’s
three asset teams are South Midway-Sunset (SMWSS, which has been realigned
to
include Ethel D), North Midway-Sunset (NMWSS) (which includes diatomite) and
Southern California (Socal) (which includes Poso Creek, Placerita and Montalvo).
The Rocky Mountain/Mid-Continent region’s three asset teams are Piceance, Uinta
and DJ basins.
SMWSS,
San Joaquin Valley Basin (SJVB)
- During
the three months ended March 31, 2007, production averaged approximately 9,900
Bbl/D compared to approximately 10,800 Bbl/D and 10,700 Bbl/D during the three
month periods ended March 31, 2006 and December 31, 2006, respectively. During
the three months ended March 31, 2007, we completed four horizontal infill
wells
and improved subsurface steam monitoring to determine best heat placement into
the remaining oil column to maximize recovery and value. Additionally, a number
of horizontal wells were pulled off production for cyclic steaming. Cyclic
steaming of these horizontal wells is necessary to place steam effectively
into
the remaining oil column. In the second quarter of 2007, we plan to drill
approximately 14 infill horizontal wells. Increased production from these
activities is expected to slow the natural decline. We expect to manage our
decline rate to approximately 6% to 7% for 2007.
We
have
completed our 2007 drilling program on our Ethel D property and production
has
increased by over 200 Bbl/D. We may expand our program depending on reservoir
performance.
NMWSS,
SJVB
- Our
Midway-Sunset diatomite oil project is performing above expectations due to
a
more aggressive approach in our use of steam. During the three months ended
March 31, 2007, production from the diatomite project averaged approximately
600
Bbl/D up from approximately 200 Bbl/D and 400 Bbl/D during the three month
periods ended March 31, 2006 and December 31, 2006, respectively. Our 2007
capital is focused on drilling the diatomite first phase development wells
and
adding steam generation equipment and various facilities. Diatomite wells will
not begin to be drilled until the third quarter of 2007.
Socal,
SJVB and Los Angeles Basin
- Poso
Creek is performing solidly above plan due to strong steam flood performance
and
our infill drilling. During the three months ended March 31, 2007, production
averaged approximately 1,500 Bbl/D up from approximately 600 Bbl/D and 1,400
Bbl/D during the three month periods ended March 31, 2006 and December 31,
2006,
respectively. We are planning to accelerate development drilling with over
70
infill producing wells this year, expanding the steam drive by 14 patterns
and
installing a third steam generator in the second quarter of 2007.
Piceance
Basin, Colorado -
We
currently have four drilling rigs operating in the basin and expect to maintain
this level for the remainder of the year. Newly constructed pipelines to the
mesa plateaus were completed late in the first quarter and since completion,
three North Parachute Ranch wells and eight Garden Gulch wells have been put
into production. Twelve additional wells are forecasted to be drilled and
connected by the end of the second quarter of 2007. Average
daily production in the Piceance basin for the first quarter was 6.4 net MMcf/D.
The recent well connects have increased April monthly production to over 8.5
net
MMcf/D. Significant progress has been made to lower the days required to drill
wells. Construction
has begun on the Garden Gulch road extension, which, coupled with the mountain
road, will greatly improve access to our operations on the Garden Gulch acreage.
Uinta
Basin, Utah -
Our
2007
capital is directed at additional Brundage Canyon 40-acre development wells,
drilling the Ashley Forest extension to the south of Brundage Canyon, continued
Lake Canyon assessment and drilling 20-acre infill wells in Brundage Canyon.
During the first quarter, we drilled 13 net wells in Brundage Canyon. Well
performance results continue to be positive and preliminary results from four
20-acre pilot wells indicate the possibility of new production
opportunities.
Average
daily production during the first quarter from all Uinta basin assets was 4,800
net BOE/D. In the fourth quarter of 2006, oil sales were interrupted due to
refinery and trucking limitations. The
refinery resumed operations in mid-January 2007. Improved
market conditions late in the first quarter resulted in a daily production
exit
rate of 6,100 net BOE/D for the quarter. We continue to have one drilling rig
operating in the basin. In February 2007, we signed a six year oil contract
with
Holly for 3,200 BOE/D starting in July 2007 with up to 5,000 BOE/D through
June
30, 2013 upon the certified completion of their refinery upgrade. This contract
along with our other oil marketing arrangements provides us the ability to
sell
all of our crude oil production in the Uinta basin.
Post
winter season access to our Ashley Forest acreage and Lake Canyon area will
open
up in May of 2007, with our second and third quarter drilling focusing in these
areas. Six drilling permits have been received for Ashley Forest and four
permits received for Lake Canyon wells with an additional 16 permits anticipated
in the second quarter to support the mid-May to December drilling
window.
In
December 2004, we entered into a development agreement with an industry partner
to develop their Coyote Flats prospect. In the first and early second quarter
of
2006, we established gas sales from three Ferron wells. The combined net
production from the three wells is approximately 1.0 MMcf/D. We will
continue the production tests to further assess the Ferron’s potential at Coyote
Flats. As the result of establishing production in the three wells, we were
assigned a 50% interest in approximately 43,700 gross acres from our industry
partner.
DJ
Basin -
Our
first quarter activity in the DJ basin has focused on Niobrara development
drilling in Yuma County, Colorado. Production early in the quarter was hampered
by severe snow on Colorado’s eastern plains. Average daily production in the DJ
for the first quarter was 17.4 net MMcf/D and by the end of the quarter,
production has recovered to approximately 18 MMcf/D.
We
drilled 41 Niobrara wells during the first quarter of 2007. In addition, 28.5
square miles of 3-D seismic data was acquired in the quarter. This 3-D data
and
the existing drilling location inventory supports the 2007 drilling program
of
168 wells.
Company
Owned Drilling Rigs.
During
2005 and 2006, we purchased three drilling rigs, two of which are drilling
for
us. Owning these rigs allows us to successfully meet a portion of our drilling
needs in the Uinta and Piceance basins.
Financial
Condition, Liquidity and Capital Resources. Substantial
capital is required to replace and grow reserves. We achieve reserve replacement
and growth primarily through successful development and exploration drilling
and
the acquisition of properties. Fluctuations in commodity prices have been the
primary reason for short-term changes in our cash flow from operating
activities. The net long-term growth in our cash flow from operating activities
is the result of growth in production as affected by period to period
fluctuations in commodity prices. In the second quarter of 2006, we revised
our
senior unsecured revolving credit facility to increase
our
maximum credit amount under the facility to $750 million and increased our
current borrowing base to $500 million. On October 24, 2006, we completed
the sale of $200 million of ten year 8.25% senior subordinated notes and paid
down our borrowings under our facility by $141 million. As of March 31, 2007,
we
had total borrowings under the senior unsecured revolving credit facility and
senior unsecured money market line of credit of $277 million and $200
million under our senior subordinated ten year notes.
Capital
Expenditures. We
establish a capital budget for each calendar year based on our development
opportunities and the expected cash flow from operations for that year.
Acquisitions are typically debt financed. We may revise our capital budget
during the year as a result of acquisitions, drilling outcomes and/or changes
in
commodity prices that influence our decision to change capital expenditures
to
closely match operating cash flows. Excess cash generated from operations is
expected to be applied toward capital expenditures, debt reduction or other
corporate purposes.
Management
is closely monitoring the capital
development program in relation to estimated cash flows and expects to
commit capital in the $227 million to $267 million range, excluding
acquisitions. The capital development program may be revised due to lower
commodity price expectations, timing of crude deliveries out of the Uinta basin,
equipment availability, permitting or other factors. We
have
reevaluated the development plan in the Piceance basin to maximize capital
efficiency by minimizing rig moves. Consequently, we estimate that companywide
proved reserves will approximate 170 to 180 million BOE at year end 2007,
including the effect of the expected sale of the Montalvo assets which
consist of 7 million BOE of reserves. During the three months ended March 31,
2007, capital expenditures totaled $75.5 million of which $28 million related
to
the 2007 capital budget and $47.5 million related to the 2006 capital
budget.
Our
2007
expenditures will be directed toward developing reserves, increasing oil and
gas
production and exploration opportunities. For 2007, we plan to invest up to
approximately $176 million, or 66%, in our Rocky Mountain/Mid-Continent region
assets, and up to $91 million, or 34%, in our California assets.
On
March
19, 2007 we announced that we have entered into an agreement to sell our
non-core West Montalvo assets, near Ventura, California. We estimate a sales
price of approximately $63 million before adjustments and expect to transfer
the
assets in the second quarter of 2007. Production from the property is
approximately 700 BOE/D, which is less than 3% of current production and, as
of
December 31, 2006, the property had 7 million BOE of proved reserves which
is
less than 5% of the 2006 year end total of 150 million BOE. The completion
of
the transaction is subject to certain conditions and there is no assurance
that
all such conditions will be satisfied.
Dividends.
Our
annual dividend is currently $.30 per share, payable quarterly in March, June,
September and December.
Working
Capital and Cash Flows. Cash
flow
from operations is dependent upon the price of crude oil and natural gas and
our
ability to increase production and manage costs. Combined crude oil and natural
gas prices increased in the first three months of 2007 (see graphs on page
11)
and production decreased since December 2006 by 5%.
Our
working capital balance fluctuates as a result of the amount of borrowings
and
the timing of repayments under our credit arrangements. We used our long-term
borrowings under our senior unsecured revolving credit facility primarily to
fund property acquisitions. Generally, we use excess cash to pay down borrowings
under our credit arrangement. As a result, we often have a working capital
deficit or a relatively small amount of positive working capital.
The
table
below compares financial condition, liquidity and capital resources changes
for
the three month periods ended (in millions, except for production and average
prices):
|
March
31, 2007
(1Q07)
|
March
31, 2006
(1Q06)
|
1Q07
to 1Q06 Change
|
December
31, 2006
(4Q06)
|
1Q07
to 4Q06 Change
|
Average
production (BOE/D)
|
25,490
|
23,461
|
9%
|
26,889
|
(5%)
|
Average
oil and gas sales prices, per BOE after hedging
|
$
43.84
|
$
48.45
|
(10%)
|
$
42.00
|
4%
|
Net
cash provided by operating activities
|
$
12
|
$
25
|
(52%)
|
$
58
|
(79%)
|
Working
capital, excluding line of credit
|
$
(65)
|
$
(50)
|
(30%)
|
$
(101)
|
36%
|
Sales
of oil and gas
|
$
102
|
$
102
|
-%
|
$
102
|
-%
|
Long-term
debt, including line of credit
|
$
477
|
$
259
|
84%
|
$
406
|
17%
|
Capital
expenditures, including acquisitions and deposits on acquisitions
|
$
76
|
$
206
|
(63%)
|
$
127
|
(40%)
|
Dividends
paid
|
$
3.3
|
$
2.9
|
14%
|
$
3.3
|
-%
|
Contractual
Obligations. Our
contractual obligations as of March 31, 2007 are as follows (in
millions):
|
|
|
Total
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
Long-term
debt and interest
|
|
$
|
715.1
|
$
|
34.3
|
$
|
34.3
|
$
|
34.3
|
$
|
34.3
|
$
|
295.4
|
$
|
282.5
|
Abandonment
obligations
|
|
|
30.9
|
|
.7
|
|
.9
|
|
1.0
|
|
1.0
|
|
1.0
|
|
26.3
|
Property
acquisition payable
|
|
|
54.4
|
|
54.4
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Operating
lease obligations
|
|
|
13.9
|
|
1.4
|
|
1.7
|
|
1.4
|
|
1.4
|
|
1.4
|
|
6.6
|
Drilling
and rig obligations
|
|
|
89.8
|
|
19.6
|
|
25.3
|
|
42.7
|
|
2.2
|
|
-
|
|
-
|
Firm
natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
transportation
contracts
|
|
|
72.7
|
|
3.6
|
|
7.6
|
|
8.5
|
|
8.7
|
|
8.7
|
|
35.6
|
Total
|
|
$
|
976.8
|
$
|
114.0
|
$
|
69.8
|
$
|
87.9
|
$
|
47.6
|
$
|
306.5
|
$
|
351.0
|
Long-term
debt and interest
- Our
credit facility borrowings and related interest of approximately 6.6% can be
paid before its maturity date without significant penalty on borrowings under
our credit facility. Our 8.25% senior subordinated notes mature in November
2016, but are not redeemable until November 1, 2011 and are not redeemable
without any premium until November 1, 2014.
Operating
leases
-
We
lease
corporate
and field offices in California, Colorado and Texas. We lease an airplane for
business travel under a ten year operating lease beginning December
2006.
Drilling
obligation
-
We
intend
to participate in the drilling of over 16 gross wells on our Lake Canyon
prospect over the four year contract, beginning in 2006. Our minimum expenditure
obligation under our exploration and development agreement is $9.6 million.
Also
included above, under our June 2006 joint venture agreement in the Piceance
basin, we must have 120 wells drilled by 2010 to avoid penalties of $.2 million
per well or a maximum of $24 million.
Drilling
rig obligation
- We are
obligated in operating lease agreements for the use of multiple drilling rigs.
Firm
natural gas transportation
-
We
have
one firm transportation contract which provides us additional flexibility in
securing our natural gas supply for California operations. This allows us to
potentially benefit from lower natural gas prices in the Rocky Mountains
compared to natural gas prices in California. We also have several long-term
transportation contracts which provide us with physical access to interstate
pipelines to move gas from our producing areas to markets.
On
February 27, 2007, we entered into a six year multi-staged crude oil sales
contract with a subsidiary of Holly for a portion of our Uinta basin crude
oil.
Under the agreement, Holly will begin purchasing 3,200 Bbl/D beginning July
1,
2007. Upon completion of their Woods Cross refinery expansion in Salt Lake
City,
which is expected in late 2008, Holly will increase their total purchased
volumes to 5,000
Bbl/D through June 30, 2013.
During
the term of the contract, the minimum number of delivered units (“base daily
volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion
of the refinery upgrade. Holly may, but is not obligated to, purchase volumes
in
excess of the base daily volumes when notified by us at the beginning of any
contract year.
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, from time to time we enter into crude
oil and natural gas hedge contracts. The terms of contracts depend on various
factors, including management's view of future crude oil and natural gas prices,
acquisition economics on purchased assets and our future financial commitments.
This price hedging program is designed to moderate the effects of a severe
crude
oil and natural gas price downturn while allowing us to participate in any
commodity price increases. In California, we benefit from lower natural gas
pricing as we are a consumer of natural gas in our operations and elsewhere,
we
benefit from higher natural gas pricing. We have hedged, and may hedge in the
future both natural gas purchases and sales as determined appropriate by
management. Management regularly monitors the crude oil and natural gas markets
and our financial commitments to determine if, when, and at what level some
form
of crude oil and/or natural gas hedging and/or basis adjustments or other price
protection is appropriate in accordance with policy established by our board
of
directors.
Currently,
our hedges are in the form of swaps and collars. However, we may use a variety
of hedge instruments in the future to hedge WTI or the index gas price. We
have
crude oil sales contracts in place which are priced based on a correlation
to
WTI. Natural gas (for cogeneration and conventional steaming operations) is
purchased at the SoCal border price and we sell our produced gas in Colorado
and
Utah at CIG and Questar index prices, respectively.
The
following table summarizes our hedge position as of March 31, 2007:
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
Barrels
|
|
Floor/Ceiling
|
|
|
|
MMBtu
|
|
Floor/Ceiling
|
Term
|
|
Per
Day
|
|
Prices
|
|
Term
|
|
Per
Day
|
|
Prices
|
Crude
Oil Sales
(NYMEX
WTI)
|
|
|
|
|
|
Natural
Gas Sales
(NYMEX
HH)
|
|
|
|
|
Collars
|
|
|
|
|
|
Collars
|
|
|
|
|
Full
year 2007
|
|
8,000
|
|
$47.50
/ $70.00
|
|
2nd
Quarter 2007
|
|
13,000
|
|
$8.00
/ $8.82
|
Full
year 2008
|
|
10,000
|
|
$47.50
/ $70.00
|
|
3rd
Quarter 2007
|
|
14,000
|
|
$8.00
/ $9.10
|
Full
year 2009
|
|
10,000
|
|
$47.50
/ $70.00
|
|
4th
Quarter 2007
|
|
15,000
|
|
$8.00
/ $11.39
|
Full
year 2010
|
|
5,000
|
|
$56.00
/ $78.95
|
|
1st
Quarter 2008
|
|
16,000
|
|
$8.00
/ $15.65
|
Full
year 2010
|
|
1,000
|
|
$60.00
/ $75.00
|
|
2nd
Quarter 2008
|
|
17,000
|
|
$7.50
/ $8.40
|
|
|
|
|
|
|
3rd
Quarter 2008
|
|
19,000
|
|
$7.50
/ $8.50
|
|
|
|
|
|
|
4th
Quarter 2008
|
|
21,000
|
|
$8.00
/ $9.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas Sales (NYMEX HH TO CIG)
|
|
|
|
|
Swaps
|
|
|
|
Price
|
|
Basis
Swaps
|
|
|
|
Price
|
2nd
through 4th
quarter 2007
|
|
1,000
|
|
$64.55
|
|
April
2007
|
|
13,000
|
|
$1.77
|
2nd
through 4th
quarter 2007
|
|
2,000
|
|
$60.00
|
|
May
2007
|
|
13,000
|
|
$1.70
|
|
|
|
|
|
|
June
2007
|
|
13,000
|
|
$1.69
|
|
|
|
|
|
|
July
2007
|
|
14,000
|
|
$1.56
|
|
|
|
|
|
|
August
2007
|
|
14,000
|
|
$1.51
|
|
|
|
|
|
|
September
2007
|
|
14,000
|
|
$1.58
|
|
|
|
|
|
|
October
2007
|
|
15,000
|
|
$1.63
|
|
|
|
|
|
|
November
& December 2007
|
|
15,000
|
|
$1.71
|
|
|
|
|
|
|
1st
Quarter 2008
|
|
16,000
|
|
$1.74
|
|
|
|
|
|
|
2nd
Quarter 2008
|
|
17,000
|
|
$1.43
|
|
|
|
|
|
|
3rd
Quarter 2008
|
|
19,000
|
|
$1.40
|
|
|
|
|
|
|
4th
Quarter 2008
|
|
21,000
|
|
$1.46
|
The
collar strike prices will allow us to protect a significant portion of our
future cash flow if 1) oil prices decline below $47.50 per barrel while
still participating in any oil price increase up to $78.95 per barrel on these
volumes and if 2) gas prices decline below approximately $8 per MMBtu.
These hedges improve our financial flexibility by locking in significant
revenues and cash flow upon a substantial decline in crude oil or natural gas
prices. It also allows us to develop our long-lived assets and pursue
exploitation opportunities with greater confidence in the projected economic
outcomes and allows us to borrow a higher amount under our senior unsecured
revolving credit facility.
While
we
have designated our hedges as cash flow hedges in accordance with SFAS
No. 133, Accounting
for Derivative Instruments and Hedging Activities,
it is
possible that a portion of the hedge related to the movement in the WTI to
California heavy crude oil price differential may be determined to be
ineffective. Likewise, we may have some ineffectiveness in our natural gas
hedges due to the movement of HH pricing as compared to actual sales points.
If
this occurs, the ineffective portion will directly impact net income rather
than
being reported as Other Comprehensive Income. While we believe that the
differential will narrow and move closer toward its historical level over time,
there are no assurances as to the movement in the differential. If the
differential were to change significantly, it is possible that our hedges,
when
marked-to-market, could have a material impact on earnings in any given quarter
and, thus, add increased volatility to our net income. The marked-to-market
values reflect the liquidation values of such hedges and not necessarily the
values of the hedges if they are held to maturity.
We
entered into derivative contracts (natural gas swaps and collar contracts)
on
March 1, 2006 that did not qualify for hedge accounting under SFAS 133 because
the price index for the location in the derivative instrument did not correlate
closely with the item being hedged. These contracts were recorded in the first
quarter of 2006 at their fair value on the balance sheet and we recognized
an
unrealized net loss of approximately $4.8 million on the income statement under
the caption “Commodity derivatives.” We entered into natural gas basis swaps on
the same volumes and maturity dates as the previous hedges in May 2006 which
allowed for these derivatives to be designated as cash flow hedges going
forward, causing an unrealized net gain of $5.6 million to be recognized in
the
second quarter of 2006. The difference of $.8 million was recorded in other
comprehensive income at the date the hedges were designated.
On
June
8, 2006 and July 10, 2006 we entered into five year interest rate swaps for
a
fixed rate of approximately 5.5% on $100 million of our outstanding borrowings
under our credit facility. These interest rate swaps have been designated as
cash flow hedges.
The
related cash flow impact of all of our derivative activities are reflected
as
cash flows from operating activities.
Irrespective
of the unrealized gains reflected in Other Comprehensive Income, the ultimate
impact to net income over the life of the hedges will reflect the actual
settlement values. All of these hedges have historically been deemed to be
cash
flow hedges with the marked-to-market valuations provided by external sources,
based on prices that are actually quoted.
Based
on
NYMEX futures prices as of March 31, 2007, (WTI $68.72; HH $8.50) 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, 2007
|
|
|
on
earnings
|
|
|
|
|
NYMEX
Futures
|
|
|
-20%
|
|
|
-10%
|
|
|
+
10%
|
|
|
+
20%
|
|
Average
WTI Futures Price (2007 - 2010)
|
|
$
|
68.72
|
|
$
|
54.98
|
|
$
|
61.85
|
|
$
|
75.59
|
|
$
|
82.46
|
|
Crude
Oil gain/(loss) (in millions)
|
|
|
(5.7
|
)
|
|
11.6
|
|
|
.1
|
|
|
(69.6
|
)
|
|
(147.6
|
)
|
Average
HH Futures Price (2007 - 2008)
|
|
|
8.50
|
|
|
6.80
|
|
|
7.65
|
|
|
9.35
|
|
|
10.2
|
|
Natural
Gas gain (in millions)
|
|
|
5.7
|
|
|
16.1
|
|
|
8.8
|
|
|
3.3
|
|
|
(2.2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
pre-tax future cash (payments) and receipts by year (in
millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
(WTI $68.27; HH $8.24)
|
|
$
|
.6
|
|
$
|
16.8
|
|
$
|
8.3
|
|
$
|
(16.6
|
)
|
$
|
(38.6
|
)
|
2008
(WTI $69.97; HH $8.70)
|
|
|
(.6
|
)
|
|
5.0
|
|
|
.6
|
|
|
(28.0
|
)
|
|
(57.7
|
)
|
2009
(WTI $69.05)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(21.7
|
)
|
|
(46.9
|
)
|
2010
(WTI $67.49)
|
|
|
-
|
|
|
5.9
|
|
|
-
|
|
|
-
|
|
|
(6.6
|
)
|
Total
|
|
$
|
-
|
|
$
|
27.7
|
|
$
|
8.9
|
|
$
|
(66.3
|
)
|
$
|
(149.8
|
)
|
Interest
Rates.
Our
exposure to changes in interest rates results primarily from long-term debt.
On
October 24, 2006, we issued $200 million of 8.25% senior subordinated notes
due
2016 in a public offering. Total
long-term debt outstanding including our short-term line of credit, at March
31,
2007 was $477 million. Interest on amounts borrowed under our revolving credit
facility is charged at LIBOR plus 1.0% to 1.75%, with the exception of the
$100
million of principal for which we have a hedge in place to fix the interest
rate
at approximately 5.5% plus the senior unsecured revolving credit facility’s
margin through June 30, 2011. Based on March 31, 2007 credit facility
borrowings, a 1% change in interest rates would have an annual $1.1 million
after tax impact on our financial statements.
Item
4. Controls and Procedures
As
of
March 31, 2007, we have carried out an evaluation under the supervision of,
and
with the participation of management, including our Chief Executive Officer
and
Chief Financial Officer, of the effectiveness of the design and operation of
our
disclosure controls and procedures pursuant to Rule 13a-15 under the Securities
and Exchange Act of 1934, as amended.
Based
on
their evaluation as of March 31, 2007, our Chief Executive Officer and Chief
Financial Officer have concluded that our disclosure controls and procedures
(as
defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act
of
1934) are effective to ensure that the information required to be disclosed
in
the reports that we file or submit under the Securities Exchange Act of 1934
is
recorded, processed, summarized and reported within the time periods specified
in SEC rules and forms.
There
was
no change in our internal control over financial reporting during the most
recently completed calendar quarter that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
Forward
Looking Statements
“Safe
harbor under the Private Securities Litigation Reform Act of 1995:” Any
statements in this Form 10-Q that are not historical facts are forward-looking
statements that involve risks and uncertainties. Words such as “will,” “intend,”
“continue,” “target(s),” “expect,” “achieve,” “future,” “may,” “could,”
“goal(s),”, “forecast,” “anticipate,” or other comparable words or phrases, or
the negative of those words, and other words of similar meaning indicate
forward-looking statements and important factors which could affect actual
results. Forward-looking statements are made based on management’s current
expectations and beliefs concerning future developments and their potential
effects upon Berry Petroleum Company. These items are discussed at length in
Part I, Item 1A on page 15 of our Form 10-K filed with the Securities and
Exchange Commission, under the heading “Risk Factors” and all material changes
are updated in Part II, Item 1A within this 10-Q.
PART
II. OTHER INFORMATION
Item
1. Legal Proceedings
None.
Item
1A. Risk Factors
We
may not be able to deliver minimum crude oil volumes required by our sales
contract.
Production volumes from our Uinta properties over the next six years are
uncertain and there is no assurance that we ill be able to consistently meet
the
minimum requirement. On February 27, 2007, we entered into a six year
multi-staged crude oil sales contract with a subsidiary of Holly for a portion
of our Uinta basin crude oil. Under the agreement, we will begin delivering
3,200 Bbl/D beginning July 1, 2007. Upon completion of their Woods Cross
refinery expansion in Salt Lake City, which is expected in late 2008, Holly
will
increase their total purchased volumes to 5,000
Bbl/D through June 30, 2013.
During
the term of the contract, the minimum number of delivered units (“base daily
volume”) is 3,200 Bbl/D increasing to 5,000 Bbl/D upon the certified completion
of the refinery upgrade.
Item
2. Unregistered Sales of Equity Securities and Use of
Proceeds
None.
Item
3. Defaults Upon Senior Securities
None.
Item
4. Submission of Matters to a Vote of Security Holders
None.
Item
5. Other Information
None.
Item
6. Exhibits
Exhibit
No.
Description
of Exhibit
10.1* Purchase
and sale agreement between the Company and Venoco, Inc. dated March 19,
2007.
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
Controller
(Principal
Accounting Officer)
Date: May
2, 2007